ITEM 1. BUSINESS.
GENERAL CSW, CPL, PSO, SWEPCO and WTU CSW, incorporated under the laws of Delaware in 1925, is a registered holding company under the Holding Company Act and owns all of the outstanding shares of common stock of the Operating Companies, CSWS, CSW Credit, CSWE, CSWI and CSW Communications. In addition, CSW owns 80% of the outstanding shares of common stock of CSW Leasing. The corporate predecessors of CSW and the Electric Operating Companies date back to the 19th century.
The Electric Operating Companies are public utility companies engaged in generating, purchasing, transmitting, distributing and selling electricity. The Electric Operating Companies were incorporated as follows:
State of Registrant Incorporation Year
CPL Texas 1945 PSO Oklahoma 1913 SWEPCO Delaware 1912 WTU Texas 1927
CPL and WTU operate in portions of south and central west Texas, respectively. PSO operates in portions of eastern and southwestern Oklahoma, and SWEPCO operates in portions of northeastern Texas, northwestern Louisiana and western Arkansas. Transok is an intrastate natural gas gathering, transmission, processing, storage and marketing company which transports for and sells natural gas to the Electric Operating Companies, principally PSO, as well as processing, transporting and selling natural gas to and for non- affiliates. CSWS performs, at cost, various accounting, engineering, tax, legal, financial, electronic data processing, centralized economic dispatching of electric power and other services for the CSW System. CSW Credit purchases accounts receivable of the Operating Companies and unaffiliated electric and gas utilities. CSWE and CSWI pursue cogeneration projects and other energy ventures within the United States and internationally. CSW Communications provides communication services to the Operating Companies and non-affiliates. CSW Leasing invests in leveraged leases.
CPL The economic base of the service territory served by CPL includes manufacturing, metal refining, petroleum products, agriculture and tourism. In 1994, industrial customers accounted for approximately 22% of CPL's total operating revenues. Contracts with substantially all industrial customers provide for both demand and energy charges. Demand charges continue under such contracts even during periods of reduced industrial activity, thus mitigating the effect of reduced activity on operating income.
PSO The economic base of the territory served by PSO includes mining, petroleum products, manufacturing and agriculture, which provides a balanced economy. The principal industries in the territory include natural gas and oil production, oil refining, steel processing, maintenance of aircraft, the manufacture of paper and timber products, glass, chemicals, cement and aircraft components.
1-8 SWEPCO The economic base of the service territory served by SWEPCO includes chemical processing, petroleum refining and oil and gas extraction. The primary metals and paper processing industries add balance to SWEPCO's industrial base.
WTU The economic base of the territory served by WTU is predominantly agricultural, producing cattle, sheep, goats, cotton, wool, mohair and feed crops. Significant gains have been made in economic diversification through value added processing of these products. The natural resources of the territory include oil, natural gas, sulfur, gypsum and ceramic clays. Important manufacturing and processing plants served by WTU produce cotton seed products, oil products, electronic equipment, precision and consumer metal products, meat products and gypsum products. The territory also includes several military installations and state correctional institutions.
Certain information relating to service provided by the Electric Operating Companies at December 31, 1994 follows:
SERVICE AREA ESTIMATED APPROXIMATE RETAIL RURAL ELECTRIC REGISTRANT POPULATION SQUARE MILES CUSTOMERS MUNICIPALITIES COOPERATIVES CPL 1,969,000 44,000 603,000 1 5 PSO 1,021,000 30,000 470,000 2 1 SWEPCO 887,000 25,000 403,000 2 8 WTU 410,000 53,000 185,000 2 12 CSW SYSTEM 4,287,000 152,000 1,661,000 7 26
The largest cities served by the Electric Operating Companies at retail are shown below:
CITY CPL PSO SWEPCO WTU
Corpus Christi, Texas 265,000 Laredo, Texas 133,000 McAllen, Texas 88,000
Tulsa, Oklahoma 557,000 Lawton, Oklahoma 89,000 Bartlesville, Oklahoma 44,000
Shreveport/Bossier City, Louisiana 278,000 Longview, Texas 79,000 Texarkana, Texas and Arkansas 63,000
Abilene, Texas 112,000 San Angelo, Texas 88,000
In 1994, the CSW System companies contributed the following percentages to aggregate operating revenues, operating income and net income for common stock. TOTAL CPL PSO SWEPCO WTU ELECTRIC TOK OTHER TOTAL OPERATING REVENUES 34% 20% 22% 9% 85% 14% 1% 100% OPERATING INCOME 48% 15% 22% 8% 93% 7% --% 100% NET INCOME FOR COMMON STOCK 49% 17% 26% 9% 101% 6% (7)% 100%
1-9 The relative contributions of the CSW System companies to the aggregate operating revenues, operating income and net income for common stock differ from year to year due to variations in weather, fuel costs reflected in charges to customers, timing and amount of rate changes and other factors, including changes in business conditions and the results of non-utility businesses. In 1994, approximately 62% of the CSW System's electric revenues were earned in Texas, 24% in Oklahoma, 8% in Louisiana and 6% in Arkansas.
Restructuring In November 1993, CSW undertook a restructuring designed to consolidate and restructure its operations in order to meet the challenges of the changing electric utility industry and to compete effectively in the years ahead. The restructuring is a response to two major factors, (i) a reduction in the rate of growth in the use of electricity and (ii) increasing competition among suppliers of electricity as a result of the Energy Policy Act. As a result of these changes, CSW believes that the electric utility industry faces changes in the way all electric utilities do business. The underlying goal of the restructuring is to enable the Electric Operating Companies to focus on and be accountable for serving the customer.
In general, the restructuring is designed to consolidate and centralize in CSWS certain functions which had been performed separately by CSW's Electric Operating Companies. In part, the restructuring shifts certain management functions relating to the operation of power plants, certain engineering activities and certain administrative and support functions from the Electric Operating Companies to CSWS, thereby reducing costs and freeing the Electric Operating Companies to focus on customer service, marketing and economic development. The restructuring is intended to standardize certain practices throughout the CSW System and to streamline management.
To delineate lines more clearly at the holding company level, the restructuring aligns CSW management into two principal units, CSW Electric, covering the CSW System's electric utility operations, and CSW Enterprises, covering CSW's other businesses, including Transok, CSWE, CSWI, CSW Communications, and the mergers and acquisitions and strategic planning departments. CSW Electric and CSW Enterprises are functional business designations only, not new subsidiaries.
CSW expects to realize a number of benefits from the restructuring. Beginning in 1994 and continuing into the future, increased efficiencies and synergies have been, and are expected to continue to be, realized with the elimination of previously duplicated functions. This leads to enhanced communication and efficiency, which should translate into a reduction in the rate of growth in O&M costs and thereby reduce the need for future rate increases.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Restructuring for further discussion about the restructuring.
New Business Opportunities CSW CSW continues to consider new business opportunities to expand and enhance its core electric utility business, and to expand its non- utility business. CSW's investment strategy with respect to non- utility businesses is to invest in businesses that are related to the expertise utilized in the core electric utility business. CSW's principal non-utility businesses are Transok and CSWE. During 1994, CSW formed a new corporation, CSWI, to pursue independent power initiatives abroad. In addition, CSW is considering investments in telecommunications, environmental and energy services. During 1994, CSW formed CSW Communications to provide a communications network for the CSW System as well as third-parties. CSW expects to make additional investments in non-regulated business during 1995. For additional information, see NON-UTILITY OPERATIONS below.
1-10 Proposed Acquisition of El Paso CSW In May 1993, CSW entered into a Merger Agreement pursuant to which El Paso would emerge from bankruptcy as a wholly-owned subsidiary of CSW. El Paso is an electric utility company headquartered in El Paso, Texas, engaged principally in the generation and distribution of electricity to approximately 262,000 retail customers in west Texas and southern New Mexico. El Paso also sells electricity under contract to wholesale customers in a number of locations including southern California and Mexico. El Paso had filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code on January 8, 1992.
On July 30, 1993, El Paso filed the Modified Plan and a related proposed form of Disclosure Statement providing for the acquisition of El Paso by CSW. On November 15, 1993, all voting classes of creditors and shareholders of El Paso voted to approve the Modified Plan. On December 8, 1993, the Bankruptcy Court confirmed the Modified Plan.
Under the Modified Plan, the total value of CSW's offer to acquire El Paso is approximately $2.2 billion. The Modified Plan generally provides for El Paso creditors and shareholders to receive shares of CSW Common, cash and/or securities of El Paso, or to have their claims cured and reinstated. The Modified Plan also provides for claims of secured creditors generally to be paid in full with debt securities of reorganized El Paso, and for unsecured creditors to receive a combination of debt securities of reorganized El Paso and CSW Common equal to 95.5 percent of their claims, and for small trade creditors to be paid in full with cash. The Modified Plan provides for El Paso's preferred shareholders to receive preferred shares of reorganized El Paso, or cash, and for options to purchase El Paso Common to be converted into options to purchase a proportionate number of shares of CSW Common. In addition, the Modified Plan provides for certain creditor classes of El Paso to accrue interest on their claims and to receive periodic interim distributions of such interest through the Effective Date or the withdrawal or revocation of the Modified Plan, subject to certain conditions and limitations set forth in the Modified Plan. To date, all such accrued interest payments to creditors have been made by El Paso on a timely basis. If, under certain circumstances, the Merger is not consummated, the Merger Agreement provides for CSW to pay El Paso for a portion of such interim interest payments paid or accrued prior to the termination of the Merger Agreement. The Merger Agreement also provides for CSW to pay for a portion of fees and expenses, including legal expenses of certain El Paso creditors under such circumstances. CSW's potential exposure as of December 31, 1994, is estimated to be approximately $17.5 million; however, the actual amount, if any, that CSW may be required to pay pursuant to these provisions depends on a number of contingencies and cannot presently be predicted.
The Merger is subject to numerous conditions set forth in the Merger Agreement, including but not limited to (i) the receipt of final orders with respect to all required regulatory approvals on terms that would not cause a regulatory material adverse effect as defined in the Merger Agreement, (ii) the receipt of all third party consents, (iii) the absence of a material adverse effect or facts or circumstances that could reasonably be expected to result in a material adverse effect on El Paso or the business prospects of El Paso, (iv) transfer to El Paso of good and marketable title to El Paso's share of Palo Verde, (v) performance by El Paso, CSW and CSW's acquisition subsidiary, CSW Sub, Inc., in all material respects of all covenants contained in the Merger Agreement and (vi) the occurrence of the Effective Date under the Modified Plan. Required regulatory approvals and filings in connection with the Merger include approvals of the FERC, the SEC, the Texas Commission, the New Mexico Commission, the NRC, and filings with the Department of Justice and the Federal Trade Commission under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.
See ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, NOTE 11 for CSW, Commitments and Contingent Liabilities, for a discussion of regulatory approval process relating to El Paso.
CSW continues to use its best efforts to consummate the Merger. At the same time, however, CSW continues to monitor contingencies which may preclude the consummation of the Merger, including without
1-11 limitation the potential loss of significant portions of El Paso's service area and significant El Paso customers, including Las Cruces and two military installations, Holloman Air Force Base and White Sands Missile Range, regulatory risks principally related to approval of the Merger and El Paso's request for a rate increase in Texas as well as the effects of the conditions imposed by federal or state regulatory agencies on the approval of the Merger and operating risks associated with the ownership of an interest in Palo Verde.
Based upon El Paso's written response to the concerns identified in a September 12 letter from CSW to El Paso and the failure of El Paso to resolve the contingencies set forth above, CSW cannot predict whether, or if so when, the Merger will be consummated. In the event that the proposed Merger is not consummated, there may be ensuing litigation between El Paso and CSW or among other parties to El Paso's bankruptcy proceedings and either or both of El Paso and CSW.
See CSW's ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Proposed Acquisition of El Paso, and CSW's ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - NOTE 11, Commitments and Contingent Liabilities, for additional information related to the proposed El Paso merger.
Competition CSW, CPL, PSO, SWEPCO and WTU Competitive forces at work in the electric utility industry are impacting the CSW System and electric utilities generally. Increased competition facing electric utilities is driven by complex economic, political and technological factors. These factors have resulted in legislative and regulatory initiatives that are likely to result in even greater competition at both the wholesale and retail levels in the future. As competition in the industry increases, the Electric Operating Companies will have the opportunity to seek out new customers and at the same time be at risk of losing customers to competitors. The Electric Operating Companies believe that their prices for electricity and the quality and reliability of their service currently place them in a position to compete effectively in the marketplace.
The Energy Policy Act, which was enacted in 1992, significantly alters the way in which electric utilities compete. The Energy Policy Act creates exemptions from regulation under the Holding Company Act for EWGs and permits utilities, including registered holding companies and non-utilities, to form EWGs. EWGs are a new category of non-utility wholesale power producers that are free from most federal and state regulation, including the principal restrictions of the Holding Company Act. These provisions enable broader participation in wholesale power markets by reducing regulatory hurdles to such participation. The Energy Policy Act also allows the FERC, on a case-by-case basis and with certain restrictions, to order wholesale transmission access and to order electric utilities to enlarge their transmission systems. A FERC order requiring a transmitting utility to provide wholesale transmission service must include provisions generally that permit (i) the utility to recover from the FERC applicant all of the costs incurred in connection with the transmission services and (ii) any enlargement of the transmission system and associated services. While CSW believes that the Energy Policy Act will continue to make the wholesale markets more competitive, CSW is unable to predict the extent to which the Energy Policy Act will impact CSW System operations.
Wholesale energy markets, including the market for wholesale electric power, have been extremely competitive since the enactment of the Energy Policy Act. The Electric Operating Companies compete in the wholesale energy markets with other public utilities, cogenerators, qualified facilities, exempt wholesale generators and others for sales of electric power.
CSW is unable to predict the ultimate outcome or impact of competitive forces on the electric utility industry or the CSW System. As the wholesale and retail electricity markets become more competitive, however, the principal factor determining success is likely to be price, and to a lesser extent, reliability, availability of capacity, and customer service.
1-12 CSW, CPL, SWEPCO and WTU PURA is the legal foundation for electric utility regulation in Texas. PURA will expire on September 1, 1995, in accordance with the sunset policy of the Texas Legislature, which applies to all state agencies, unless the Texas Legislature reenacts PURA in its current form or in modified form. Several proposals have been made to amend PURA which, among other things, provide for a market-driven integrated resource planning process, pricing flexibility for utilities faced with competitive challenges, incentive regulation and deregulation of the wholesale bulk power market in ERCOT. CSW is unable to predict the ultimate outcome of the 1995 session of the Texas Legislature and in particular whether amendments to PURA will be adopted.
In Texas, electric service areas are approved by the Texas Commission. A given tract in a utility's overall service area may be singly certificated to a utility, to one of several competing electric cooperatives or to one of the competing municipal electric systems or, it may be dually or triply certificated to these entities. These certificated areas have changed only slightly since the formation of the Texas Commission in 1976.
CSW and CPL CPL is generally singly certificated to serve inside most municipalities, and cooperatives are singly certificated to serve much of the rural areas. The suburban areas are mostly dually certificated. Since 1990, in dually certificated areas, CPL's rates have been higher than some competitors for some customers, especially small commercial and industrial customers. However, most business has been retained and some new business acquired, primarily because of service reliability and other customer service advantages. The availability of low cost natural gas and other alternative fuels, including those used in cogeneration facilities, have resulted in some losses of sales. Although there have been some losses, electricity is still the fuel of choice for most air conditioning installations. Renewable energy such as solar and wind is not now a feasible economic choice for customers of CPL in most instances. CPL believes that its rates, the quality and reliability of its service and the relatively inelastic demand for electricity for certain end uses should allow it to continue to compete in current retail markets.
See each of the registrants' ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Recent Developments and Trends for a discussion of competitive issues facing the utility industry.
REGULATION AND RATES
Regulation CSW, CPL, PSO, SWEPCO and WTU The CSW System is subject to the jurisdiction of the SEC under the Holding Company Act with respect to the issuance, acquisition and sale of securities, the acquisition and sale of certain assets or any interest in any business and accounting practices and other matters. The Holding Company Act generally limits the operations of a registered holding company to a single integrated public utility system, plus such additional businesses as are functionally related to such system.
The Electric Operating Companies have been classified as public utilities under the Federal Power Act and accordingly the FERC has jurisdiction in certain respects over their electric utility facilities and operations, wholesale rates, and in certain other matters.
The Electric Operating Companies are subject to the jurisdiction of various state commissions as to rates, accounting matters, standards of service and, in some cases, issuance of securities, certification of facilities and extensions and division of service territory.
1-13 CPL, SWEPCO and WTU The Texas Commission has jurisdiction over accounts, certification of utility service territory, sales of certain utility property, mergers and certain other matters. Neither the Texas Commission nor the governing bodies of incorporated municipalities have jurisdiction over the issuance of securities.
CPL Ownership of an interest in a nuclear generating unit exposes CPL and indirectly CSW to regulation not common to a fossil generating unit. Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, operation of nuclear plants is intensively regulated by the NRC, which has broad power to impose licensing and safety-related requirements. Along with other federal and state agencies, the NRC also has extensive regulations pertaining to the environmental aspects of nuclear reactors. The NRC has the authority to impose fines and/or shut down a unit until compliance is achieved, depending upon its assessment of the severity of the situation.
For a discussion of NRC regulation and other considerations arising from the ownership of nuclear assets, see NUCLEAR-STP, below.
Other See ENVIRONMENTAL MATTERS below, for information relating to environmental regulation.
Rates CSW, CPL, PSO, SWEPCO and WTU The retail rates of the Electric Operating Companies are subject to regulation by the state utility commissions in the states in which they operate.
CPL, SWEPCO and WTU The Texas Commission has original jurisdiction over retail rates in the unincorporated areas of Texas. The governing bodies of incorporated municipalities have original jurisdiction over rates within their incorporated limits. Municipalities may elect, and some have elected, to surrender this jurisdiction to the Texas Commission. The Texas Commission has appellate jurisdiction over rates set by incorporated municipalities.
PSO PSO is subject to the jurisdiction of the Oklahoma Commission with respect to retail prices, accounts, issuance of certain securities and certain other matters.
Pursuant to authority granted under RESCTA, the Oklahoma Commission established service territorial boundary maps in all unincorporated areas for all regulated retail electric suppliers serving Oklahoma. In accordance with RESCTA, a retail electric supplier may not extend retail electric service into the certified territory of another supplier, except to serve its own facilities or to serve a new customer with an initial full load of 1,000 KW or more. RESCTA provides that when any territory certified to a retail electric supplier or suppliers is annexed and becomes part of an incorporated city or town, the certification becomes null and void. However, once established in the annexed territory, a supplier may generally continue to serve within the annexed area.
SWEPCO In Arkansas, SWEPCO is subject to the jurisdiction of the Arkansas Commission as to rates, accounts, standards of service, sale or acquisition of certain utility property and issuance of securities by liens on property located in that state. In Louisiana, SWEPCO is subject to the jurisdiction of the Louisiana Commission as to rates, accounts and standards of service, but not as to the issuance of securities. In Oklahoma, SWEPCO is subject to the jurisdiction of the Oklahoma Commission only as to the issuance of evidences of indebtedness secured by liens on property located in that state.
1-14 SWEPCO has agreements, which have been approved by the FERC, with all of its wholesale customers under which rates are based upon an agreed cost of service formula. These rates are adjusted periodically to reflect the actual cost of providing service. All of SWEPCO's contracts with its wholesale customers contain FERC approved fuel-adjustment provisions that permit it to pass actual fuel costs through to its customers.
Fuel Recovery in Texas CSW, CPL, SWEPCO and WTU Electric utilities in Texas, including CPL, SWEPCO and WTU, are not allowed to make automatic adjustments to recover changes in fuel costs from retail customers. A utility is allowed to recover its known or reasonably predictable fuel costs through a fixed fuel factor. The Texas Commission established procedures that became effective on May 1, 1993, subject to certain transition rules, whereby each utility under its jurisdiction may petition to revise its fuel factor every six months according to a specified schedule. Fuel factors may also be revised in the case of emergencies or in a general rate proceeding. Under the revised procedures, a utility will remain subject to the prior rules until after its first fuel reconciliation, or in some instances, a general rate proceeding including a fuel reconciliation. To date, the new fuel rule has not significantly changed the manner in which the Electric Operating Companies recover retail fuel costs in Texas. Fuel factors are in the nature of temporary rates and the utility's collection of revenues by such factors is subject to adjustments at the time of a fuel reconciliation. Under the procedures, at the utility's semi- annual adjustment date, a utility will be required to petition the Texas Commission for a surcharge or to make a refund when it has materially under- or over-collected its fuel costs and projects that it will continue to materially under- or over-collect. Material under- or over-collections including interest are defined as four percent of the most recent Texas Commission adopted annual estimated fuel cost for the utility. A utility does not have to revise its fuel factor when requesting a surcharge or refund. An interim emergency fuel factor order must be issued by the Texas Commission within 30 days after such petition is filed by the utility. Final reconciliation of fuel costs is made through a reconciliation proceeding, which may contain a maximum of three years and a minimum of one year of reconcilable data, and must be filed with the Texas Commission no later than six months after the end of the period to be reconciled. In addition, a utility must include a reconciliation of fuel costs in any general rate proceeding regardless of the time since its last fuel reconciliation proceeding. Any fuel costs that are determined unreasonably incurred in a reconciliation proceeding are not recoverable from retail customers.
Fuel Recovery in Oklahoma CSW and PSO All KWH sales to PSO's retail customers for 1994 were made under rates which include a fuel cost adjustment clause. Oklahoma law requires that an examination of PSO's retail fuel cost adjustment clause be performed annually by the Oklahoma Commission. The fuel cost adjustment is computed for each month on the basis of the average cost of fuel consumed in the month. The amount of any difference in such cost over or under a base rate is applied on a KWH basis and reflected in adjustments to customers' bills during the second month subsequent to the month in which the difference occurred.
The FUSER program for qualified commercial and industrial customers and the CSF program, for qualified wholesale customers, were developed to allow program participants to purchase natural gas directly from suppliers, at negotiated prices, to be delivered to and burned in PSO's gas-fired power plants, resulting in reduced prices because of the low cost spot gas fuel provided. Under these programs participants could deliver sufficient quantities of natural gas to meet 70% of their generation requirements with the remaining 30% met with PSO-supplied coal. The FUSER and CSF programs resulted in lower electric costs to all classes of PSO's customers. The FUSER program was canceled effective October 1, 1993 because changing market and supply conditions eliminated the economic viability of the program. The CSF program remains in place although no customers participated in the program during 1994.
1-15 Fuel Recovery in Louisiana and Arkansas CSW and SWEPCO SWEPCO's retail rates currently in effect in Louisiana are adjusted based on SWEPCO's cost of fuel in accordance with a fuel cost adjustment which is applied to each billing month based on the second previous month's average cost of fuel. Provision for any over- or under-recovery of fuel costs is allowed under an automatic fuel clause.
Under SWEPCO's fuel adjustment rider currently in effect in Arkansas, the fuel cost adjustment is applied for each billing month on a basis which permits SWEPCO to recover the level of fuel cost experienced two months earlier.
Fuel Recovery from Wholesale Customers CSW, CPL, PSO, SWEPCO and WTU All of the Electric Operating Companies' contracts with their wholesale customers contain FERC approved fuel-adjustment provisions for recovery of fuel costs.
Other CSW, CPL, PSO, SWEPCO and WTU In the event that the Electric Operating Companies do not recover all of their fuel costs under the procedures described above, such event could have a material adverse effect on the companies' results of operations and financial condition.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for CSW, CPL, PSO, SWEPCO and WTU, and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - NOTE 10, for CSW, NOTE 9 for CPL, SWEPCO, and WTU and NOTE 8 for PSO, Litigation and Regulatory Proceedings, for further information with respect to rate proceedings including CPL's rate case and fuel reconciliation proceedings, PSO's rate proceedings, SWEPCO's fuel reconciliation proceedings, WTU's rate matters and fuel reconciliation and CPL's and WTU's deferred accounting matters.
NUCLEAR - STP CSW and CPL CPL owns 25.2% of STP, a two-unit nuclear power plant which is located near Bay City, Texas. In addition, HLP, the Project Manager, owns 30.8%; San Antonio owns 28.0%; and Austin owns 16.0%. STP Unit 1 was placed in service in August 1988 and STP Unit 2 was placed in service in June 1989.
STP Outage From February 1993 until May 1994 STP experienced an unscheduled outage which has resulted in significant rate and regulatory proceedings involving CPL.
Nuclear Decommissioning At the end of STP's service life, decommissioning is expected to be accomplished using the decontamination method, which is one of the techniques acceptable to the NRC. Using this method the decontamination activities occur as soon as possible after the end of plant operations. Contaminated equipment is cleaned or removed to a permanent disposal location and the site is generally returned to its pre-plant state.
CPL's decommissioning costs are accrued and funded to an external trust over the expected service life of the STP units. The existing NRC operating licenses will allow the operation of STP Unit 1 until 2027, and Unit 2 until 2028. The accrual is an annual level cost based on the estimated future cost to decommission STP, including escalations for expected inflation to the expected time of decommissioning and is net of expected earnings on the trust fund.
1-16 Deferred Accounting CPL was granted deferred accounting for STP Unit 1 and 2 costs by Texas Commission orders. These orders allowed CPL to defer post- in-service operating and maintenance costs, including taxes and depreciation, and carrying costs until these costs were reflected in retail rates. Deferred accounting had an immediate positive effect on net income in the years allowed, but cash earnings were not increased until rates went into effect reflecting STP in service.
See CSW's and CPL's ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - NOTE 10 for CSW and NOTE 9 for CPL, Litigation and Regulatory Proceedings, for further information with respect to CPL's rate case and fuel reconciliation proceedings, nuclear decommissioning and deferred accounting.
Other See ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - NOTE 11 for CSW and NOTE 10 for CPL, Commitments and Contingent Liabilities for further information related to nuclear insurance for STP.
1-17 UTILITY OPERATIONS
Facilities At December 31, 1994, the Electric Operating Companies owned electric generating plants, or portions thereof in the case of jointly-owned plants, with the following net dependable summer rating capabilities, substantially all of which were steam electric and which were located in the cities indicated:
Net Dependable Capability Plant Name and Location Principal Fuel (MW) (b) Source (a) CSW and CPL
Barney M. Davis, Corpus Christi, Gas 679 Texas Coleto Creek, Goliad, Texas Coal 604 Lon C. Hill, Corpus Christi, Texas Gas 549 Nueces Bay, Corpus Christi, Texas Gas 512 (c) Victoria, Victoria, Texas Gas 258 (c) La Palma, San Benito, Texas Gas 203 (c) E.S. Joslin, Point Comfort, Texas Gas 252 J. L. Bates, Mission, Texas Gas 182 Laredo, Laredo, Texas Gas 172 Eagle Pass, Eagle Pass, Texas Hydro 6 Oklaunion, Vernon, Texas (b) Coal 53 (d) STP, Bay City, Texas (b) Nuclear 630 (e)
CPL Total 4,100 (c)
CSW and PSO
Comanche, Lawton, Oklahoma Gas 258 Oil 4
Northeastern, Oologah, Oklahoma Gas 632 Coal 924 Oil 4
Riverside, Jenks, Oklahoma Gas 922 Oil 3
Southwestern, Washita, Oklahoma Gas 475 Oil 2
Tulsa, Tulsa, Oklahoma Gas 162 (c) Oil 8
Weleetka, Weleetka, Oklahoma Gas 151 Oil 4
Oklaunion, Vernon, Texas (b) Coal 106 (d)
PSO Total 3,655 (c)
1-18 (Continued) Net Dependable Capability Plant Name and Location Principal Fuel (MW) (b) Source (a)
CSW and SWEPCO
Arsenal Hill, Shreveport, Gas 113 Louisiana Lieberman, Mooringsport, Louisiana Gas 276 Knox Lee, Cherokee Lake, Texas Gas 501 Lone Star, Daingerfield, Texas Gas 50 Wilkes, Jefferson, Texas Gas 879 Welsh, Cason, Texas Coal 1,584 Flint Creek, Gentry, Arkansas (b) Coal 240 Henry W. Pirkey, Hallsville, Texas (b) Lignite 559 Dolet Hills, Mansfield, Texas (b) Lignite 262
SWEPCO Total 4,464
CSW and WTU
Abilene, Abilene, Texas Gas 18 Paint Creek, Haskell, Texas Gas 237 Lake Pauline, Quanah, Texas Gas 46 Oak Creek, Bronte, Texas Gas 87 San Angelo, San Angelo, Texas Gas 125 Rio Pecos, Girvin, Texas Gas 140 Fort Phantom, Abilene, Texas Gas (f) 362 Presidio, Presidio, Texas Oil 2 Ft. Stockton, Ft. Stockton, Texas Gas 5 Vernon, Vernon, Texas Oil 9 Oklaunion, Vernon, Texas (b) Coal 370 (d)
WTU Total 1,401
CSW 13,620 Plant in storage 557 CSW Total 14,177
Facilities Notes CSW, CPL, PSO, SWEPCO and WTU (a)Some plants have the capability of burning oil in combination with gas. Use of oil in facilities primarily designed to burn gas results in increased maintenance expense and a reduction of approximately from 5% to 15% in capability. PSO and WTU have 25 MW and 11 MW, respectively, of facilities primarily designed to burn oil. (b)Data reflects only CSW System's portion of plants which are jointly owned with non-affiliates. (c)Excludes units in storage - 34 MW at Nueces Bay, 228 MW at Victoria, 48 MW at La Palma for CPL and 247 MW at Tulsa for PSO. (d)CPL owns 7.81%, PSO owns 15.62% and WTU owns 54.69% of the 676 MW unit. The plant is operated by WTU. (e)CPL owns 25.2% of the two 1,250 MW units operated by HLP. (f)Although both Fort Phantom units burn primarily gas, Unit 1 is designed to burn fuel oil for extended periods of time before maintenance is required and Unit 2 is designed to burn fuel oil on a continuous basis.
1-19 Plants and Properties CSW, CPL, PSO, SWEPCO and WTU All of the generating plants described above are located on land owned by the Electric Operating Companies or jointly with other participants in the case of jointly owned plants. The Electric Operating Companies' electric transmission and distribution facilities are mostly located over or under highways, streets and other public places or property owned by others, for which permits, grants, easements or licenses (which the Electric Operating Companies believe to be satisfactory, but without examination of underlying land titles) have been obtained. The principal plants and properties of the Electric Operating Companies are subject to the liens of the first mortgage indentures under which the Electric Operating Companies' bonds are issued.
Peak Loads and System Capabilities of the Electric Operating Companies CSW, CPL, PSO, SWEPCO and WTU The following tables set forth for the last three years (i) the net system capability, including the net amounts of contracted purchases and contracted sales, at the time of peak demand, (ii) the maximum coincident system demand on a one-hour integrated basis, exclusive of sales to other electric utilities, and (iii) the respective amounts and percentages of peak demand generated by the Electric Operating Companies and net purchases and sales:
CSW 1994 1993 1992 NET SYSTEM CAPABILITY (MW) 13,549(3) 13,163(1)(2)(3) 13,230(1)(3) MAXIMUM COINCIDENT SYSTEM DEMAND (MW) 11,434 11,464 10,606 PERCENTAGE INCREASE (DECREASE) IN PEAK DEMAND OVER PRIOR PERIOD (0.3)% 8.1% 3.9% GENERATION AT TIME OF PEAK (MW) 11,353 10,624 10,426 PERCENT OF PEAK DEMAND GENERATED 99.3% 92.7% 98.3% NET PURCHASES (SALES) AT TIME OF PEAK (MW) 81 840 180 PERCENT OF NET PURCHASES (SALES) AT TIME OF PEAK .7% 7.3% 1.7% DATE OF MAXIMUM COINCIDENT SYSTEM DEMAND JUNE 27 AUGUST 18 AUGUST 10
(1) CSW's 1993 net system capability at the time of peak demand was less than 1992 net system capability due to unit outages. (2) Does not include 630 MW of STP capability that was not available at the 1993 peak due to the outage described in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - NOTE 10 for CSW, Litigation and Regulatory Proceedings and NUCLEAR - STP, in ITEM 1.
1-20 (3) Does not include 881 MW of system capability for 1994, 719 MW of system capability for 1993 and 1992.
CPL 1994 1993 1992 NET SYSTEM CAPABILITY (MW) 3,969(2) 3,850(1)(2) 4,165(2) MAXIMUM COINCIDENT SYSTEM DEMAND (MW) 3,732 3,518 3,347 PERCENTAGE INCREASE (DECREASE) IN PEAK DEMAND OVER PRIOR PERIOD 6.1% 5.1% 1.7% GENERATION AT TIME OF PEAK (MW) 3,074 2,943 3,003 PERCENT OF PEAK DEMAND GENERATED 82.4% 83.7% 89.7% NET PURCHASES (SALES) AT TIME OF PEAK (MW) 658 575 344 PERCENT OF NET PURCHASES (SALES) AT TIME OF PEAK 17.6% 16.3% 10.3% DATE OF MAXIMUM COINCIDENT SYSTEM DEMAND AUGUST 18 AUGUST 25 AUGUST 11
(1) Does not include 630 MW of STP capability that was not available at the 1993 peak due to the outage described in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - NOTE 9 for CPL, Litigation and Regulatory Proceedings and NUCLEAR - STP, in ITEM 1. (2) Does not include 310 MW of system capability in storage as described above under the heading UTILITY OPERATIONS - Facilities.
PSO 1994 1993 1992 NET SYSTEM CAPABILITY (MW) 3,664(1) 3,649(1) 3,721(1) MAXIMUM COINCIDENT SYSTEM DEMAND (MW) 3,167 3,147 3,010 PERCENTAGE INCREASE (DECREASE) IN PEAK DEMAND OVER PRIOR PERIOD 0.6% 4.6% (2.3)% GENERATION AT TIME OF PEAK (MW) 2,645 2,609 2,788 PERCENT OF PEAK DEMAND GENERATED 83.5% 82.9% 92.6% NET PURCHASES (SALES) AT TIME OF PEAK (MW) 522 538 222 PERCENT OF NET PURCHASES (SALES) AT TIME OF PEAK 16.5% 17.1% 7.4% DATE OF MAXIMUM COINCIDENT SYSTEM DEMAND JUNE 27 AUGUST 18 AUGUST 10
(1) Does not include 247 MW of system capability for 1994, and 409 MW of system capability for 1993 and 1992 in storage, as described above under the heading UTILITY OPERATIONS - Facilities.
SWEPCO 1994 1993 1992 NET SYSTEM CAPABILITY (MW) 4,464(1) 4,436 3,959 MAXIMUM COINCIDENT SYSTEM DEMAND (MW) 3,526 3,651 3,237 PERCENTAGE INCREASE (DECREASE) IN PEAK DEMAND OVER PRIOR PERIOD (3.4%) 12.8% 1.2% GENERATION AT TIME OF PEAK (MW) 3,987 3,559 3,292 PERCENT OF PEAK DEMAND GENERATED 113.1% 97.5% 101.7% NET PURCHASES (SALES) AT TIME OF PEAK (MW) (461) 92 (55) PERCENT OF NET PURCHASES (SALES) AT TIME OF PEAK (13.1%) 2.5% (1.7)% DATE OF MAXIMUM COINCIDENT SYSTEM DEMAND JUNE 27 AUGUST 18 AUGUST 10
(1) Does not include 324 MW of capability that was not available at the 1994 peak.
WTU 1994 1993 1992 NET SYSTEM CAPABILITY (MW) 1,459 1,384 1,404 MAXIMUM COINCIDENT SYSTEM DEMAND (MW) 1,262 1,201 1,118 PERCENTAGE INCREASE (DECREASE) IN PEAK DEMAND OVER PRIOR PERIOD 5.1% 7.4% 1.9% GENERATION AT TIME OF PEAK (MW) 1,401 1,223 1,151 PERCENT OF PEAK DEMAND GENERATED 111.0% 101.8% 102.9% NET PURCHASES (SALES) AT TIME OF PEAK (MW) (139) (22) (33) PERCENT OF NET PURCHASES (SALES) AT TIME OF PEAK (11.0%) (1.8%) (2.9)% DATE OF MAXIMUM COINCIDENT SYSTEM DEMAND JUNE 27 AUGUST 11 JULY 1
Power Purchases and Sales CSW, CPL, PSO, SWEPCO and WTU Various municipalities, electric cooperatives and public power authorities are served by the Electric Operating Companies. The Electric Operating Companies exchange power on an emergency or economy basis with various neighboring systems and engage in economy interchanges with each other. In addition, they contract with certain suppliers for the purchase or sale of power on a unit capacity basis.
CSW and SWEPCO As part of the negotiations to acquire BREMCO, SWEPCO entered into a long-term purchased power contract with Cajun, BREMCO's previous full-requirements wholesale supplier. The contract covered the purchase of energy at a fixed price for 1993 and 1994, and the purchase of capacity and energy in subsequent years. SWEPCO is a member of the Southwest Power Pool and the Western Systems Power Pool.
1-21 CSW, SWEPCO and WTU On April 4, 1994, the FERC issued an order pursuant to Section 211 of the Federal Power Act forcing a regional utility to transmit power to Tex-La on behalf of WTU. The order was one of the first issued by FERC under that provision, which was added by the Energy Policy Act to increase competition in wholesale power markets. On December 1, 1994, the FERC issued an order requiring a regional utility to provide this transmission service at a cost which was acceptable to Tex-La. The FERC also ordered the same regional utility to enter into an interconnection and remote control area load agreement with WTU within 30 days. This agreement was executed on January 3, 1995. On January 5, 1995, WTU began selling 92 MW of power and energy to Tex-La. Tex-La has a peak requirement of approximately 120 MWs. WTU will serve Tex-La until facilities are completed to connect Tex-La to SWEPCO, at which time SWEPCO will provide 85 MW and WTU will retain 35 MW of the Tex-La electric load.
CSW and PSO In 1989, PSO entered into certain long-term contracts with MCPC, a cogeneration development company located in northeastern Oklahoma. These contracts include (i) an Interconnection and Interchange Agreement providing terms and conditions under which MCPC can connect its electric generating facilities to PSO's transmission system and providing for future transmission by PSO of specified amounts of MCPC's power to an unaffiliated utility, (ii) a Stock/Asset Purchase Agreement which allows PSO under certain conditions to acquire the stock or assets of MCPC, and (iii) an Energy Conversion Agreement which requires PSO to deliver natural gas to MCPC for conversion to electrical energy to be delivered by MCPC to PSO. Under the Energy Conversion Agreement, MCPC is required to deliver at least 394,200 MWH per year of firm energy to PSO. PSO also has the right to dispatch up to 60 MWH per hour of quick-start capability.
PSO and MCPC filed a joint application with the Oklahoma Commission seeking approval of a September 1992 Letter Agreement between PSO and MCPC which provided for MCPC granting two-year extensions to the Interconnection and Interchange Agreement and the Energy Conversion Agreement in exchange for PSO not requiring payment by MCPC of certain debt and charges related to the Energy Conversion Agreement. The Oklahoma Commission Staff subsequently filed its own application seeking a review and evaluation of the current value to PSO of the Energy Conversion Agreement. MCPC also filed an application with the Oklahoma Commission requesting additional relief through the modification of the existing Energy Conversion Agreement. An emergency order was issued under MCPC's application which increased the payment made by PSO to MCPC for energy purchases and decreased the amount of firm energy MCPC is required to deliver to PSO. The emergency order is subject to a permanent ruling. The application filed by the Oklahoma Commission Staff was subsequently withdrawn. In December 1993, PSO filed an application with an ALJ to dismiss the case filed by MCPC based on a recent ruling from the Oklahoma Supreme Court. PSO's application to dismiss was denied by the ALJ and was appealed to the Oklahoma Commission. PSO's appeal was subsequently denied. The joint application and MCPC's application are expected to be heard by the second quarter of 1995.
In July 1993, PSO commenced a lawsuit in the District Court of Tulsa County, Oklahoma, seeking a declaratory judgment that PSO is entitled to terminate the Energy Conversion Agreement as of August 1, 1993, because of a default committed by MCPC. In November 1993, the Court granted judgment in favor of MCPC on grounds that the Oklahoma Commission had exclusive jurisdiction of the case and also that PSO had contractually waived its cause of action. PSO has appealed the Court's ruling to the Oklahoma Supreme Court, where the case is pending.
SWEPCO SWEPCO furnishes energy at wholesale to two municipalities and also supplies electric energy at wholesale to eight electric cooperatives operating in its territory through NTEC, Tex-La and Rayburn Country. SWEPCO also sells power to AECC and Cajun on an as- available basis.
1-22 WTU WTU provides wholesale electricity to four electric cooperatives and one municipality for all their electric energy requirements. WTU also provides wholesale power to eight other electric cooperatives, one other municipal customer and one investor owned electric utility company. WTU's contractual obligations with thirteen of its wholesale customers require a five year notice of termination, while one wholesale customer has a three year notice period and another has a fifteen year obligation.
System Interconnections CSW, CPL, PSO, SWEPCO and WTU The CSW System operates on an interstate basis to facilitate exchanges of power. PSO and WTU are interconnected through the 200 MW North HVdc Tie. In August 1992, SWEPCO and CPL entered into an agreement with HLP and TU to construct and operate an East Texas HVdc transmission interconnection which will facilitate exchanges of power for the CSW System. This interconnection will consist of a back-to- back HVdc converter station and 16 miles of 345 KV transmission line connecting transmission substations at SWEPCO's Welsh Power Plant and TU's Monticello Power Plant. In March 1993, an application for a Certificate of Convenience and Necessity for the transmission interconnection was approved by the Texas Commission. This 600 MW project is scheduled to be completed in mid-1995.
CPL and WTU are members of ERCOT, which also includes TU, HLP, Texas Municipal Power Agency, Texas Municipal Power Pool, Lower Colorado River Authority, the municipal systems of San Antonio, Austin and Brownsville, the South Texas and Medina Electric Cooperatives, and several other interconnected systems and cooperatives. The ERCOT members interchange power and energy on a firm, economy and emergency basis.
Seasonality CSW, CPL, PSO, SWEPCO and WTU Sales of electricity by the Electric Operating Companies tend to increase during warmer summer months and, to a lesser extent, cooler winter months, because of higher demand for power for cooling and heating purposes.
Franchises CSW, CPL, PSO, SWEPCO and WTU The Electric Operating Companies hold franchises to provide electric service in various municipalities in their service areas. These franchises have varying provisions and expiration dates including, in some cases, termination and buy-out provisions. CSW considers the Electric Operating Companies' franchises to be adequate for the conduct of their business.
Employees CSW, CPL, PSO, SWEPCO and WTU At December 31, 1994, CSW had 8,055 employees, as follows:
CSWS 1,070 CPL 1,933 PSO 1,552 SWEPCO 1,777 WTU 1,090 TRANSOK 554 CSWE 79 8,055
1-23 Approximately 600 employees at PSO and 700 employees at SWEPCO are covered under collective bargaining agreements with the IBEW. CSW implemented a restructuring plan in 1994 which resulted in a reduction of approximately 7% of the CSW System work force.
Executive Officers of the Registrant The following information is included in Part I pursuant to Regulation S-K, Item 401(b), Instruction 3.
CSW Age Name at March 16, Present Position
E. R. Brooks 57 Chairman, President and CEO, Director
Harry D. Mattison 58 Executive Vice President of CSW and President and CEO of Central and South West Electric, Director
T. V. Shockley, III 50 Executive Vice President of CSW and President and CEO of Central and South West Enterprises, Director
Ferd. C. Meyer, Jr. 55 Senior Vice President and General Counsel
Glenn D. Rosilier 47 Senior Vice President and CFO
Frederic L. Frawley 52 Corporate Secretary and Senior Attorney
Stephen J. McDonnell 44 Treasurer
Wendy G. Hargus 37 Controller
Each of the executive officers of CSW is elected to hold office until the first meeting of the CSW's Board of Directors after the next annual meeting of stockholders. CSW's next annual meeting of stockholders is scheduled to be held April 20, 1995. Each of the executive officers listed in the table above has been employed by CSW or an affiliate of CSW in an executive or managerial capacity for more than the last five years.
1-24 OPERATING STATISTICS CSW CENTRAL AND SOUTH WEST CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED ELECTRIC OPERATING STATISTICS
1994 1993 1992 KILOWATT-HOUR SALES (MILLIONS) RESIDENTIAL 16,368 15,903 14,593 COMMERCIAL 13,463 12,966 12,370 INDUSTRIAL 18,869 18,205 17,257 OTHER RETAIL 1,501 1,434 1,363 SALES TO RETAIL CUSTOMERS 50,201 48,508 45,583 SALES FOR RESALE 7,133 5,852 6,262 TOTAL 57,334 54,360 51,845
NUMBER OF ELECTRIC CUSTOMERS AT END OF PERIOD (THOUSANDS) RESIDENTIAL 1,417 1,396 1,366 COMMERCIAL 205 201 196 INDUSTRIAL 24 24 25 OTHER 15 12 12 TOTAL 1,661 1,633 1,599
RESIDENTIAL SALES AVERAGES KWH PER CUSTOMER 11,665 11,541 10,786 REVENUE PER CUSTOMER(a) $824 $842 $773 REVENUE PER KWH(a)(cents) 7.06 7.29 7.17
REVENUE PER KWH ON TOTAL SALES (a)(cents) 5.35 5.62 5.38
FUEL COST DATA (a) AVERAGE Btu PER NET KWH 10,344 10,391 10,482 COST PER MILLION Btu $1.82 $2.11 $1.92 COST PER KWH GENERATED (cents) 1.88 2.19 2.01 COST AS A PERCENTAGE OF REVENUE 37.9% 39.6% 37.1%
(a) These statistics reflect the outage at STP in 1993 and early 1994 as well as FUSER and CSF in 1993 and 1992.
1-25 CPL CENTRAL POWER AND LIGHT COMPANY OPERATING STATISTICS
1994 1993 1992 KILOWATT-HOUR SALES (MILLIONS) RESIDENTIAL 5,954 5,612 5,408 COMMERCIAL 4,523 4,278 4,181 INDUSTRIAL 6,910 6,406 5,800 OTHER RETAIL 457 435 414 SALES TO RETAIL CUSTOMERS 17,844 16,731 15,803 SALES FOR RESALE 1,286 913 1,370 TOTAL 19,130 17,644 17,173
NUMBER OF ELECTRIC CUSTOMERS AT END OF PERIOD RESIDENTIAL 516,355 504,893 493,772 COMMERCIAL 76,739 74,767 73,200 INDUSTRIAL (a) 5,864 6,156 6,307 OTHER 3,577 3,538 3,561 TOTAL 602,535 589,354 576,840
RESIDENTIAL SALES AVERAGES KWH PER CUSTOMER 11,729 11,298 11,133 REVENUE PER CUSTOMER (b) $935 $955 $890 REVENUE PER KWH (b) (cents) 7.97 8.45 7.99
REVENUE PER KWH ON TOTAL SALES (b)(cents) 6.37 6.93 6.48
FUEL COST DATA (b) AVERAGE Btu PER NET KWH 10,289 10,296 10,404 COST PER MILLION Btu $1.75 $2.17 $1.70 COST PER KWH GENERATED (cents) 1.80 2.23 1.77 COST AS A PERCENTAGE OF REVENUE 27.0% 28.6% 27.6%
(a) The customer decrease in 1994 was due primarily to the combining of multiple customer accounts into single accounts and a decline in customers due to economic and competitive conditions. The customer decrease in 1993 was largely due to the combining of multiple customer accounts into single accounts.
(b) These statistics reflect the outage at STP in 1993 and early 1994.
1-26 PSO PUBLIC SERVICE COMPANY OF OKLAHOMA OPERATING STATISTICS
1994 1993 1992 KILOWATT-HOUR SALES (MILLIONS) RESIDENTIAL 4,749 4,714 4,139 COMMERCIAL 4,434 4,352 4,092 INDUSTRIAL 4,360 4,445 4,420 OTHER RETAIL 89 87 85 SALES TO RETAIL CUSTOMERS 13,632 13,598 12,736 SALES FOR RESALE 1,509 563 665 TOTAL 15,141 14,161 13,401
NUMBER OF ELECTRIC CUSTOMERS AT END OF PERIOD RESIDENTIAL 409,675 406,847 404,170 COMMERCIAL 53,454 53,166 52,215 INDUSTRIAL 5,156 5,087 5,163 OTHER 1,287 1,008 1,009 TOTAL 469,572 466,108 462,557
RESIDENTIAL SALES AVERAGES KWH PER CUSTOMER 11,640 11,637 10,297 REVENUE PER CUSTOMER $726 $731 $642 REVENUE PER KWH (cents) 6.24 6.28 6.24
REVENUE PER KWH ON TOTAL SALES (a)(cents) 4.89 5.00 4.64
FUEL COST DATA (a) AVERAGE Btu PER NET KWH 10,231 10,220 10,305 COST PER MILLION Btu $1.96 $2.38 $2.34 COST PER KWH GENERATED(cents) 2.00 2.43 2.41 COST AS A PERCENTAGE OF REVENUE 39.5% 43.7% 40.3%
(a) These statistics reflect FUSER and CSF in 1993 and 1992. See REGULATION AND RATES and FUEL SUPPLY.
1-27 SWEPCO SOUTHWESTERN ELECTRIC POWER COMPANY OPERATING STATISTICS
1994 1993 1992 KILOWATT-HOUR SALES (MILLIONS) RESIDENTIAL 4,157 4,114 3,702 COMMERCIAL 3,378 3,249 3,039 INDUSTRIAL 6,357 6,122 5,862 OTHER RETAIL 400 390 373 SALES TO RETAIL CUSTOMERS 14,292 13,875 12,976 SALES FOR RESALE 5,189 4,508 3,854 TOTAL 19,481 18,383 16,830
NUMBER OF ELECTRIC CUSTOMERS AT END OF PERIOD RESIDENTIAL 346,227 340,379 325,301 COMMERCIAL 48,153 46,728 45,185 INDUSTRIAL 5,747 5,809 5,687 OTHER 2,609 2,605 2,636 TOTAL 402,736 395,521 378,809
RESIDENTIAL SALES AVERAGES KWH PER CUSTOMER 12,107 12,357 11,445 REVENUE PER CUSTOMER $776 $822 $770 REVENUE PER KWH (cents) 6.41 6.65 6.73
REVENUE PER KWH ON TOTAL SALES (cents) 4.24 4.60 4.62
FUEL COST DATA AVERAGE Btu PER NET KWH 10,489 10,582 10,717 COST PER MILLION Btu $1.75 $1.94 $1.93 COST PER KWH GENERATED (cents) 1.84 2.05 2.07 COST AS A PERCENTAGE OF REVENUE 40.6% 42.5% 43.0%
1-28 WTU WEST TEXAS UTILITIES COMPANY OPERATING STATISTICS
1994 1993 1992 KILOWATT-HOUR SALES (MILLIONS) RESIDENTIAL 1,508 1,464 1,344 COMMERCIAL 1,128 1,087 1,057 INDUSTRIAL 1,241 1,231 1,175 OTHER RETAIL 556 522 491 SALES TO RETAIL CUSTOMERS 4,433 4,304 4,067 SALES FOR RESALE 2,051 2,288 1,951 TOTAL 6,484 6,592 6,018
NUMBER OF ELECTRIC CUSTOMERS AT END OF PERIOD RESIDENTIAL 144,966 143,453 142,270 COMMERCIAL 26,618 26,001 25,714 INDUSTRIAL 7,392 7,453 7,384 OTHER 5,533 5,361 5,254 TOTAL 184,509 182,268 180,622
RESIDENTIAL SALES AVERAGES KWH PER CUSTOMER 10,449 10,241 9,485 REVENUE PER CUSTOMER $822 $811 $752 REVENUE PER KWH (cents) 7.86 7.92 7.93
REVENUE PER KWH ON TOTAL SALES (cents) 5.29 5.24 5.24
FUEL COST DATA AVERAGE Btu PER NET KWH 10,424 10,491 10,445 COST PER MILLION Btu $1.88 $1.91 $1.82 COST PER KWH GENERATED (cents) 1.96 2.00 1.91 COST AS A PERCENTAGE OF REVENUE 38.3% 39.1% 38.0%
1-29 CONSTRUCTION AND FINANCING
CSW, CPL, PSO, SWEPCO and WTU The CSW System maintains a continuing construction program, the nature and extent of which is based upon current and estimated future loads of the system. The estimated total capital expenditures, including AFUDC, of the CSW System for the years 1995-1997 are as follows:
CSW CONSTRUCTION 1995 1996 1997 TOTAL (MILLIONS) GENERATION $ 47 $ 37 $ 43 $ 127 TRANSMISSION 35 85 59 179 DISTRIBUTION 146 138 131 415 FUEL 4 21 12 37 TRANSOK 63 40 40 143 OTHER 90 61 73 224 TOTAL $385 $382 $358 $1,125
CPL CONSTRUCTION 1995 1996 1997 TOTAL (MILLIONS) GENERATION $ 23 $ 20 $ 19 $ 62 TRANSMISSION 16 28 11 55 DISTRIBUTION 45 59 57 161 FUEL 4 21 12 37 OTHER 23 8 11 42 TOTAL $111 $136 $110 $357
PSO CONSTRUCTION 1995 1996 1997 TOTAL (MILLIONS) GENERATION $11 $ 9 $18 $ 38 TRANSMISSION 6 20 13 39 DISTRIBUTION 35 29 29 93 OTHER 19 13 11 43 TOTAL $71 $71 $71 $213
SWEPCO CONSTRUCTION 1995 1996 1997 TOTAL (MILLIONS) GENERATION $12 $ 7 $ 5 $ 24 TRANSMISSION 10 34 28 72 DISTRIBUTION 48 31 27 106 OTHER 26 22 34 82 TOTAL $96 $94 $94 $284
WTU CONSTRUCTION 1995 1996 1997 TOTAL (MILLIONS) GENERATION $ 1 $ 1 $ 1 $ 3 TRANSMISSION 3 3 7 13 DISTRIBUTION 18 19 18 55 OTHER 15 13 11 39 TOTAL $37 $36 $37 $110
Information in the foregoing tables is subject to change as a result of change in the underlying assumptions from numerous factors, including the rate of load growth, escalation of construction costs, changes in lead times in manufacturing, inflation, the availability and pricing of alternatives to construction, and nuclear, environmental and other regulation, delays from regulatory hearings, the adequacy of rate relief and the
1-30 availability of necessary external capital. Changes in these and other factors could cause each respective Electric Operating Company to defer or accelerate construction or to sell or buy more power, which would affect its cash position, revenues and income to an extent that cannot now be reliably predicted.
In addition, increasing competition in the electric utility industry may have an impact on the construction programs of the Electric Operating Companies. Traditionally, the Electric Operating Companies have made investments in their utility systems, filed a rate case to seek recovery of their operating and other costs and sought to earn a rate of return on their assets in rate base. Competition in the utility industry, however, is likely to lead to an increasing need to stabilize or reduce rates. At the same time, the retail regulatory environment is beginning to shift from traditional rate base regulation to incentive and performance-based regulation which are intended to encourage efficiency and increased productivity in lieu of traditional ratemaking formulas. In light of the trend toward competition and away from traditional ratemaking, the CSW System will periodically reevaluate its capital spending policies and generally seek to fund only those construction projects and investments that management believes will offer satisfactory returns in the current environment. Consistent with this strategy, the CSW System is likely to continue to make additional investments in non-utility businesses.
CSW continues to study ways to reduce or meet future increases in customer demand, including demand-side management programs, new and efficient electric technologies, construction of various types and sizes of generation facilities, increasing the availability or efficiency of existing generation facilities, reducing transmission and distribution losses, and where feasible and economical, acquisition of reliable long-term capacity from other suppliers. The public utility commissions in some of the jurisdictions served by the Electric Operating Companies may consider on a case-by-case basis mechanisms to permit recovery of costs of demand-side management programs and a return on the related investment from ratepayers.
The CSW System facilities plan indicates that CSW will not require substantial additions of generating capacity until the year 2001 or beyond.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources, Capital Expenditures for each registrant, for additional information with respect to construction expenditures and financing.
FUEL SUPPLY
General The CSW System's present net dependable summer rating power generation capabilities and the type of fuel used are set forth in UTILITY OPERATIONS - Facilities above. Additional fuel supply data is set forth in the tables presented below.
CSW SYSTEM AGGREGATE CAPABILITY GENERATION 1994 (MW) 1994 (KWH) NATURAL GAS 8,246 NATURAL GAS 47% COAL AND LIGNITE 4,702 COAL AND LIGNITE 47% NUCLEAR 630 NUCLEAR 6% HYDRO and OIL 42 TOTAL 100% SUB TOTAL 13,620 PLANT IN STORAGE 557 TOTAL 14,177
1-31 CPL AGGREGATE CAPABILITY GENERATION 1994 (MW) 1994 (KWH) NATURAL GAS 2,807 NATURAL GAS 56% COAL 657 COAL 24% NUCLEAR 630 NUCLEAR 20% HYDRO 6 TOTAL 100% SUB TOTAL 4,100 PLANT IN STORAGE 310 TOTAL 4,410
PSO AGGREGATE CAPABILITY GENERATION 1994 (MW) 1994 (KWH) NATURAL GAS 2,600 NATURAL GAS 58% COAL 1,030 COAL 42% OIL 25 TOTAL 100% SUB TOTAL 3,655 PLANT IN STORAGE 247 TOTAL 3,902
SWEPCO AGGREGATE CAPABILITY GENERATION 1994 (MW) 1994 (KWH) NATURAL GAS 1,819 NATURAL GAS 23% COAL 1,824 COAL 48% LIGNITE 821 LIGNITE 29% TOTAL 4,464 TOTAL 100%
WTU AGGREGATE CAPABILITY GENERATION 1994 (MW) 1994 (KWH) NATURAL GAS 1,020 NATURAL GAS 59% COAL 370 COAL 41% OIL 11 TOTAL 100% TOTAL 1,401
Natural Gas CSW The Electric Operating Companies purchase their gas from a number of suppliers operating in and around their service territories. In 1994, approximately 48% of the Electric Operating Companies' total gas purchases were made under long-term contracts and approximately 52% came from short-term contracts and spot purchases.
CSW and CPL CPL's eight gas-fired electric generating plants are supplied by a portfolio of long-term and short-term natural gas purchase agreements through multiple natural gas pipeline systems. Approximately 68% of CPL's total gas requirements in 1994 were purchased under long-term arrangements representing both purchase obligations and discretionary purchases, with the balance of CPL's requirements being acquired under short-term arrangements from the spot market. CPL's principal gas supplies for 1994 were provided
1-32 under agreements with Corpus Christi Gas Marketing, L.P., Onyx Pipeline Company, Enron Corporation, or their affiliates. They supplied approximately 25%, 13% and 10%, respectively, of CPL's total natural gas purchases.
CSW and PSO PSO engages in a program to maintain adequate gas supplies necessary for operation. Natural gas for generation is provided by purchases under a number of long-term and spot market contracts. Approximately 60% of PSO's natural gas requirements were provided for under firm contracts. Transok acts as an administrator with respect to purchases of natural gas supplies. Gas is transported by Transok to PSO facilities under agreements pursuant to which PSO pays Transok for actual costs incurred in providing the services as determined on an allocated cost of service basis, including a rate of return on equity applicable between affiliates as specified by the Oklahoma Commission in PSO's most recent Oklahoma price review. See ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - CSW's NOTE 10 and PSO's NOTE 8, Litigation and Regulatory Proceedings, for further information with respect to such agreements between PSO and Transok.
CSW and SWEPCO In 1994, SWEPCO purchased approximately 99.5% of its gas requirements pursuant to spot purchase contracts with no take-or-pay obligations. The remaining 0.5% of SWEPCO's 1994 gas requirements came from a long-term take-or-pay contract which was terminated in January 1994. SWEPCO plans to continue to enter into short-term contracts with various suppliers to provide gas for peaking purposes.
CSW and WTU WTU has gas purchase contracts with several suppliers. The largest long-term contract, which is with Lone Star, provided approximately 13% of WTU's total gas requirements in 1994. Lone Star is obligated, except during curtailments, to have gas available for 125% of the estimated annual fuel requirements of each plant served, provided the total of all plants does not exceed 110% of the estimated annual fuel requirement. The Lone Star contract, which expires in 2000, allows WTU considerable flexibility to purchase gas from other sources. Utilizing this flexibility in 1994, WTU purchased approximately 68% of its gas requirements on the spot market from many different suppliers. The remaining 19% of WTU's 1994 gas requirements came from supplemental firm contracts with several suppliers. The contracts with suppliers vary in their terms, but generally provide for periodic or other price adjustments.
Coal and Lignite CSW The Electric Operating Companies purchase coal from a number of suppliers. In 1994, approximately 82% of the Electric Operating Companies' total coal purchases were supplied under long-term contract with the balance procured on the spot market. The coal for the CSW System plants comes primarily from Wyoming or Colorado mines which are located between 1,000 and 1,500 rail miles from the generating plants.
Proposed Railroad Merger CSW, CPL, PSO, SWEPCO and WTU In October 1994, Burlington Northern Railroad Company and the Atchison, Topeka and Santa Fe Railway Company filed an application with the Interstate Commerce Commission to merge the two railroads. These railroads currently compete for a portion of the coal transportation traffic to CPL's Coleto Creek power plant. Because of the potential elimination of such competition and other factors, CPL and the other Electric Operating Companies may be adversely affected by this merger, if approved, unless conditions mitigating the impact are included in the merger.
Oklaunion CSW, CPL, PSO and WTU The jointly-owned Oklaunion plant is supplied coal under a coal supply contract with Exxon expiring in 2006. This contract was amended and restated in December 1993 as part of a settlement of litigation with Exxon. In November 1994, Caballo Coal Company, an
1-33 affiliate of Peabody Holding Company, Inc., purchased Exxon's Rawhide and Caballo mines in Wyoming, the sources of the Exxon coal. The long-term coal supply contract has subsequently been transferred from Exxon to Caballo Coal Company.
Approximately 67% of the total 1994 Oklaunion coal requirements for CPL, 70% for PSO and 71% for WTU were supplied under the Exxon contract with the balance procured on the spot market.
CPL's share of the year-end 1994 coal inventory at Oklaunion was approximately 46,000 tons, representing approximately 60 days supply. PSO's share was approximately 95,000 tons, representing approximately 21 days supply. WTU's share was approximately 250,000 tons, representing approximately 55 days supply.
All coal used at the Oklaunion plant is transported approximately 1,100 miles to the plant by the Burlington Northern Railroad Company pursuant to a coal transportation contract which is projected to expire during late 1995. The coal is transported under this contract in Burlington Northern supplied rail cars. WTU has instituted a rate proceeding at the Interstate Commerce Commission requesting a reasonable rate for rail transportation of coal to the Oklaunion plant, pursuant to filed tariffs, after expiration of the Burlington Northern contract.
Coleto Creek CSW and CPL At Coleto Creek, the long-term agreement expiring in 1999 with Colowyo Coal Company provided approximately 60% of the coal requirements of the plant for 1994. CPL's purchase obligation set forth in the Colowyo agreement for 1995 and through 1999 is for approximately 25% of Coleto Creek's requirements. The coal is mined in northwestern Colorado and is transported approximately 1,400 miles under long-term rail agreements with Denver & Rio Grande Western Railroad Company, the Burlington Northern Railroad Company and the Southern Pacific Transportation Company. Southern Pacific Transportation Company is currently the only rail carrier with access to the Coleto Creek plant. The balance of the Coleto Creek requirements are currently being procured on the spot market. CPL owns sufficient railcars for operation of three unit trains and has negotiated contracts with the rail carriers involved which have been filed with the Interstate Commerce Commission. CPL's rail transportation contracts for Coleto Creek expire December 31, 1995. CPL has instituted a proceeding at the Interstate Commerce Commission requesting a reasonable rate for the 16 mile movement from Coleto Creek to Victoria, Texas, a destination served by Missouri Pacific Railroad Company. After 1995, CPL intends to utilize coal from the Powder River Basin of Wyoming for a portion of the Coleto Creek plant requirements and intends to negotiate rail transportation agreements for such coal. At year-end 1994, CPL had approximately 290,000 tons of coal in inventory at Coleto Creek, representing approximately 43 days supply.
Northeastern Station CSW and PSO PSO has a contract with Kerr-McGee Coal Corporation, which substantially covers the coal supply for PSO's Northeastern Station coal units through at least 2007, with approximately 11% of the 1994 requirements purchased on the spot market. Coal delivery is by unit trains from mines located in the Gillette, Wyoming vicinity, a distance of about 1,100 rail miles from Northeastern Station. PSO owns sufficient rail cars and spares for operation of six unit trains. Coal is transported to Northeastern Station pursuant to long- term contracts with Burlington Northern and the Missouri Pacific Railroad Company which have been filed with the Interstate Commerce Commission. In some years, including 1994, a portion of the coal has been transported pursuant to short-term contracts with other carriers. Burlington Northern has disputed PSO's right to transport coal at Northeastern Station utilizing other carriers. This dispute is the subject of pending litigation. See ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - CSW NOTE 10 and PSO NOTE 8,
1-34 Litigation and Regulatory Proceedings for further discussion. At year-end 1994, PSO had approximately 529,000 tons of coal in inventory at Northeastern representing approximately 50 days supply.
CSW and SWEPCO The long-term supply for SWEPCO's Welsh plant and its 50 percent- owned Flint Creek plant is provided under a contract with AMAX. The current contract, executed in December 1993, replaced a prior contract between the parties as part of a settlement of litigation concerning the prior contract. The settlement has resulted in lower fuel costs to the Welsh and Flint Creek plants. Approximately 99% of the total 1994 Flint Creek coal requirements and 94% of the total 1994 Welsh coal requirements were supplied under the AMAX contract with the balance purchased on the spot market.
Coal under the AMAX contract is mined near Gillette, Wyoming, a distance of about 1,500 and 1,100 miles, respectively, from the Welsh and Flint Creek plants. This coal is delivered to the plants under rail transportation contracts with Burlington Northern and the Kansas City Southern Railroad Company. These contracts will expire between 2001 and 2007. SWEPCO owns or leases under long-term leases sufficient cars and spares for operation of twelve unit trains. SWEPCO has supplemented its railcar fleet from time to time with short-term leases. At December 31, 1994, SWEPCO had coal inventories of 1,199,000 tons at Welsh representing 53 days supply and 552,000 tons at Flint Creek representing 80 days supply.
SWEPCO has acquired lignite leases covering an aggregate of about 27,000 acres near the Henry W. Pirkey power plant. Sabine Mining Company is the contract miner of these reserves. At December 31, 1994, 322,000 tons of lignite were in inventory at the plant representing 33 days supply.
Another 25,000 acres are jointly leased in equal portions by SWEPCO and CLECO in the Dolet Hills area of Louisiana near Dolet Hills Power Plant. The Dolet Hills Mining Venture is the contract miner for these reserves. At December 31, 1994, SWEPCO had 240,000 tons of lignite in inventory at the plant representing 58 days supply.
In the opinion of the management of SWEPCO, the acreage under lease in these areas contains sufficient reserves to cover the anticipated lignite requirements for the estimated useful lives of the lignite-fired plants.
Nuclear Fuel CSW and CPL The supply of fuel for STP involves a complex process. This process includes the acquisition of uranium concentrate, the conversion of uranium concentrate to uranium hexafluoride, the enrichment of uranium hexafluoride in the isotope U235 and the fabrication of the enriched uranium into fuel rods and incorporation of fuel rods into fuel assemblies. The fuel assemblies are the final product loaded into the reactor core. The time associated with this process requires fuel decisions be made years in advance of the actual need to refuel the reactor. Fuel requirements for STP are being handled by the STP Management Committee, comprised of representatives of all participants in STP.
Outages are necessary approximately every 18 months for refueling. Because STP's fuel costs are significantly lower than any of the other CPL units, CPL's average fuel costs are expected to be higher whenever an STP unit is down for refueling or maintenance.
CPL and the other STP participants have entered into contracts with suppliers for uranium concentrate and conversion service sufficient for the operation of both STP units through 1996. Also, flexible uranium concentrate and uranium hexafluoride contracts are in place to provide approximately 50% of the uranium needed for STP from 1997 to 2000. Enrichment contracts have been secured for a 30- year period from the initial operation of each unit with the exception of the period from October of 2000 to September of 2002. The STP participants canceled the enrichment requirements for such period under a ten year no cost termination provision in the
1-35 enrichment contract. The STP participants believe that other, lower- cost options will be available in the future. Also, fuel fabrication services have been contracted for operation through 2005 for Unit 1 and 2006 for Unit 2. Although CPL and the other STP owners cannot predict the availability of uranium and related services, CPL and the other STP owners do not currently expect to have difficulty obtaining uranium and related services required for the remaining years of STP operations.
The Energy Policy Act has provisions for the recovery of a portion of the costs associated with the decommissioning and decontamination of the gaseous diffusion plants used in the enrichment process. These costs are being recovered on the basis of enrichment services purchased by utilities from the DOE prior to October of 1992. The total annual assessment for all domestic utilities is limited to $150 million per federal fiscal year and assessable for 15 years. The STP assessment will be approximately $2.0 million each year with CPL's share being 25.2% of the annual STP assessment.
The Nuclear Waste Policy Act of 1982, as amended, requires the DOE to develop a permanent high level waste disposal facility for the storage of spent nuclear fuel by 1998. The DOE recently announced that the permanent facility will not be available until 2010. The DOE will be taking possession of all spent fuel generated at STP as a result of a contract CPL and other STP participants have entered into with the DOE. STP has on-site storage facilities with the capability to store all the spent nuclear fuel generated by the STP units over their life. Therefore, the DOE delay in providing the disposal facility will not impact the operation of the STP units. Under provisions of the Nuclear Waste Policy Act of 1992, a one-mill per KWH assessment on electricity generated and sold from nuclear reactors funds the DOE waste disposal program.
Risks of substantial liability could arise from the operation of STP and from the use, handling, disposal and possible radioactive emissions associated with nuclear fuel. While CPL carries insurance, the availability, amount and coverage thereof is limited and may become more limited in the future. The available insurance may not cover all types or amounts of loss or expense which may be experienced in connection with the ownership of STP.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Fuel and Purchased Power for information relating to coal contract litigation.
Governmental Regulation CSW, CPL, PSO, SWEPCO and WTU The price and availability of each of the foregoing fuel types are significantly affected by governmental regulation. Any inability in the future to obtain adequate fuel supplies or adoption of additional regulatory measures restricting the use of such fuels for the generation of electricity might affect the CSW System's ability to economically meet the needs of its customers and could require the Electric Operating Companies to supplement or replace, prior to normal retirement, existing generating capability with units using other fuels. This would be impossible to accomplish quickly, would require substantial additional expenditures for construction and could have a significant adverse effect on CSW's and/or the Electric Operating Companies' financial condition and results of operations.
1-36 Fuel Costs and Consumption CSW, CPL, PSO, SWEPCO and WTU Additional fuel cost data for the CSW System appears under OPERATING STATISTICS. Average fuel costs and consumption by fuel type follow:
AVERAGE COST PER FUEL TYPE MILLION Btu
CSW NATURAL GAS $2.18 COAL 1.71 LIGNITE 1.34 NUCLEAR .51 FUEL TYPE 1994 CONSUMPTION (MILLIONS) All fuel types 1.82 Tons Mcfs Btus
CPL CPL NATURAL GAS $2.10 NATURAL GAS 105 107 COAL 1.98 COAL 2 43 NUCLEAR .51 NUCLEAR * * 37 All fuel types 1.75
PSO PSO NATURAL GAS $2.38 NATURAL GAS 83 86 COAL 1.38 COAL 4 63 All fuel types 1.96
SWEPCO SWEPCO NATURAL GAS $1.98 NATURAL GAS 43 43 COAL 1.90 COAL and 10 148 LIGNITE LIGNITE 1.34 All fuel types 1.75
WTU WTU NATURAL GAS $2.18 NATURAL GAS 42 42 COAL 1.42 COAL 2 28 All fuel types 1.88 * Not measured
1-37 Future Cost of Fuel CSW, CPL, PSO, SWEPCO and WTU The registrants are unable to predict the future cost of fuel.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Rates and Regulatory Matters for each registrant, for further information concerning fuel costs.
ENVIRONMENTAL MATTERS CSW, CPL, PSO, SWEPCO and WTU The Operating Companies and CSWE are subject to regulation with respect to air and water quality and solid waste standards and other environmental matters by various federal, state and local authorities. These authorities have continuing jurisdiction in most cases to require modifications in the Electric Operating Companies' facilities and operations. Changes in environmental statutes or regulations could require substantial additional expenditures to modify the Electric Operating Companies' facilities and operations and could have a significant adverse effect on CSW's and each Electric Operating Companies' results of operations and financial condition. Violations of environmental statutes or regulations can result in fines and other costs.
Air Quality Clean Air Act Amendments CSW, CPL, PSO, SWEPCO and WTU Air quality standards and emission limitations are subject to the jurisdiction of state regulatory authorities in each state in which the CSW System operates, with oversight by the EPA. In accordance with regulations of these state authorities, permits are required for all generating units on which construction is commenced or which are substantially modified after the effective date of the applicable regulations. None of the Electric Operating Companies has received notice from any federal or state government agency alleging that it currently is subject to an enforcement action for a material violation of existing federal or state air quality and emission regulations.
In November 1990, the United States Congress passed the Clean Air Act which places restrictions on the emission of sulfur dioxide from gas-, coal- and lignite-fired generating plants. Beginning in the year 2000, the Electric Operating Companies will be required to hold allowances in order to emit sulfur dioxide. The EPA issues allowances to owners of existing generating units based on historical operating conditions. Based on the CSW System facilities plan, CSW believes that the Electric Operating Companies' allowances are adequate to meet their needs at least through 2008. Public and private markets are developing for trading of excess allowances. CSW and the Electric Operating Companies presently have no intention of engaging in trading of allowances, but may seek to do so in the future if market conditions warrant and appropriate regulatory approvals are obtained.
The Clean Air Act also establishes a federal operating source permit program to be administered by the states.
The Clean Air Act also directs the EPA to issue regulations governing nitrogen oxide emissions and require government studies to determine what controls, if any, should be imposed on utilities to control air toxics emissions. The impact that the nitrogen oxide emission regulations, and the air toxics study, will have on CSW and the Electric Operating Companies cannot be determined at this time.
As a result of requirements imposed by the Clean Air Act, CSW expects to spend $4 million for annual testing of, software modifications to, and maintenance of continuous emission monitoring equipment from 1995 through 1997.
1-38 CSW, CPL and WTU Air quality standards and emission limitations are subject to the jurisdiction of the TNRCC, with oversight by the EPA. In accordance with regulations of the TNRCC, permits are required for all generating units on which construction is commenced or which are substantially modified after the effective date of the applicable regulations. CPL and WTU have not received notice from any federal or state government agency alleging that they currently are subject to an enforcement action for a material violation of existing federal or state air quality and emission regulations.
CSW and CPL As a result of requirements imposed by the Clean Air Act, CPL expects to spend approximately $1.3 million for annual testing of, software modifications to, and maintenance of continuous emission monitoring equipment from 1995 through 1997.
CSW and PSO Air quality standards and emission limitations are subject to the jurisdiction of ODEQ, with oversight by the EPA. In accordance with regulations of ODEQ, permits are required for all generating units on which construction is commenced or which are substantially modified after the effective date of the applicable regulations. PSO has not received notice from any federal or state government agency alleging that it currently is subject to an enforcement action for a material violation of existing federal or state air quality and emission regulations. As a result of requirements imposed by the Clean Air Act, PSO expects to spend approximately $1.3 million for annual testing of, software modifications to, and maintenance of continuous emission monitoring equipment from 1995 through 1997.
CSW and SWEPCO Air quality standards and emission limitations are subject to the jurisdiction of the ADPCE in Arkansas, the LDEQ in Louisiana and the TNRCC in Texas, with oversight by the EPA. In accordance with regulations of the ADPCE, LDEQ and TNRCC, permits are required for all generating units on which construction is commenced or which are substantially modified after the effective date of the applicable regulations. SWEPCO has not received notice from any federal or state government agency alleging that it currently is subject to an enforcement action for a material violation of existing federal or state air quality and emission regulations. As a result of requirements imposed by the Clean Air Act, SWEPCO expects to spend approximately $1.3 million for annual testing of, software modifications to, and maintenance of continuous emission monitoring equipment from 1995 through 1997.
CSW and WTU As a result of requirements imposed by the Clean Air Act, WTU expects to spend approximately $0.5 million for annual testing of, software modifications to, and maintenance of continuous emission monitoring equipment from 1995 through 1997.
Transok Transok's compressor engines and other emission sources are subject to air permit requirements, including monitoring. As a result of new requirements under the Clean Air Act, seven of Transok's facilities will be subject to additional permit requirements. The Clean Air Act may also impose additional enhanced monitoring requirements on these seven facilities.
Water Quality CSW, CPL, PSO, SWEPCO and WTU The ADPCE, LDEQ, ODEQ, TNRCC and the EPA have jurisdiction over all wastewater discharges into state waters. These authorities have jurisdiction for establishing water quality standards and issuing waste control permits covering discharges which might affect the quality of state waters. The EPA has jurisdiction over point source discharges through the National Pollutant Discharge Elimination System provisions of the Clean Water Act. CPL, PSO, SWEPCO and WTU
1-39 have not received notice from any federal or state government agency alleging that they currently are subject to an enforcement action for a material violation of existing federal or state wastewater discharge regulations.
RCRA, CERCLA and Related Matters RCRA CSW, CPL, PSO, SWEPCO and WTU The RCRA and the Arkansas, Louisiana, Oklahoma and Texas solid waste rules provide for comprehensive control of all solid wastes from generation to final disposal. The appropriate state regulatory authorities in the states in which the CSW System operates have received authorization from the EPA to administer the RCRA solid waste control program for their respective states. None of the Electric Operating Companies has received notice from any federal or state government agency alleging that it currently is subject to an enforcement action for a material violation of existing federal or state solid waste regulations.
CERCLA The operations of the CSW System, like those of other utility systems, generally involve the use and disposal of substances subject to environmental laws. CERCLA, the federal "Superfund" law, addresses the cleanup of sites contaminated by hazardous substances. Superfund requires that PRPs fund remedial actions regardless of fault or the legality of past disposal activities. PRPs include owners and operators of contaminated sites and transporters and/or generators of hazardous substances. Many states have similar laws. Theoretically, any one PRP can be held responsible for the entire cost of a cleanup. Typically, however, cleanup costs are allocated among PRPs.
CSW's subsidiaries incur significant costs for the handling, transportation, storage and disposal of hazardous and non-hazardous waste materials. Unit costs for waste classified as hazardous exceed by a substantial margin unit costs for waste classified as non- hazardous waste.
The Electric Operating Companies are also subject to various pending claims alleging that they are PRPs under federal or state remedial laws for investigating and cleaning up contaminated property. CSW anticipates that resolution of these claims, individually or in the aggregate, will not have a material adverse effect on CSW's consolidated results of operations or financial condition. Although the reasons for this expectation differ from site to site, factors that are the basis for the expectation for specific sites are the volume and/or type of waste allegedly contributed by the Electric Operating Company, the estimated amount of costs allocated to the Electric Operating Company and the participation of other parties.
The Electric Operating Companies, like other electric utilities, produce combustion and other generation by-products, such as sludge, slag, low-level radioactive waste and spent nuclear fuel. The Electric Operating Companies own distribution poles treated with creosote or related substances. The EPA currently exempts coal combustion by-products from regulation as hazardous wastes. Distribution poles treated with creosote or similar substances are not expected to exhibit characteristics that would cause them to be hazardous waste. In connection with their operations, the Electric Operating Companies also have used asbestos, PCBs and materials classified as hazardous waste. If additional by-products or other materials generated or used by companies in the CSW System were reclassified as hazardous wastes, or other new laws or regulations concerning hazardous wastes or other materials were put in effect, CSW System disposal and remedial costs could increase materially. The EPA is expected to issue new regulations stating whether certain other materials will be classified as hazardous.
Sol Lynn Superfund Site CSW and CPL The Sol Lynn salvage yard was declared a Superfund site by the EPA after it was found to contain a number of contaminants including PCBs. Gulf States Utilities Company remediated the site for approximately $2 million and is trying to recover a portion of the remediation costs from alleged PRPs, including CPL. CPL believes its
1-40 liability, if any, would be as a deminimus party. CPL is negotiating with Gulf States Utilities Company to determine its share, if any, of remediation costs.
Industrial Road and Industrial Metals Site CSW and CPL Several lawsuits relating to the industrial road and industrial metal site in Corpus Christi, Texas, naming CPL as a defendant, are currently pending in federal and state court in Texas. Plaintiffs' claims allege property damage and clean-up activities. Although management cannot predict the outcome of these proceedings, based on the defenses that management believes are available to CPL, management believes that the ultimate resolution of these matters will not have a material adverse effect on CSW's or CPL's results of operations or financial condition.
Rose Chemical Site CSW, SWEPCO and WTU SWEPCO and WTU were named PRPs in the clean-up of the Rose Chemical Site, in Missouri, along with 750 other companies. A clean- up fund was established through payments by PRPs who agreed to a "buyout settlement," and the site remediation was undertaken. The site buildings were removed and the grounds cleaned to standards acceptable to the EPA. The site remediation is virtually completed and the court settlement became final in July 1994. Remaining costs are expected to be covered by the previously collected funds and there should be no further costs to either SWEPCO or WTU.
B&B Salvage Site CSW, SWEPCO and WTU SWEPCO and WTU are also PRPs at the B&B Salvage site. This site, located in Missouri, received scrap metal from the Rose Chemical firm. The B&B site has been remediated and SWEPCO's and WTU's share of cleaning up this site and the Rose Chemical site is not expected to have a material effect on CSW's, SWEPCO's, or WTU's results of operations or financial condition.
PCB Litigation CSW and PSO PSO has been named a defendant in complaints filed in federal and state courts of Oklahoma in 1984, 1985, 1986 and 1993. The complaints allege, among other things, that some of the plaintiffs and the property of other plaintiffs were contaminated with PCBs and other toxic by-products following certain incidents, including transformer malfunctions in April 1982, December 1983 and May 1984. To date, complaints representing approximately $736 million of claims, including compensatory and punitive damages, have been dismissed, certain of which resulted from settlements among the parties. The settlements did not have a significant effect on CSW's or PSO's consolidated results of operations. Remaining complaints currently total approximately $395 million, of which approximately one-third is for punitive damages. Discovery with regard to the remaining complaints continues. Management cannot predict the outcome of these proceedings. However, management believes that PSO has defenses to these complaints and intends to pursue them vigorously. Moreover, management has reason to believe that PSO's insurance may cover some of the claims. Management also believes that the ultimate resolution of the remaining complaints will not have a material adverse effect on CSW's or PSO's consolidated results of operations or financial condition.
PCB Storage Facilities CSW and PSO PSO investigated and identified PCB contamination at one of its PCB storage facilities in Sand Springs, Oklahoma. PSO made proper notification to the EPA of the contamination that was caused by spills prior to PCB spill regulations. PSO negotiated a remediation plan with the EPA. Remediation began in November 1994, and the remediation costs are estimated to be $210,000. As part of the remediation plan, the EPA has requested PSO to sample the land surrounding the PCB storage building site. The land will include an active PSO substation and an industrial area that is privately owned.
1-41 The extent of any PCB contamination has not been determined on either site.
Compass Industries Superfund Site CSW and PSO PSO has received notice from the EPA that it is a PRP under CERCLA and may be required to share in the reimbursement of cleanup costs for the Compass Industries Superfund site which has been remediated. PSO has been named defendant in a lawsuit filed in Federal District Court in Tulsa, Oklahoma on August 29, 1994, for reimbursement of the clean-up cost. The range of PSO's degree of responsibility, if any, as a de minimis party appears to be insignificant. Management believes the ultimate resolution of this matter will not have a material adverse effect on CSW's or PSO's consolidated results of operations or financial condition.
Alleged Coal Gasification Plant in McAlester, Oklahoma CSW and PSO PSO has been notified by the EPA of the identification of a coal gasification plant in McAlester, Oklahoma. The EPA requested PSO to identify all properties owned by PSO currently and formerly in McAlester that had been once owned by a non-affiliated company. PSO has submitted the information to the EPA. PSO has not been able to locate the alleged coal gasification plant in McAlester, Oklahoma. PSO has had no further contact with the EPA regarding this issue.
USI Site CSW and PSO PSO has been identified by the ADPCE as a PRP at the USI site in Pine Bluff, Arkansas. In 1993, the ADPCE asked PSO to provide it with information regarding any transactions between USI and PSO since 1973 that involved hazardous substances. Based on a review of its records, PSO's environmentally related transactions with USI were limited to USI's provision of oil recycling services to PSO at property owned by PSO, not at the USI site. As a result, PSO's degree of responsibility, if any, at the USI site appears to be insignificant.
Coal Mine Reclamation CSW and PSO In August 1994, PSO received approval from the Wyoming Department of Environmental Quality to begin reclamation of a coal mine in Sheridan, Wyoming owned by Ash Creek Mining Company, a wholly-owned subsidiary of PSO. Ash Creek Mining Company recorded a $3 million liability in 1993 for the estimated reclamation costs. Actual reclamation work is expected to commence in mid-1995, with completion estimated in late 1996. Surveillance monitoring will continue for ten years after final reclamation. Management believes the ultimate resolution of this matter will not have a material adverse effect on CSW's or PSO's consolidated results of operations or financial condition.
Suspected MGP Site in Marshall, Texas CSW and SWEPCO SWEPCO owns a suspected former MGP site in Marshall, Texas. SWEPCO has notified the TNRCC that evidence of contamination has been found at the site. As a result of sampling conducted at the end of 1993 and early 1994, SWEPCO is evaluating the extent, if any, to which contamination has impacted soil, groundwater and other conditions in the area. A final range of clean-up costs has not yet been determined, but, based on a preliminary estimate, SWEPCO accrued approximately $2 million as a liability for this site on SWEPCO's books as of December 31, 1993. As more information is obtained about the site, and SWEPCO discusses the site with the TNRCC, the preliminary estimate may change.
1-42 Suspected MGP Sites in Texarkana, Texas and Arkansas and Shreveport, Louisiana CSW and SWEPCO SWEPCO also owns a suspected former MGP site in Texarkana, Texas and Arkansas. The EPA ordered an initial investigation of this site, as well as one in Shreveport, Louisiana, which is no longer owned by SWEPCO. The contractor who performed the investigations of these two sites recommended to the EPA that no further action be taken at this time.
Suspected Biloxi, Mississippi MGP Site CSW and SWEPCO SWEPCO has been notified by Mississippi Power Company that it may be a PRP at the former Biloxi MGP site formerly owned and operated by a predecessor of SWEPCO. SWEPCO is working with Mississippi Power Company to investigate the extent of contamination at this site. The MDEQ approved a site investigation work plan and, in January 1995, SWEPCO and Mississippi Power Company initiated sampling pursuant to that work plan. On an interim basis, SWEPCO and Mississippi Power Company are each paying fifty percent of the cost of implementing the site investigation work plan. That interim allocation is subject to a final allocation in the future. SWEPCO and Mississippi Power Company are investigating whether there are other PRPs at the Biloxi site. Until the extent of the contamination at the Biloxi site is identified, it is unknown what, if any, additional investigation or cleanup may be required.
Rochester Substation Spill CSW and WTU In September 1992, an automobile crashed into WTU's 69 KV substation in Rochester, Texas, and struck a transformer containing 1,500 gallons of 25 parts per million PCB oil. WTU responded and coordinated clean-up efforts with state officials. In December 1993, WTU contracted with a consulting firm to ascertain the impact of the spill on the area ground water and to help determine WTU's effectiveness in the clean-up effort. Total costs to date have been approximately $400,000. The consultant's report, dated June 30, 1994, concluded that the spill cleanup procedures were effective. WTU forwarded the report to the TNRCC on July 12, 1994 and requested the agency close the matter. Management believes the ultimate resolution of this matter will not have a material adverse effect on CSW's or WTU's results of operations or financial condition.
Toxic Substances Control Act of 1976 Under the TSCA, the storage, use and disposal, among other things, of PCBs are regulated. Violations of TSCA may lead to fines and penalties.
CSW and CPL In an inspection of CPL by the EPA, the EPA alleged that CPL failed to comply with the regulations governing the reporting of leakage of PCBs from some of its equipment. The EPA has proposed a penalty of $91,000. CPL met with EPA to negotiate a reduction in the penalty. EPA responded on January 26, 1995, with a proposed potential reduced penalty of $61,000 dependent upon filing additional information with the EPA. Based on the information currently available to it, CPL expects the final penalty to be between $61,000 and $91,000.
See ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, CSW NOTE 10, and PSO NOTE 8, Litigation and Regulatory Proceedings for additional information related to PCB matters.
Other Environmental CSW, CPL, PSO, SWEPCO and WTU From time to time the registrants are made aware of various other environmental issues or are named as a party to various other legal claims, actions, complaints or other proceedings related to environmental matters. Management does not expect disposition of any such pending environmental proceedings to have a material adverse effect on the registrants' results of operations or financial condition.
1-43 See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Environmental for each registrant and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, CSW NOTE 10 and PSO NOTE 8, Litigation and Regulatory Proceedings and CSW NOTE 11 and SWEPCO NOTE 10, Commitments and Contingent Liabilities, for additional information relating to environmental matters.
NON-UTILITY OPERATIONS
CSW Transok Transok, a wholly-owned subsidiary of CSW, is an intrastate natural gas gathering, transmission, processing, storage and marketing company. Transok, incorporated in Oklahoma in 1955, was acquired by CSW in 1961 to supply natural gas to PSO's power stations. While Transok's operations in recent years have included the marketing and transportation of natural gas for third parties, it functions within the CSW System to insure reliable and economic natural gas service to the Electric Operating Companies and CSWE.
Transok provides a variety of services to the Electric Operating Companies including acquiring and transporting natural gas to meet certain of their power generation needs. Transok's largest customer is PSO. The contract between PSO and Transok provides (i) for the transportation of PSO's natural gas fuel supply through Transok's pipeline system and (ii) for Transok to act as PSO's supply administrator in acquiring natural gas and negotiating and administering supply contracts. PSO pays Transok for such services at cost, including a return on equity applicable between affiliates as specified by the Oklahoma Commission in PSO's most recent Oklahoma price review. The contract expires on January 1, 2003, but continues for consecutive five-year terms thereafter unless either party provides two years' notice of cancellation. Under the contract, PSO has the right to require delivery of up to 546 MMcf/d of natural gas through Transok's pipeline system. Effective January 1, 1998, PSO may adjust the transportation capacity available to it under the contract based on its projected needs. Delivery of natural gas to PSO is currently about 86 Bcf annually and is projected to increase.
Natural Gas Transportation and Gathering Transok provides natural gas suppliers and shippers with pipeline interconnects for access to the Electric Operating Companies and other end-users throughout the United States. At December 31, 1994, Transok's pipeline system consisted of approximately 6,436 miles of gathering and transmission lines which include approximately 3,973 miles of gathering lines in Oklahoma, 275 miles in Louisiana and 214 miles in Texas. At December 31, 1994, Transok's pipeline system consisted of 200 compressors with 197,900 horsepower to provide both gathering and transmission line compression. Transok's pipeline facilities are located in the major natural gas producing basins in Oklahoma, including the Anadarko and Arkoma basins, and in the major Louisiana corridor of pipelines transporting natural gas to the northeast from the Gulf Coast and mid-continent areas. The Transok pipeline system has numerous connections with major interstate pipelines through which natural gas is transported to markets throughout the United States. In 1994, the Transok pipeline system had a throughput of 506 Bcf of natural gas.
Transok transported more than 86 Bcf per year of natural gas for PSO in 1994 and provided administrative services to PSO to manage its supply of natural gas. Transok has been active in the development of joint gas purchase arrangements with its other CSW affiliates as well. Transok's access to diverse natural gas markets combined with the natural gas fuel needs of the Electric Operating Companies allow for natural gas opportunities at high load factors, reducing the cost of natural gas fuel for the CSW System.
Natural Gas Processing Transok also owns and operates seven natural gas processing plants for the production of natural gas liquids. The plants have an aggregate capacity of 444 MMcf/d. Transok is the second largest natural gas processor in Oklahoma and ranks seventeenth among natural gas liquids producers nationwide. In 1994, Transok's plants produced
1-44 399.4 million gallons of natural gas liquids while revenue from the sale of natural gas liquids amounted to $117.9 million for the year.
Natural Gas Storage Transok owns and operates an underground natural gas storage reservoir in Oklahoma with an aggregate storage capacity of approximately 26 billion cubic feet. Operational capabilities include injection into storage at a rate of 130 MMcf/d and a withdrawal rate in excess of 210 MMcf/d. In 1993, the FERC issued an order approving market-based storage rates for Transok which enables it to sell storage services to interstate customers at negotiated fees based on the value of those services in the competitive marketplace. Transok's gas storage field also allows Transok to offer peaking services, accommodate volume swings on its pipeline system, and support the natural gas requirements of the Electric Operating Companies.
Natural Gas Marketing In 1989, Transok began its natural gas marketing program and sold 26 Bcf to a variety of customers including local distribution companies, end-users and other pipelines. In 1994, Transok's natural gas sales volumes were 257 Bcf with a sales revenue of $484.4 million. Off-system sales of natural gas accounted for 111 Bcf of the natural gas sold in 1994. This increase was the result of pipeline acquisition and construction activities combined with new customers. Transok aggregates natural gas supply into various supply pools, which provide Transok with reliable sources of natural gas at market sensitive prices, allowing Transok to meet its natural gas supply needs. Transok offers various gas supply services to provide customers with peaking and balancing alternatives utilizing Transok's gas supplies and facilities. In addition, Transok's customers have the opportunity to select various pricing options including (i) fixed or variable pricing, (ii) indexed to New York Mercantile Exchange pricing or (iii) cash quotes.
Transok uses natural gas futures, options and basis swaps to reduce its price risk exposure arising from the purchase and sale of natural gas. Natural gas futures and options allow Transok to protect against volatility in supply costs in fulfilling fixed price contracts, meeting storage requirements and purchasing natural gas for processing operations. Natural gas futures and options are also used to protect Transok against price exposure on sales of natural gas from storage or anticipated purchases. In addition, basis swaps protect Transok against volatility in price differentials between geographic areas in matching anticipated supply and demand prices.
In 1992, FERC Order 636 went into effect to deregulate the natural gas industry and increase competition. Although Transok operations were not directly affected by Order 636, Transok has developed tariff services, flexible contracts and other natural gas related services in order to meet customers' needs and take advantage of new competitive opportunities.
Services for CSWE Transok provides natural gas fuel planning and management services for CSWE. Transok assists CSWE in developing natural gas supply and transportation strategies for CSWE's non-utility electric generation projects.
Regulation As a subsidiary of CSW, Transok is subject to regulation under the Holding Company Act. The Holding Company Act, among other things, requires that regulated companies seek prior SEC approval before entering into certain transactions including the acquisition or issuance of securities.
Transok's pipelines are considered gathering systems or intrastate pipelines. Transok is therefore exempt from regulation by the FERC under the Natural Gas Act. However, Transok's rates for transporting gas in interstate commerce are subject to FERC regulation under the Natural Gas Policy Act of 1978. The FERC approves Transok's rates for transportation of gas in interstate commerce through Transok's pipelines in Oklahoma and Louisiana and the Texas Railroad Commission approves the rates for such transportation through pipelines in Texas. The FERC also has given
1-45 Transok approval to charge market-based rates for storage of gas using Transok's storage facility in Oklahoma.
While Transok is not subject to direct regulation by any state public utility commission, the costs that result from transactions with its affiliated Electric Operating Companies are subject to review by the state commissions regulating such affiliates and are required to meet standards for affiliate transactions to be recoverable by the Electric Operating Companies.
CSWE CSWE, a wholly-owned subsidiary of CSW, is authorized to develop various independent power and cogeneration facilities and to own and operate such non-utility projects, subject to further regulatory approvals. CSWE has an approximate 50% interest in the Brush, Fort Lupton and Mulberry facilities which achieved commercial operation in 1994.
Brush The 68 MW Brush project, located in Brush, Colorado, achieved commercial operation in January 1994 and provides steam and hot water to a 15-acre greenhouse and sells electricity to Public Service Company of Colorado.
Ft. Lupton The Ft. Lupton project provides steam and hot water to a 20- acre greenhouse and also sells electricity to Public Service Company of Colorado. Phase I of the Ft. Lupton project, representing 122 MWs, achieved commercial operation in June 1994. Phase II of the project commenced operations in July 1994 bringing total on-line capacity of the project to 272 MWs.
Mulberry The Mulberry facility, a 117 MW gas-fired cogeneration plant in Polk County, Florida achieved commercial operation in August 1994 and provides steam to a combined distilled water and ethanol facility and sells electricity to Florida Power Corporation and Tampa Electric Company. CSWS is providing engineering, procurement and construction management services for the Mulberry project. CSWE's operating and maintenance division is operating the plant. On December 30, 1994, the borrower, Polk Power Partners, L.P., in which CSWE is indirectly a 50% owner, was notified it was in technical default under the third party financing documents since substantial completion of the Mulberry Ethanol facility had not occurred by December 30, 1994. CSWE is in the process of discussing with the lender means of curing the technical default. Management does not expect this matter to have a material effect on CSW's consolidated results of operations or financial condition.
Orange Cogen The Orange Cogen facility, in which CSWE holds a 50% interest, is expected to commence operation in June 1995. The 103 MW, gas fired plant in Florida will provide thermal energy to an orange juice processor and will sell electricity to Florida Power Corporation and Tampa Electric Company. CSWE's O&M division plans to operate the plant.
Oildale In November 1994, CSWE transferred its 50% interest in the 40 MW Oildale cogeneration facility to two non-affiliated third parties, Oildale Holdings, Inc. and Oildale Holdings II, Inc. The Oildale project, which was financed with third-party non-recourse project financing, had been in default of certain provisions of its loan agreement since December 1993. Under the terms of the project transfer, CSWE contributed $3 million in equity in exchange for the return of a letter of credit in the same amount in favor of a third party lender. CSWE had reserved for this liability in 1993, therefore, this transaction has no material adverse effect on CSW's or CSWE's 1994 results of operations or financial condition.
1-46 Other Projects In addition to these projects, CSWE has another 19 projects totaling more than 5,000 MW in various stages of development, mostly in affiliation with other developers. CSWE can provide no assurances that these projects, which are subject to further negotiations and regulatory approvals, will be commenced or completed and, if they are completed, that they will provide the anticipated return on investment.
As a result of its participation in these projects, CSWE has contractual commitments to provide certain services and support. These commitments provide that the potential maximum liability of CSWE will be limited to $215 million. Management believes the likelihood of material liabilities under these contracts is remote.
The following table sets forth information about cogeneration projects CSWE is currently operating or bringing to operation:
CSWI In November 1994, CSWI, a wholly-owned subsidiary of CSW, was formed to engage in international activities including developing, acquiring, financing and owning the securities of exempt wholesale generators and foreign utility companies.
In 1994, CSWI continued the Mexico initiative that CSW began in 1992. CSWI's goal is to participate in providing for Mexico's future electric power needs. The geographical location of the CSW System offers opportunities to provide bulk power sales to Mexico. The Mexico City office of CSW allows CSWI greater access to key Mexican markets, permitting CSWI to more readily evaluate opportunities as they become available. However, the recent devaluation of the Mexican peso will slow previously projected power demand for the near-term.
CSWI is also evaluating energy-related projects in other international markets.
CSW Communications In July 1994, CSW Communications, a wholly-owned subsidiary of CSW, was formed to provide communication services to the Operating Companies and non-affiliates. One important goal of CSW Communications is to enhance services to CSW System customers through fiber optics and other telecommunications technologies. CSW Communications will consolidate the future design, construction, maintenance and ownership of the CSW System's telecommunications networks. In 1994, CSW announced a $9 million project in Laredo, Texas, to install fiber optic lines and coaxial cable to CPL residential customers who have volunteered to take part in this pilot program. This project involving CSW Communications and CPL will demonstrate the energy efficiency and cost savings that result from giving customers greater choice and control over their electric service. These energy-efficiency services will use only a portion of the capacity of the telecommunications lines CSW Communications is installing. In the future, CSW Communications may, subject to any required regulatory approvals, seek to lease or otherwise use the remaining capacity for other services including possibly telephone service, cable television and home security systems.
1-47 ITEM 2.
ITEM 2. PROPERTIES. CSW, CPL, PSO, SWEPCO and WTU See ITEM 1. BUSINESS - UTILITY OPERATIONS - Facilities for a description of properties used in utility operations.
See ITEM 1. BUSINESS - Transok and CSWE for a description of properties used in non-utility operations.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS. CSW, CPL, PSO, SWEPCO and WTU The registrants are party to various other legal claims, actions and complaints arising in the normal course of business. Management does not expect disposition of these matters to have a material adverse effect on the registrants' results of operations or financial condition.
See ITEM 1. BUSINESS - REGULATION AND RATES, ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - CSW NOTE 10, CPL NOTE 9, PSO NOTE 8, SWEPCO NOTE 9, and WTU NOTE 9, Litigation and Regulatory Proceedings, for information relating to legal and regulatory proceedings.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for each of the registrants, for information related to fuel settlements.
See ITEM 1. BUSINESS - ENVIRONMENTAL MATTERS and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Recent Developments and Trends for each of the registrants, for information relating to environmental proceedings.
CSW and CPL See ITEM 1. BUSINESS - NUCLEAR - STP, ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - CSW NOTE 10 and CPL NOTE 9, Litigation and Regulatory Proceedings, for information as to pending legal proceedings relating to STP.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. CSW, CPL, PSO, SWEPCO and WTU None.
2-1 PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. CSW Common Stock Price Range and Dividends Paid per Share 1994 1993 Market Price Dividends Market Price Dividends High Low Paid High Low Paid (cents) (cents) First Quarter $30 7/8 $24 1/8 42.5 $33 1/4 $28 5/8 40.5 Second Quarter 26 1/4 20 1/8 42.5 34 1/4 28 3/4 40.5 Third Quarter 23 1/4 20 7/8 42.5 33 7/8 32 1/4 40.5 Fourth Quarter 23 3/4 20 1/8 42.5 33 28 1/4 40.5
Common Stock Listing CSW's common stock is traded under the ticker symbol CSR and listed on the New York Stock Exchange, Inc. and Chicago Stock Exchange, Inc.
Common Stock Dividends Dividends of 42.5 cents a share were paid in each quarter of 1994. All dividends paid by CSW represent taxable income to stockholders for federal income tax purposes.
In January 1995, CSW's board of directors increased the quarterly dividend to 43 cents per share, payable on February 28, 1995, to stockholders of record on February 8, 1995. Traditionally, the CSW board of directors has declared dividends to be payable on the last business day of February, May, August, and November. CSW has stated that it is committed to achieving a 75% payout ratio in the long-term as a key component of its corporate strategy to maximize stockholder value.
Stockholders There were approximately 74,000 record holders of CSW's common stock as of December 31, 1994.
CPL, PSO, SWEPCO and WTU All of the outstanding shares of common stock of CPL, PSO, SWEPCO and WTU are owned by CSW.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
Reference is made to the page numbers noted in the following table for the location of ITEM 6. SELECTED FINANCIAL DATA, which is included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Page Number CSW CPL PSO SWEPCO WTU Selected Financial Data 2-6 2-70 2-106 2-132 2-160
2-2 ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Reference is made to the page numbers noted in the following table for the location of ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS which is included in ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Page Number CSW CPL PSO SWEPCO WTU Management's Discussion and Analysis of Financial Condition 2-7 2-71 2-107 2-133 2-161
2-3 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Page CSW Central and South West Corporation 2-5 Selected Financial Data 2-6 Management's Discussion and Analysis of Financial Condition and Results of Operations 2-7 Consolidated Statements of Income 2-26 Consolidated Statements of Retained Earnings 2-27 Consolidated Balance Sheets 2-28 Consolidated Statements of Cash Flows 2-30 Notes to Consolidated Financial Statements 2-31 Report of Independent Public Accountants 2-67 Report of Management 2-68
CPL Central Power and Light Company 2-69 Selected Financial Data 2-70 Management's Discussion and Analysis of Financial Condition and Results of Operations 2-71 Statements of Income 2-81 Statements of Retained Earnings 2-82 Balance Sheets 2-83 Statements of Cash Flows 2-85 Statements of Capitalization 2-86 Notes to Financial Statements 2-87 Report of Independent Public Accountants 2-103 Report of Management 2-104
PSO Public Service Company of Oklahoma 2-105 Selected Financial Data 2-106 Management's Discussion and Analysis of Financial Condition and Results of Operations 2-107 Consolidated Statements of Income 2-113 Consolidated Statements of Retained Earnings 2-114 Consolidated Balance Sheets 2-115 Consolidated Statements of Cash Flows 2-117 Consolidated Statements of Capitalization 2-118 Notes to Consolidated Financial Statements 2-119 Report of Independent Public Accountants 2-129 Report of Management 2-130
2-4 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. (continued)
SWEPCO Southwestern Electric Power Company 2-131 Selected Financial Data 2-132 Management's Discussion and Analysis of Financial Condition and Results of Operations 2-133 Statements of Income 2-141 Statements of Retained Earnings 2-142 Balance Sheets 2-143 Statements of Cash Flows 2-145 Statements of Capitalization 2-146 Notes to Financial Statements 2-147 Report of Independent Public Accountants 2-157 Report of Management 2-158
WTU West Texas Utilities Company 2-159 Selected Financial Data 2-160 Management's Discussion and Analysis of Financial Condition and Results of Operations 2-161 Statements of Income 2-169 Statements of Retained Earnings 2-170 Balance Sheets 2-171 Statements of Cash Flows 2-173 Statements of Capitalization 2-174 Notes to Financial Statements 2-175 Report of Independent Public Accountants 2-186 Report of Management 2-187
2-5
CSW
CENTRAL AND SOUTH WEST CORPORATION
2-6 Selected Financial Data CSW The following selected financial data for each of the five years ended December 31 are provided to highlight significant trends in the financial condition and results of operations for CSW.
1994 1993 1992 1991 1990 (millions, except per share amounts and ratios) Operating Revenues $ 3,623 $ 3,687 $ 3,289 $ 3,047 $2,744 Income Before Cumulative Effect of Changes in Accounting Principles 412 281 404 401 386 Cumulative Effect of Changes in Accounting Principlies (1) -- 46 -- -- -- Net Income 412 327 404 401 386 Preferred Stock Dividends 18 19 22 26 30 Dividends Net Income for Common Stock 394 308 382 375 356
Total Assets (2) 10,909 10,604 9,829 9,396 9,074
Common Stock Equity 3,052 2,930 2,927 2,834 2,743 Preferred Stock Not Subject to Mandatory Redemption 292 292 292 292 291 Subject to Mandatory Redemption 35 58 75 97 103 Long-term Debt 2,940 2,749 2,647 2,518 2,513
Capitalization Ratios Common Stock Equity 48.3% 48.6% 49.3% 49.4% 48.5% Preferred Stock 5.2 5.8 6.2 6.8 7.0 Long-term Debt 46.5 45.6 44.5 43.8 44.5 Earnings per Share of Common Stock $2.08 $1.63 $2.03 $1.99 $1.89 Dividends Paid per Share of Common Stock $1.70 $1.62 $1.54 $1.46 $1.38
(1) The 1993 cumulative effect relates to the changes in accounting for unbilled revenues and adoption of SFAS No. 112, Employer's Accounting for Postemployment Benefits and the adoption of SFAS No. 109, Accounting for Income Taxes. See NOTE 1. Summary of Significant Accounting Policies.
(2) The 1992 - 1990 total assets have been reclassified to reflect the effects of the adoption in 1993 of SFAS No. 109, Accounting for Income Taxes. See NOTE 2. Federal Income Taxes.
All common stock data have been adjusted to reflect the two-for-one common stock split, effected by a 100% stock dividend paid on March 6, 1992, to stockholders of record on February 10, 1992.
CSW changed its method of accounting for unbilled revenues in 1993. Pro forma amounts, assuming that the change in accounting for unbilled revenues had been adopted retroactively, are not materially different from amounts reported for prior years and therefore have not been restated.
2-7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CENTRAL AND SOUTH WEST CORPORATION
Reference is made to CSW's Consolidated Financial Statements and related Notes and Selected Financial Data. The information contained therein should be read in conjunction with, and is essential in understanding, the following discussion and analysis.
Overview The electric utility industry is changing rapidly and becoming more competitive. Several years ago, in anticipation of increasing competition and fundamental changes in the industry, CSW's management developed a four-part strategic plan. This plan is designed to help position CSW to be competitive in the rapidly changing environment that the CSW System currently faces. The four-part strategy is:
Enhance CSW's core electric utility business.
Expand CSW's core electric utility business.
Expand CSW's non-utility business.
Pursue financial initiatives.
Since the introduction of CSW's strategic plan in 1990, CSW has undertaken initiatives in each of these areas that are important steps in the implementation of the overall strategy. These initiatives were marked by the efforts in the proposed acquisition of El Paso and the continued restructuring of CSW's core business. In addition, CSW has faced some operational challenges during the past two years with the outage and 1994 restart of STP. These events are discussed below and elsewhere in this report.
CSW and the Electric Operating Companies believe that, compared to other electric utilities, the CSW System is well positioned to meet future competition. The CSW System benefits from economies of scale and scope by virtue of its size and is a relatively low-cost producer of electric power. Moreover, CSW is taking steps to enhance its marketing and customer service, reduce costs, improve and standardize business practices, and grow through strategic acquisitions, in order to position itself for increased competition in the future.
Proposed Acquisition of El Paso El Paso filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code on January 8, 1992. In May 1993, CSW entered into a Merger Agreement pursuant to which El Paso would emerge from bankruptcy as a wholly-owned subsidiary of CSW. El Paso is an electric utility company headquartered in El Paso, Texas, engaged principally in the generation and distribution of electricity to approximately 262,000 retail customers in west Texas and southern New Mexico. El Paso also sells electricity under contract to wholesale customers in a number of locations including southern California and Mexico.
On July 30, 1993, El Paso filed the Modified Plan and a related proposed form of disclosure statement providing for the acquisition of El Paso by CSW. On November 15, 1993, all voting classes of creditors and shareholders of El Paso voted to approve the Modified Plan. On December 8, 1993, the Bankruptcy Court confirmed the Modified Plan.
Under the Modified Plan, the total value of CSW's offer to acquire El Paso is approximately $2.2 billion. The Modified Plan generally provides for El Paso creditors and shareholders to receive shares of CSW Common, cash and/or securities of El Paso, or to have
2-8 their claims cured and reinstated. The Modified Plan also provides for claims of secured creditors generally to be paid in full with debt securities of reorganized El Paso, and for unsecured creditors to receive a combination of debt securities of reorganized El Paso and CSW Common equal to 95.5 percent of their claims, and for small trade creditors to be paid in full with cash. The Modified Plan provides for El Paso's preferred shareholders to receive preferred shares of reorganized El Paso, or cash, and for options to purchase El Paso Common to be converted into options to purchase a proportionate number of shares of CSW Common.
Based on information provided by El Paso, 35,544,330 shares of El Paso Common were outstanding as of the Confirmation Date. The Modified Plan provides for El Paso's common shareholders to receive between $3.00 and $4.50, plus dividends, per share of El Paso Common to be paid in CSW Common as described below. The Merger Agreement provides for each share of El Paso Common to be converted on the Effective Date into the number of shares of CSW Common with a value (based on a value of $29.4583 per share of CSW Common) equal to the sum of (i) $3.00 per share of El Paso Common outstanding on the Confirmation Date, (ii) any proceeds received by El Paso prior to the Effective Date from certain contingent claims based on a value of CSW Common equal to the closing price on the New York Stock Exchange on the day such proceeds are received by El Paso, and (iii) the dividends that would be deemed to have been paid on the amounts described in items (i) and (ii) above from the Confirmation Date, or the date upon which such contingent claims are converted into cash, as the case may be, through and including the Effective Date, as well as dividends that would have been paid on such dividends under (iii) above; provided, however, that the sum of (i) and (ii) above will not exceed $4.50 multiplied by the number of shares of El Paso Common outstanding on the Confirmation Date. If $4.50 per share of El Paso Common has not been realized under items (i) and (ii) above and any of the contingent claims are remaining on the Effective Date, the Modified Plan and Merger Agreement provide for a liquidation trust to be established pursuant to the Modified Plan and for El Paso's rights in those contingent claims to be assigned to the trust. The Modified Plan provides for proceeds resulting from disposition of the assets in the liquidation trust, if any, to be distributed pro rata to the holders of El Paso Common up to $4.50 per share under items (i) and (ii) above, with any net proceeds thereafter to be returned to El Paso. El Paso has stated publicly that it has realized sufficient proceeds from the contingent claims referred to in item (ii) above so that no liquidation trust would be required.
The aggregate number of shares of CSW Common that would be issued in connection with the Merger cannot be determined at this time due to certain contingencies, including the future price of CSW Common, future dividend rates on CSW Common and the occurrence and timing of the Effective Date of the Merger. CSW has estimated the value of the shares to be issued to El Paso stakeholders at approximately $569 million based on an assumed Effective Date in the first half of 1995. In addition, CSW expects to make payments in cash of approximately $335 million in connection with the consummation of the Merger, a portion of which would be funded by cash in the El Paso estate and an estimated $200 million of which would be funded from other internal or external sources which may include a new issuance of CSW Common or debt securities. Depending on the number of shares issued and the outcome of other matters discussed below, existing holders of CSW Common could experience short-term dilution in earnings if the Merger is consummated. As of December 31, 1994, the price per share of CSW Common had declined by approximately 31% since May 3, 1993, the date of the Merger Agreement. Because the number of shares of CSW Common and the interest rates of the debt securities that would be issued to the creditor groups in connection with the Merger are to be set on or about the Effective Date, changes in the price of CSW Common and the level of interest rates would affect the economic impact of the proposed acquisition to CSW.
The Merger is subject to numerous conditions set forth in the Merger Agreement, including but not limited to (i) the receipt of final orders with respect to all required regulatory approvals on terms that would not cause a regulatory material adverse effect as defined in the Merger Agreement, (ii) the receipt of all third party consents, (iii) the absence of a material adverse effect or facts or circumstances that could reasonably be expected to result in a material adverse effect on El Paso or the business prospects of El Paso, (iv) transfer to El Paso of good and marketable title to the leased portion of El Paso's share of Palo Verde, (v) performance by
2-9 El Paso, CSW and CSW's acquisition subsidiary, CSW Sub, Inc., in all material respects of all covenants contained in the Merger Agreement and (vi) the occurrence of the Effective Date under the Modified Plan. Required regulatory approvals and filings in connection with the Merger include approvals of the FERC, the SEC, the Texas Commission, the New Mexico Commission, the NRC, and filings with the Department of Justice and the Federal Trade Commission under the Hart- Scott-Rodino Antitrust Improvements Act of 1976.
The Merger Agreement also provides that CSW and El Paso have the right to terminate the Merger Agreement under specified circumstances including without limitation, (i) the filing of a stand-alone rate plan by El Paso, (ii) the failure of the Effective Date to occur within 18 months after the Confirmation Date (i.e., by June 8, 1995), or , if extended by mutual consent of CSW and El Paso, within 24 months of the Confirmation Date (i.e., by December 8, 1995), or (iii) the entering of any order denying any of the required regulatory approvals. In the event the Merger Agreement is terminated, a termination fee is payable in limited circumstances. El Paso is required to pay a termination fee of $50 million to CSW if El Paso terminates the Merger Agreement under certain circumstances and subsequently consummates a merger with another party. CSW and El Paso would be required to pay a $25 million termination fee to the other party in the case of termination based upon a material breach of the Merger Agreement or failure to approve an extension of time permitted to consummate the Merger under specified circumstances. If the Merger Agreement is terminated, whether or not any termination fee is payable, CSW could be required, in most cases, to recognize as an expense deferred costs associated with the Merger, which amounted to approximately $36 million at December 31, 1994. Additionally, under certain circumstances, if the Merger is not consummated, the Merger Agreement provides for CSW to pay El Paso a portion of certain interest costs and certain fees and expenses. CSW's potential exposure as of December 31, 1994 is estimated to be approximately $17.5 million; however, the actual amount, if any, that CSW may be required to pay pursuant to these provisions depends on a number of contingencies and cannot presently be predicted.
CSW continues to use its best efforts to consummate the Merger. At the same time, however, CSW continues to monitor contingencies which may preclude the consummation of the Merger, including without limitation the potential loss of significant portions of El Paso's service area and significant El Paso customers, including Las Cruces and two military installations, Holloman Air Force Base and White Sands Missile Range, regulatory risks principally related to approval of the Merger and El Paso's request for a rate increase in Texas as well as the effects of the conditions imposed by federal or state regulatory agencies on the approval of the Merger, and operating risks associated with the ownership of an interest in Palo Verde.
Based upon El Paso's written response to the concerns identified in a September 12 letter from CSW to El Paso and the failure of El Paso to resolve the contingencies set forth above, CSW cannot predict whether, or if so when, the Merger will be consummated. In the event that the proposed Merger is not consummated, there may be ensuing litigation between El Paso and CSW or among other parties to El Paso's bankruptcy proceedings and either or both of El Paso and CSW.
Management is unable to predict the ultimate outcome of the proposed Merger. In the event that recognition of any or all of these expenses is required, it could have a material adverse impact on CSW's consolidated results of operations in the period they are recognized, but would not be expected to have a material adverse impact on CSW's consolidated results of operations or financial condition.
See NOTE 11, Commitments and Contingent Liabilities - Proposed Acquisition of El Paso, for additional information related to the proposed El Paso merger.
Restructuring As previously reported, the CSW System has taken steps to implement a restructuring and early retirement program designed to consolidate and restructure its operations in order to meet the challenges of the changing electric utility industry and to compete effectively in the years ahead. The underlying goal of the
2-10 restructuring is to enable the Electric Operating Companies to focus on and be accountable for serving the customer. The restructuring costs were initially estimated to be $97 million and were expensed in 1993. The final costs of the restructuring were approximately $88 million. Approximately $84 million of the restructuring expenditures were incurred during 1994, with the remaining $4 million expected to be incurred during 1995. Approximately $12 million of the restructuring expenses relate to employee termination benefits, $45 million relate to enhanced benefit costs and $31 million relate to employees that will not be terminated. Approximately $60 million of the restructuring costs were paid from or will be paid from general corporate funds. The remaining $28 million represents the present value of enhanced benefit amounts to be paid from the benefit plan trusts to participants over future years in accordance with the early retirement program. The cost of these enhanced benefit amounts will be paid from general corporate funds to the benefit plan trusts over future years. The restructuring is substantially completed, with the remaining activity to take place during 1995. Certain aspects of the restructuring are pending SEC approval under the Holding Company Act.
CSW expects to realize a number of benefits from the restructuring. Beginning in 1994 and continuing into the future, increased efficiencies and synergies are expected to be realized with the elimination of previously duplicated functions. This leads to enhanced communication and efficiency, which should translate into a reduction in the rate of growth in O&M costs. All restructuring costs are expected to be recovered by early 1996 with reductions in the rate of growth of O&M costs continuing thereafter.
STP Introduction CPL owns 25.2% of STP, a two-unit nuclear power plant which is located near Bay City, Texas. In addition to CPL, HLP, the Project Manager, owns 30.8%, San Antonio owns 28.0%, and Austin owns 16.0%. STP Unit 1 was placed in service in August 1988 and STP Unit 2 was placed in service in June 1989.
From February 1993 until May 1994, STP experienced an unscheduled outage which has resulted in significant rate and regulatory proceedings involving CPL. These matters, including a base rate case and fuel reconciliation proceedings, are discussed immediately below.
STP Outage In February 1993, Units 1 and 2 of STP were shut down by HLP in an unscheduled outage resulting from mechanical problems. HLP determined that the units would not be restarted until the equipment failures had been corrected and the NRC was briefed on the causes of these failures and the corrective actions that were taken. The NRC formalized that commitment in a confirmatory action letter that it supplemented to identify additional issues to be resolved and verified by the NRC before STP could be restarted.
During the outage, the necessary improvements were made by HLP to address the issues in the confirmatory action letter, as supplemented. On February 15, 1994, the NRC agreed that the confirmatory action letter issues had been resolved with respect to Unit 1, and that it agreed with HLP's recommendation that Unit 1 was ready to restart. Unit 1 restarted on February 25, 1994 and reached 100% power on April 8, 1994. Subsequently, the issues with respect to Unit 2 were resolved and the NRC on May 17, 1994 agreed with HLP's recommendation to restart Unit 2. Unit 2 resumed operation on May 30, 1994 and reached 100% power on June 16, 1994. During 1994, Unit 1 and Unit 2 achieved annual net capacity factors of 75.3% and 54.7%, respectively. During the last six months of 1994, the STP units operated at capacity factors of 98.6% for Unit 1 and 99.2% for Unit 2.
In June 1993, the NRC placed STP on its "watch list" of plants with "weaknesses that warrant increased NRC attention." The decision to place STP on the watch list followed the June 1993 issuance of a report by an NRC Diagnostic Evaluation Team which conducted a review of STP operations.
On February 3, 1995, the NRC removed STP from the "watch list". The NRC noted that the four key areas for their decision were sustained improvement throughout 1994, high standards of performance exhibited by the plant, effective maintenance and engineering support
2-11 resulting in reduced equipment repair backlogs and improved plant reliability, and the open and positive employee climate at the plant. With the NRC reviewing the "watch list" status every 6 months and with Unit 2 achieving 100% power in June of 1994, the February review was the first realistic opportunity for STP to be considered for a change in status. On average, plants previously placed on the "watch list" have stayed on the list for 29 months.
Rates and Regulatory Matters CPL Rate Inquiry Several Cities, the Texas Commission General Counsel and others initiated actions in late 1993 and early 1994 which, if approved by the Texas Commission, would lower CPL's base rates. The requests for a review of CPL's rates arose out of the unscheduled outage at STP which began in February 1993. The STP outage did not affect CPL's ability to meet customer demand because of existing capacity and CPL's purchase of additional energy.
CPL submitted a filing package on July 1, 1994, to the Texas Commission justifying its current base rate structure. Parties to CPL's base rate case have filed testimony with the Texas Commission recommending reductions in CPL's retail base rates of up to $147 million annually, resulting from a combination of proposed rate base and cost of service reductions, as well as a rate base disallowance of up to $400 million.
The Texas Commission held hearings in November and December 1994, and all parties have filed briefs in the case. The ALJ is expected to issue a recommended order for consideration by the Texas Commission in April 1995 with a final order from the Texas Commission expected in May 1995. Testimony filed by parties to the rate case, including the Staff, is not binding on either the ALJ or the Texas Commission.
CPL continues to maintain that its rates are reasonable and that its earnings are within established regulatory guidelines. In addition, CPL strongly believes that 100 percent of its investment in both units of STP belongs in rate base. This belief is based on, among other factors, Units 1 and 2 providing output at high capacity factors since April and June 1994, respectively. In addition, the long-term benefits nuclear generation provides to customers further support their inclusion in rate base. Furthermore, there are no Texas Commission precedents addressing the removal of a nuclear plant from rate base as a performance disallowance. Assuming both units of STP are included in rate base, CPL believes it is not collecting excessive revenues, notwithstanding that market rates of return on common equity are generally lower today than they were in 1990 and 1991, when CPL's base rates were last set.
CPL Fuel Pursuant to the substantive rules of the Texas Commission, CPL generally is allowed to recover its fuel costs through a fixed fuel factor. These fuel factors are in the nature of temporary rates, and CPL's collection of revenues by such fuel factors is subject to adjustment at the time of a fuel reconciliation proceeding before the Texas Commission. The difference between fuel revenues billed and fuel expense incurred is recorded as an addition to or a reduction from revenues, with a corresponding entry to unrecovered fuel costs or other current liabilities, as appropriate. Any fuel costs, not limited to under- or over-recoveries, which the Texas Commission determines as unreasonable in a reconciliation proceeding are not recoverable from customers.
CPL is currently involved in two proceedings before the Texas Commission relating to the recovery of fuel and purchased power costs. CPL originally filed Docket No. 12154 seeking approval of a customer surcharge to recover fuel and purchased power costs, including those resulting from the STP outage. In Docket No. 13126, the Texas Commission General Counsel and others are reviewing the prudence of management activities at STP. In November 1994, CPL filed a fuel reconciliation case in Docket No. 13650 with the Texas Commission seeking to reconcile fuel costs since March 1, 1990, including the period during which CPL's fuel and purchased power costs were increased due to the STP outage. At December 31, 1994, CPL's under-recovered fuel balance was $54.1 million, exclusive of interest, which was due primarily to the STP outage. If a
2-12 significant portion of the fuel costs were disallowed by the Texas Commission, CSW could experience a material adverse effect on its consolidated results of operations in the year of disallowance but not on its financial condition. Finally, in Docket No. 13126, the Texas Commission General Counsel is reviewing the prudence of management activities at STP. On January 4, 1995, Docket No. 12154 was consolidated into Docket No. 13650. The results of the prudence inquiry in Docket No. 13126 are expected to be incorporated into the fuel reconciliation proceedings in Docket No. 13650.
CPL continues to negotiate with the intervening parties to resolve these matters through settlement. However, no settlement has been reached to date.
Management cannot predict the ultimate outcome of these regulatory proceedings. However, management believes that the ultimate resolution of the various issues will not have a material adverse effect on CSW's consolidated results of operations or financial condition.
See NOTE 10, Litigation and Regulatory Proceedings - CPL, STP, for a discussion of regulatory proceedings arising out of the STP outage and background on STP rate orders and deferred accounting.
Nuclear Decommissioning CPL's decommissioning costs are accrued and funded to an external trust over the expected service life of the STP units. The existing NRC operating licenses will allow the operation of STP Unit 1 until 2027, and Unit 2 until 2028. The accrual is an annual level cost based on the estimated future cost to decommission STP, including escalations for expected inflation to the expected time of decommissioning and is net of expected earnings on the trust fund.
The staff of the SEC has questioned certain of the current accounting practices of the electric utility industry regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations. In response to these questions, FASB has agreed to review the accounting for removal costs, including decommissioning. If current electric utility industry accounting practices for such decommissioning are changed, (i) annual provisions for decommissioning could increase, (ii) the estimated cost for decommissioning could be recorded as a liability rather than as accumulated depreciation, and (iii) trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense.
See NOTE 1, Summary of Significant Accounting Policies - Nuclear Decommissioning, for further information regarding CPL's decommissioning of STP.
See NOTE 10, Litigation and Regulatory Proceedings, for information regarding other rate and regulatory matters, including the PSO rate case, the SWEPCO fuel reconciliation, and WTU's fuel and rate proceedings.
New Accounting Standards SFAS No. 115, was effective for fiscal years beginning after December 15, 1993. CSW adopted SFAS No. 115 in 1994. The adoption of SFAS No. 115 did not have a material effect on CSW's consolidated results of operations or financial condition.
In June 1993 the FASB issued SFAS No. 116. The statement, effective for fiscal years beginning after December 15, 1994, will be adopted by CSW for 1995. The statement establishes accounting standards for contributions and applies to all entities that receive or make contributions. Management does not believe the adoption of SFAS No. 116 will have a material impact on CSW's consolidated results of operations or financial condition.
2-13 SFAS No. 119 was effective for fiscal years ending after December 15, 1994. Transok, which is the only subsidiary of CSW currently using derivative financial instruments, uses derivatives to manage price and market risks for gas purchases and sales. The Electric Operating Companies may use these instruments in the future to manage the increased market risks associated with greater competition in the electric utility industry. The adoption of this new statement had no material effect on CSW's consolidated results of operations or financial condition.
Liquidity and Capital Resources Overview The historical capital requirements of the CSW System have been primarily for the construction of electric utility plant. Large capital expenditures for the construction of new generating capacity are not planned through the end of this decade. Accordingly, internally generated funds should meet most of the capital requirements of the Electric Operating Companies. However, CSW's strategic initiatives, including expanding CSW's core electric utility and non-utility businesses, may require additional capital. Primary sources of capital are long-term debt and preferred stock issued by the Electric Operating Companies, common stock issued by CSW and internally generated funds. In addition, CSWE uses various forms of non-recourse project financing. CSW, in order to strengthen its capital structure and support growth from time to time, may issue additional shares of its common stock.
Productive investment of net funds from operations in excess of capital expenditures and dividend payments are necessary to enhance the long-term value of CSW for its investors. CSW is continually evaluating the best use of these funds. CSW is required to obtain authorization from various regulators in order to invest in any additional business activities.
Capital Expenditures Construction expenditures for the CSW System totaled $578 million in 1994. Based on projections of growth in peak demand, the CSW System will not require significant additional generating capability through the end of this decade. Planned construction expenditures for the Electric Operating Companies for the next three years are primarily to improve and expand distribution facilities. These improvements will be required to meet the needs of new customers and the growth in the requirements of existing customers. Construction expenditures, excluding capital required for acquisitions by CSW or its subsidiaries, if any, are expected to be approximately $385 million, $382 million and $358 million during 1995, 1996, and 1997, respectively. Not included in the 1995 amount is approximately $61 million of equity investments by CSWE.
The construction program continues to be monitored, reviewed and adjusted to reflect changes in estimated load growth in the Electric Operating Companies' service areas, variations in prices of alternative fuel sources, the cost of labor, materials, equipment and capital, and other external factors.
The CSW System facilities plan presently includes projected coal and lignite-fired generating plants for which the CSW System has invested approximately $140 million in prior years for plant sites, engineering studies and lignite reserves. Should future plans exclude these plants for environmental or other reasons, CSW would evaluate the probability of recovery of these investments and may record appropriate reserves.
Long-Term Financing As of December 31, 1994, the capitalization ratios of CSW were: common stock equity 48%, preferred stock 5% and long-term debt 47%. The CSW System's embedded cost of long-term debt was 7.7% at the end of 1994. The CSW System continually monitors the capital markets for opportunities to lower its cost of capital through refinancing. The CSW System continues to be committed to maintaining financial flexibility by maintaining a strong capital structure and favorable securities ratings which should allow funds to be obtained from the capital markets when required.
2-14 The CSW System's significant long-term financing activity for 1994 and 1995 to date is summarized as follows:
Security Issued Security Reacquired Security Amount Rate Maturity Security Amount Rate Maturity (millions) (millions) CPL FMB(1) $100.0 7-1/2% 1999 PFDs $22.4 10.05% -- FMB 0.6 9-3/8% 2019
SWEPCO Term Term Loan 50.0 Floating 2000 Loan 50.0 Floating 1997 FMB 5.8 9-1/8% 2019
WTU FMB(2) 40.0 6-1/8% 2004 FMB 12.0 7-1/4% 1999 FMB(3) 40.0 7-1/2% 2000 FMB 7.8 9-1/4% 2019 PFDs 4.7 7-1/4% -- CSWS Term(4) Loan 60.0 Floating 2001
(1) Net proceeds were used to repay a portion of CPL's short-term borrowings.
(2) Net proceeds were used to reimburse WTU's treasury for (i) $12 million aggregate principal amount of 7-1/4% FMBs, Series G, due January 1, 1999, redeemed on January 1, 1994, and (ii) $23 million aggregate principal amount of 7-7/8% FMBs, Series H, due July 1, 2003, redeemed on December 30, 1993. The balance of the proceeds were used to repay outstanding short-term borrowings.
(3) Issuance occurred in 1995 and is not reflected in the 1994 financial statements. Net proceeds were used to repay a portion of WTU's short-term debt, to provide working capital and for other general corporate purposes.
(4) Proceeds were used to repay short-term debt, which had been previously used to finance certain assets, including the CSW headquarters building in Dallas, Texas.
Shelf Registration Statements The Electric Operating Companies expect to obtain a majority of their 1995 capital requirements from internal sources, but may issue additional securities subject to market conditions and other factors. CPL and WTU have filed shelf registration statements with the SEC for the sale of securities. The amount available for issuance by company and the date filed with the SEC follow:
First Mortgage Bonds Preferred Stock Amount Date Filed Amount Date Filed Available Available (millions) (millions) CPL $260 1993 $75 1994
WTU $20 1993
The Operating Companies may issue additional debt securities subject to market conditions and other factors. The proceeds of any such offerings will be used principally to redeem higher cost FMBs, to lower the embedded cost of debt, to repay short-term debt, to provide working capital and for other general corporate purposes.
2-15 The Electric Operating Companies may issue additional preferred stock subject to market conditions and other factors. The proceeds of any such offerings will be used principally to redeem higher cost preferred stock and to repay short-term debt.
Short-Term Financing The Electric Operating Companies utilize short-term debt to meet fluctuations in working capital requirements due to the seasonal nature of electric sales. The CSW System has established a money pool to coordinate short-term borrowings and to make borrowings outside the money pool through CSW's issuance of commercial paper. At December 31, 1994, the CSW System had bank lines of credit aggregating $930 million to back up the CSW commercial paper program.
The maximum amount of consolidated short-term debt outstanding in 1994 was $1,618 million in September 1994, which represented 26% of the total capitalization at December 31, 1994. The average amount of short-term debt during 1994 was $1,455 million, of which $694 million was attributable to CSW Credit. The weighted average cost of short- term debt was 4.5% in 1994. Short-term debt outstanding increased due to continued expenditures for corporate initiatives, including investments in CSWE.
Acquisitions To meet its strategic goals, CSW will continue to search for electric utility companies or other electric utility properties to acquire and will continue evaluating opportunities to pursue energy related non-utility businesses. For any major acquisition, additional funds from the capital markets, including the issuance of CSW Common in underwritten public offerings, in the acquisition transaction itself, or otherwise, may be required.
For a discussion of circumstances under which CSW may issue additional shares of common stock in connection with the proposed acquisition of El Paso, see Proposed Acquisition of El Paso, above.
Dividend Reinvestment Plan The PowerShare dividend reinvestment plan is available to all CSW stockholders, employees, eligible retirees, utility customers and other residents of the four states where the Electric Operating Companies operate. Plan participants are able to make optional cash payments and reinvest all or any portion of their dividends in CSW Common. During 1994 CSW raised approximately $50 million in new equity through the PowerShare plan.
Internally Generated Funds Internally generated funds consist of cash flows from operating activities less common and preferred stock dividends. The Electric Operating Companies utilize short-term debt to meet fluctuations in working capital requirements due to the seasonal nature of energy sales. Information concerning internally generated funds follows:
1994 1993 1992 (millions) Internally Generated Funds $424 $369 $374
Capital expenditures, Acquisitions, CSWE Equity Investments Provided by Internally Generated Funds 63% 58% 82%
CSWE and CSWI At December 31, 1994, CSW had loaned $221 million to CSWE on an interim basis for the purpose of developing and constructing independent power and cogeneration facilities. Repayment of these amounts to CSW is expected to be made through funds obtained from third party non-recourse project financing. In late February 1994, CSWE closed permanent project financing for its 50% owned Mulberry facility, which is described below, and repaid $94 million of the interim financing provided by CSW. In March 1995, CSWE closed permanent project financing for its Ft. Lupton facility, which is described below, and repaid $102 million of the interim financing provided by CSW. In addition to the amounts already expended in 1994 for the development of projects, CSWE and CSWI have general authority from the SEC to expend up to $242 million and $399 million, respectively, on future projects.
CSW Credit CSW Credit purchases, without recourse, the accounts receivable of the Operating Companies and certain non-affiliated electric companies. CSW Credit's capital structure contains greater leverage than that of the Operating Companies, consequently lowering CSW's cost of capital.
CSW Credit issues commercial paper, secured by the assignment of its receivables, to meet its financing needs. CSW Credit maintains a secured revolving credit agreement which aggregated $900 million at December 31, 1994 to back up its commercial paper program.
The sale of these accounts receivables provides the Operating Companies with cash immediately, thereby reducing working capital needs and revenue requirements.
Recent Developments and Trends
Competition and Industry Challenges Competitive forces at work in the electric utility industry are impacting the CSW System and electric utilities generally. Increased competition facing electric utilities is driven by complex economic, political and technological factors. These factors have resulted in legislative and regulatory initiatives that are likely to result in even greater competition at both the wholesale and retail level in the future. As competition in the industry increases, the Electric Operating Companies will have the opportunity to seek new customers and at the same time be at risk of losing customers to other competitors. The Electric Operating Companies believe that their prices for electricity and the quality and reliability of their service currently place them in a position to compete effectively in the marketplace.
The Energy Policy Act, which was enacted in 1992, significantly alters the way in which electric utilities compete. The Energy Policy Act creates exemptions from regulation under the Holding Company Act and permits utilities, including registered utility holding companies and non-utility companies, to form EWGs. EWGs are a new category of non-utility wholesale power producer that are free from most federal and state regulation, including the principal restrictions of the Holding Company Act. These provisions enable broader participation in wholesale power markets by reducing regulatory hurdles to such participation. The Energy Policy Act also allows the FERC, on a case- by-case basis and with certain restrictions, to order wholesale transmission access and to order electric utilities to enlarge their transmission systems. A FERC order requiring a transmitting utility to provide wholesale transmission service must include provisions generally that permit (i) the utility to recover from the FERC applicant all of the costs incurred in connection with the transmission services and (ii) any enlargement of the transmission system and associated services. While CSW believes that the Energy Policy Act will continue to make the wholesale markets more competitive, CSW is unable to predict the extent to which the Energy Policy Act will impact CSW System operations.
Increasing competition in the utility industry brings an increased need to stabilize or reduce rates. The retail regulatory environment is beginning to shift from traditional rate base regulation to incentive regulation. Incentive rate and performance- based plans encourage efficiencies and increased productivity while permitting utilities to share in the results. Retail wheeling, a major industry issue which may require utilities to "wheel" or move power from third parties to their own retail customer, is evolving gradually.
The Electric Operating Companies also compete with suppliers of alternative forms of energy, such as natural gas, fuel oil and coal, some of which may be cheaper than electricity. The Electric Operating Companies believe that their prices and the quality and reliability of
2-17 their service currently places them in a position to compete effectively in the marketplace.
Wholesale energy markets, including the market for wholesale electric power, have been extremely competitive since the enactment of the Energy Policy Act. The Electric Operating Companies compete in the wholesale energy markets with other public utilities, cogenerators, qualified facilities, exempt wholesale generators and others for sales of electric power.
Under the Energy Policy Act, the FERC has approved several proposals by utility companies to sell wholesale power at market-based rates and provide to electric utilities "open access" to transmission systems, subject to certain requirements. The adoption of these proposals increases marketing opportunities for electric utilities, but also exposes them to the risk of loss of load or reduced revenues due to competition with alternative suppliers. In 1993, PSO and SWEPCO filed with the FERC tariffs under which they make available firm and non-firm transmission services for other electric utilities on the combined PSO and SWEPCO transmission systems in the Southwest Power Pool. The FERC accepted the tariffs for filing on November 9, 1993. In the event the FERC approves the Merger between CSW and El Paso and denies CSW's request for rehearing wherein CSW asked FERC to reconsider the imposition of a comparable service requirement, these tariffs could be superseded by a set of compliance tariffs which offer point-to-point and network transmission service on terms and conditions comparable to CSW's and El Paso's use of their own transmission systems. As discussed, compliance tariffs could expose the merged CSW System to additional risks of loss of load from current requirements wholesale customers purchasing power from alternative suppliers or reduced revenue resulting from competition with alternative suppliers of electric power.
CSW and the Electric Operating Companies believe that, compared to other electric utilities, the CSW System is well positioned to meet future competition. The CSW System benefits from economies of scale and scope by virtue of its size and is a relatively low-cost producer of electric power. Moreover, CSW is taking steps to enhance its marketing and customer service, reduce costs, improve and standardize business practices, and grow through strategic acquisitions, in order to position itself for increased competition in the future.
CSW is unable to predict the ultimate outcome or impact of competitive forces on the electric utility industry or the CSW System. As the wholesale and retail electricity markets become more competitive, however, the principal factor determining success is likely to be price, and to a lesser extent, reliability, availability of capacity, and customer service.
Public Utility Regulatory Act PURA is the legal foundation for electric utility regulation in Texas. PURA will expire on September 1, 1995, in accordance with the sunset policy of the Texas Legislature, which applies to all state agencies, unless the Texas Legislature reenacts PURA in its current form or in modified form. Several proposals have been made to amend PURA which, among other things, provide for a market-driven integrated resource planning process, pricing flexibility for utilities faced with competitive challenges, incentive regulation and deregulation of the wholesale bulk power market in ERCOT. CSW is unable to predict the ultimate outcome of the 1995 session of the Texas Legislature and in particular whether amendments to PURA will be adopted. If, however, the Texas Legislature passes legislation permitting any form of retail wheeling, such legislation could have an adverse impact on CPL and CPL's sales to its retail customers.
Regulatory Accounting Consistent with industry practice and the provisions of SFAS No. 71, which allows for the recognition and recovery of regulatory assets, the Electric Operating Companies have recognized significant regulatory assets and liabilities. Management believes that the Electric Operating Companies will continue to meet the criteria for following SFAS No. 71. However, in the event the Electric Operating Companies no longer meet the criteria for following SFAS No. 71, a write-off of regulatory assets and liabilities would be required. For additional information regarding SFAS No. 71 reference is made to NOTE
2-18 1, Summary of Significant Accounting Policies - Regulatory Assets and Liabilities.
Holding Company Act The Holding Company Act generally has been construed to limit the operations of a registered holding company to a single integrated public utility system, plus such additional businesses as are functionally related to such system. Among other things, the Holding Company Act requires CSW and its subsidiaries to seek prior SEC approval before effecting mergers and acquisitions or pursuing other types of non-utility initiatives. Pervasive regulation under the Holding Company Act may impede or delay CSW's efforts to achieve its strategic and operating objectives, including its pursuit of non- utility initiatives. CSW is continuing its efforts to repeal or modify the Holding Company Act in order to provide the flexibility to compete within the changing environment.
Consolidated Taxes The Texas Commission before 1992 allowed income taxes to be recovered in rates based on the federal income tax incurred by a utility as if it were a stand-alone company. This stand-alone approach treated the regulated activities of a utility as a separate entity and considered only those revenues and expenses that are included in the utility's cost of service to calculate the federal income tax liability for ratemaking purposes.
Beginning in 1992, the Texas Commission changed its method of calculating the federal income tax component of rates to the "actual tax approach." The actual tax approach is an evolving concept but generally seeks to reflect in rates the actual tax liability of the utility irrespective of its relationship to the utility's cost of service. The approach reduces rates by the tax benefits of deductions which are not considered for or included in setting rates for the utility.
The Texas Commission is expected to use the actual tax approach for calculating the recovery of federal income tax in the pending rate cases for CPL and WTU. The impact of the actual tax approach on the prospective rates for CPL and WTU cannot be determined since the application of the concept is unsettled.
CSW believes that the recovery of federal income taxes in rates should be determined on the stand-alone approach for ratemaking purposes, but there is no assurance this approach will be adopted in the pending CPL or WTU rate cases or the pending El Paso rate and Merger cases.
Environmental Matters CERCLA and Related Matters The operations of the CSW System, like those of other utility systems, generally involve the use and disposal of substances subject to environmental laws. The CERCLA, the federal "Superfund" law, addresses the cleanup of sites contaminated by hazardous substances. Superfund requires that PRPs fund remedial actions regardless of fault or the legality of past disposal activities. PRPs include owners and operators of contaminated sites and transporters and/or generators of hazardous substances. Many states have similar laws. Theoretically, any one PRP can be held responsible for the entire cost of a cleanup. Typically, however, cleanup costs are allocated among PRPs.
The Electric Operating Companies are subject to various pending claims alleging that they are PRPs under federal or state remedial laws for investigating and cleaning up contaminated property. CSW anticipates that resolution of these claims, individually or in the aggregate, will not have a material adverse effect on CSW's consolidated results of operations or financial condition. Although the reasons for this expectation differ from site to site, factors that are the basis for the expectation for specific sites include the volume and/or type of waste allegedly contributed by the Electric Operating Company, the estimated amount of costs allocated to the Electric Operating Company and the participation of other parties.
2-19 MGPs Contaminated former MGPs are a type of site which utilities, and others, may have to remediate in the future under Superfund or other federal or state remedial programs. Gas was manufactured at MGPs from the mid-1800s to the mid-1900s. In some cases, utilities and others have faced potential liability for MGPs because they, or their alleged predecessors, owned or operated the plants. In other cases, utilities or others may have been subjected to such liability for MGPs because they acquired MGP sites after gas production ceased.
Suspected MGP Site in Marshall, Texas SWEPCO owns a suspected former MGP site in Marshall, Texas. SWEPCO has notified the TNRCC that evidence of contamination has been found at the site. As a result of sampling conducted at the end of 1993 and early 1994, SWEPCO is evaluating the extent, if any, to which contamination has impacted soil, groundwater and other conditions in the area. A final range of clean-up costs has not yet been determined, but, based on a preliminary estimate, SWEPCO has accrued approximately $2 million as a liability for this site on SWEPCO's books as of December 31, 1993. As more information is obtained about the site, and SWEPCO discusses the site with the TNRCC, the preliminary estimate may change.
Suspected MGP Site in Texarkana, Texas and Arkansas and Shreveport, Louisiana SWEPCO also owns a suspected former MGP site in Texarkana, Texas and Arkansas. The EPA ordered an initial investigation of this site, as well as one in Shreveport, Louisiana, which is no longer owned by SWEPCO. The contractor who performed the investigations of these two sites recommended to the EPA that no further action be taken at this time.
Biloxi, Mississippi MGP Site SWEPCO has been notified by Mississippi Power Company that it may be a PRP at the former Biloxi MGP site formerly owned and operated by a predecessor of SWEPCO. SWEPCO is working with Mississippi Power Company to investigate the extent of contamination at this site. The MDEQ approved a site investigation work plan and, in January 1995, SWEPCO and Mississippi Power Company initiated sampling pursuant to that work plan. On an interim basis, SWEPCO and Mississippi Power Company are each paying fifty percent of the cost of implementing the site investigation work plan. That interim allocation is subject to a final allocation in the future. SWEPCO and Mississippi Power Company are investigating whether there are other PRPs at the Biloxi site. Until the extent of the contamination at the Biloxi site is identified, it is unknown what, if any, additional investigation or cleanup may be required.
Management does not expect these matters to have a material effect on CSW's consolidated results of operations or financial condition.
Clean Air Act Amendments In November 1990, the United States Congress passed the Clean Air Act which places restrictions on the emission of sulfur dioxide from gas-, coal- and lignite-fired generating plants. Beginning in the year 2000, the Electric Operating Companies will be required to hold allowances in order to emit sulfur dioxide. EPA issues allowances to owners of existing generating units based on historical operating conditions. Based on the CSW System facilities plan, CSW believes that the Electric Operating Companies' allowances will be adequate to meet their needs at least through 2008. Public and private markets are developing for trading of excess allowances. CSW presently has no intention of engaging in trading of allowances, but may seek to do so in the future if market conditions warrant and appropriate regulatory approvals are obtained.
The Clean Air Act also establishes a federal operating source permit program to be administered by the states. CSW estimates that it and the Electric Operating Companies will incur approximately $500,000 to prepare permit applications for the program.
2-20 The Clean Air Act also directs the EPA to issue regulations governing nitrogen oxide emissions and requires government studies to determine what controls, if any, should be imposed on utilities to control air toxics emissions. The impact that the nitrogen oxide emission regulations and the air toxics study will have on CSW cannot be determined at this time.
As a result of requirements imposed by the Clean Air Act, CSW expects to spend an additional $4 million for annual testing of, software modifications to, and maintenance of continuous emission monitoring equipment from 1995 through 1997.
EMFs Research is ongoing whether exposure to EMFs may result in adverse health effects or damage to the environment. Although a few of the studies to date have suggested certain associations between EMFs and some types of adverse health effects, the research to date has not established a cause-and-effect relationship between EMFs and adverse health effects. CSW cannot predict the impact on the CSW System or the electric utility industry if further investigations or proceedings were to establish that the present electricity delivery system is contributing to increased risk or incidence of health problems.
See NOTE 10, Litigation and Regulatory Proceedings, for additional discussion of environmental issues.
Non-Utility Initiatives As indicated above, one component of CSW's four-part strategy to meet the increasing competition and fundamental changes in the electric utility industry is to expand CSW's non-utility business. CSW continues to consider new business opportunities to expand its energy related business. CSW's principal non-utility businesses are Transok and CSWE. As discussed below, CSW recently formed CSWI to seek opportunities internationally for investment in non-utility generation. CSW Communications was formed to provide a communications network for the CSW System as well as third parties. While CSW believes that non-utility initiatives are necessary to maintain its competitiveness and to grow in the future, there can be no assurance as to the level of success that will be attained in these initiatives.
Transok Transok is an intrastate natural gas gathering, transmission, marketing and processing company that provides natural gas services to CSW System companies, predominately PSO, and to non-affiliated gas customers throughout the United States. Transok's natural gas facilities are located in Oklahoma, Louisiana and Texas. It operates gas processing plants and markets natural gas liquids produced from those plants to various markets.
CSWE CSWE, a wholly-owned subsidiary of CSW, is authorized to develop various independent power and cogeneration facilities and to own and operate such non-utility projects, subject to further regulatory approvals. CSWE has an approximate 50% interest in the Brush, Ft. Lupton and Mulberry facilities which achieved commercial operation in 1994.
Brush The 68 MW Brush project, located in Brush, Colorado, achieved commercial operation in January 1994, and provides steam and hot water to a 15-acre greenhouse and sells electricity to Public Service Company of Colorado.
Ft. Lupton The Ft. Lupton project, located in Colorado, provides steam and hot water to a 20-acre greenhouse and also sells electricity to Public Service Company of Colorado. Phase I of the Ft. Lupton project, representing 122 MWs, achieved commercial operation in June 1994. Phase II of the project commenced operations in July 1994 bringing total on-line capacity of the project to 272 MWs.
2-21 Mulberry The Mulberry facility, a 117 MW gas-fired cogeneration plant in Polk County, Florida achieved commercial operation in August 1994 and provides steam to a combined distilled water and ethanol facility and sells electricity to Florida Power Corporation and Tampa Electric Company.
Orange Cogen The Orange Cogen facility, in which CSWE holds a 50% interest, is expected to commence operation in June 1995. The 103 MW, gas-fired plant in Florida will provide thermal energy to an orange juice processor and will sell electricity to Florida Power Corporation and Tampa Electric Company. CSWE's O&M division plans to operate the plant.
Other Projects In addition to these projects, CSWE has 19 other projects totaling more than 5,000 MW in various stages of development, mostly in affiliation with other developers. CSWE can provide no assurances that these projects, which are subject to further negotiations and regulatory approvals, will be commenced or completed and, if they are completed, that they will provide the anticipated return on investment.
CSWI In November 1994, CSWI, a wholly-owned subsidiary of CSW, was formed to engage in international activities including developing, acquiring, financing and owning the securities of exempt wholesale generators and foreign utility companies.
In 1994, CSWI continued with the Mexico initiative that began in 1992. CSWI's goal is to participate in providing Mexico's future electricity needs. The geographical location of the CSW System offers opportunities to provide bulk power sales to Mexico. The Mexico City office of CSW, opened in 1993, allows CSWI greater access to key Mexican markets, permitting CSWI to more readily evaluate opportunities as they become available. However, the recent devaluation of the Mexican peso will slow previously projected power demand for the near-term.
CSW Communications In July 1994, CSW Communications, a wholly-owned subsidiary, of CSW, was formed to provide communication services to the CSW System and non-affiliates. One important goal of CSW Communications is to enhance services to CSW System customers through fiber optics and other telecommunications technologies. CSW Communications will consolidate the future design, construction, maintenance and ownership of the CSW System's telecommunications networks. In 1994, CSW announced a $9 million project in Laredo, Texas, to install fiber optic lines and coaxial cable to CPL residential customers who have volunteered to take part in this pilot program. This project involving CSW Communications and CPL will demonstrate the energy efficiency and cost savings that result from giving customers greater choice and control over their electric service. These energy- efficiency services will use only a portion of the capacity of the telecommunications lines CSW Communications is installing. In the future, CSW Communications may, subject to any required regulatory approvals, seek to lease the remaining capacity for other services including possibly telephone service, cable television and home security systems.
Results of Operations
Overview Of Results CSW's earnings increased to $394 million or $2.08 per share in 1994 as compared to $308 million or $1.63 per share in 1993 and $382 million or $2.03 per share in 1992. The return on average common stock equity was 13.4% in 1994 compared to 10.6% in 1993 and 13.5% in 1992. Electric operations contributed approximately 100% of total earnings in 1994 and 1993, and 95% in 1992. In 1994, earnings at Transok, CSWE, and CSW Credit totaling $34 million, were offset by corporate expenditures including merger and acquisition activities and the formation of two new subsidiaries.
2-22 Earnings increased in 1994 compared to 1993 due primarily to higher KWH sales and natural gas operations and decreased costs associated with the end of the outage at STP. In addition, CSWE, which had three projects become operational during 1994, contributed $2 million to earnings. These items were partially offset by increased interest and depreciation and amortization expense. Earnings in 1993 were significantly affected by several items described below:
(millions,after-tax) Restructuring charges $(63) Recognition of unbilled revenues 49 Early adoption of SFAS No. 112 (9) Adoption of SFAS No. 109 6 Establishment of reserves for fuel and other properties (11) Prior year tax adjustments (18)
In addition to the aforementioned items, earnings in 1993 were below 1992 levels due to additional costs primarily associated with the outage at STP, higher benefit costs as a result of the adoption of SFAS No. 106, higher taxes other than income as a result of school funding tax increases in Texas, and the increase in the federal income tax rate from 34% to 35%. These items were partially offset by higher KWH sales in 1993 due primarily to more normal weather than was experienced in 1992.
Operating Revenues Revenues decreased 2% in 1994, after increasing 12% in 1993 and 8% in 1992 from the previous years due to the following items:
Revenue Increase (Decrease) From Prior Year 1994 1993 1992 (millions) Base rate changes $ 7 $ 8 $ -- Fuel costs (49) 168 -- KWH sales 61 93 (25) Natural gas (85) 107 255 Other electric and 2 22 12 diversified $(64) $398 $242
Electric Revenues Electric revenues increased $10 million in 1994 compared to 1993. Total KWH sales increased approximately 6%, with increases in sales among all customer classes. During 1994, the average number of customers increased approximately 2%. In addition to customer growth, there was slightly more favorable weather during 1994 as compared to 1993. However, offsetting much of the increases in revenue due to KWH sales, fuel revenues were down substantially during 1994 compared to 1993. Fuel costs incurred in the generation of electricity are typically passed through to the customers, so decreases in fuel costs will cause a corresponding decrease in fuel revenues. Fuel costs, which decreased during 1994, are more fully discussed below under Fuel and Purchased Power. Fuel revenues increased in 1993 compared to 1992 due to higher per unit costs of fuel and purchased power.
2-23 Base rates increased slightly at PSO because of changes in retail customers' rates, and decreased due to a 3.2% interim rate reduction at WTU implemented during the fourth quarter of 1994. Because PSO's increased base rates, finalized in December 1993, were not significantly higher than the interim rates that had been in effect throughout the year, base rates had little overall change from 1993. As part of a stipulated agreement reflecting its rate increase, PSO agreed that it will not file for an increase in base rates until after June 30, 1995. During late 1993 and early 1994, several parties initiated actions, which, if approved, would lower CPL's base rates. The review of CPL's rates arose out of the unscheduled outage at STP as discussed above under the heading Rates and Regulatory Matters, CPL Rate Inquiry.
For additional information on these proceedings and others, see NOTE 10, Litigation and Regulatory Proceedings.
The percentage changes in KWH sales for the three years were as follows:
KWH Sales Increase (Decrease) From Prior Year 1994 1993 1992 Residential 2.9% 9.0% (4.2)% Commercial 3.8 4.8 (1.1) Industrial 3.6 5.5 3.1 Sales for resale 21.9 (6.6) 5.4 Total sales 5.5 4.9 0.1
KWH sales to retail customers increased in 1994 and 1993 as a result of more favorable weather and increased residential customers. In addition, KWH sales grew in all of the other customer classes. SWEPCO acquired BREMCO in July 1993, and accordingly, there were twelve months of KWH sales to these customers in 1994 compared to only six months in 1993. Weather was more favorable in 1994 than in 1993, while extremely mild weather was experienced in 1992. The continued increases in industrial sales over the last three years reflect the increased marketing efforts by the Electric Operating Companies and the continued improvement in the economy throughout their service areas. Sales for resale increased in 1994 because STP was operational for most of the year, whereas in 1993, plants in the CSW System were producing power to replace the power normally produced at STP.
The Electric Operating Companies have maintained competitive rates in an increasingly competitive marketplace. Efforts have increased at each of the Electric Operating Companies to attract new customers while efficiently serving all customers. Economic conditions in the service areas of the Electric Operating Companies are expected to continue to improve in 1995.
Natural Gas Revenues Revenues from natural gas decreased 14% in 1994 due primarily to a decrease in the price of gas, even though total natural gas volumes increased 4% from 1994 to 1993. However, lower gas sales prices were mitigated by lower gas purchase prices, which are described below under Gas Purchased for Resale. The lower gas sales revenues were partially offset by both increased gathering and transportation revenues and increased natural gas liquids processing revenues. Gathering and transportation sales volumes increased 12% primarily as a result of a pipeline extension completed during 1994, and gas liquids processing volumes increased 12% during 1994. Revenues from natural gas increased 22% in 1993 from 1992 due primarily to an increase in sales volumes and to a lesser extent an increase in sales prices. A portion of this increase is attributable to the acquisition of the NGC Anadarko Gathering System in 1993. Revenue increases in 1993 from natural gas liquids are due to increased sales volumes combined with slightly higher prices.
2-24 Other Diversified Revenues Other diversified revenues increased 38% from 1994 as compared to 1993 due to the reclassification of CSWE's operating revenues more fully discussed below under Other Income and Deductions. Other diversified revenues increased substantially in 1993 as compared to 1992 because CSW Credit began factoring the receivables of a significant non-affiliated utility in January 1993.
Fuel and Purchased Power Expense During 1994, the Electric Operating Companies generated approximately 95% of their electric energy requirements. During 1993 and 1992, they generated 92% and 94%, respectively. Total fuel and purchased power expenses decreased 4% during 1994 due to a decrease in fossil fuel costs and increased usage of lower cost nuclear fuel. The average unit cost of fuel was $1.82 during 1994, compared to $2.11 and $1.92 for 1993 and 1992, respectively. Several contracts with major fuel suppliers and carriers have been recently renegotiated. These settlements have contributed to the lower cost of fuel. In addition, because STP restarted and Units 1 and 2 reached 100% capacity in April and June of 1994, respectively, lower cost nuclear fuel was utilized, whereas the 1993 outage required higher cost energy purchases to replace STP's nuclear power. The increase in fuel and purchased power expense in 1993 compared to 1992 is attributable to higher natural gas costs as well as the cost of STP replacement power.
Gas Purchased for Resale/Gas Extraction and Marketing Gas purchased for resale decreased 30% in 1994 from 1993, while it increased 29% in 1993 from 1992. Lower gas prices caused the decrease in 1994, including a significant portion attributable to sales made on natural gas drawn from storage. Increased natural gas prices and increased pipeline capacity from Transok's recent acquisitions caused the 1993 increase. Gas extraction and marketing expenses increased 14% in 1994 from 1993 and 19% in 1993 from 1992 due to higher input costs associated with higher natural gas liquids processing volumes.
Other Operating and Maintenance Expenses and Taxes Other operating and maintenance expenses decreased 8% in 1994 compared to 1993, due primarily to the absence of expenses that were incurred during the 1993 STP outages. In 1993, in addition to $29 million in maintenance costs associated with the STP outage, operating expenses increased compared to 1992 due to expenses associated with the adoption of SFAS 106, reserves taken on lignite and other property, corporate expenditures, and other administrative and general expenses. Federal income taxes were higher in 1994 than 1993 due to higher pre-tax income. Federal income taxes were lower in 1993 than 1992 due to lower pre-tax income offset in part by tax adjustments and the increase in the corporate tax rate from 34% to 35%, which was effective retroactive to January 1, 1993. Taxes other than federal income remained comparable in 1994 from 1993, while they increased in 1993 compared to 1992 due to school funding tax increases in Texas.
Restructuring Charges In 1994, the original restructuring accrual of $97 million that had been recorded in 1993 was reduced by $9 million. Accordingly, the final costs associated with the CSW System's restructuring totaled $88 million over the two year period. For additional information on CSW's restructuring, see Restructuring, above.
Depreciation and Amortization Depreciation and amortization expense increased in 1994 compared to 1993 and also 1993 compared to 1992 as a result of increases in depreciable plant.
Inflation Annual inflation rates, as measured by the national Consumer Price Index, have averaged about 2.7% during the three years ended December 31, 1994. Management believes that inflation, at these levels, does not materially affect CSW's consolidated results of operations or financial position. However, under existing regulatory practice, only the historical cost of plant is recoverable from
2-25 customers. As a result, cash flows designed to provide recovery of historical plant costs may not be adequate to replace plant in future years.
Other Income and Deductions Other income and deductions increased $18 million or 19% in 1994 compared to 1993, as a result of the reclassification of CSWE's operating activities offset partially by decreased Mirror CWIP liability amortization and the absence of adjustments recorded in 1993 associated with Transok's 1991 acquisition of TEX/CON. Prior to 1994, CSWE was in the developmental stage of its business, so its operating activities were classified in CSW's Other Income and Deductions. However, in conjunction with the completion of three projects in 1994, CSWE's revenues and expenses were classified as operating activities in CSW's Other Diversified Revenues and Other Operating Expenses. Both of these components had negative earnings impacts classified in Other Income and Deductions in 1993. Other Income and Deductions increased $11 million or 13% in 1993 from 1992 due in part to Transok's aforementioned TEX/CON acquisition adjustments and slightly higher Allowance for Equity Funds Used During Construction partially offset by decreased Mirror CWIP liability amortization.
Interest Expense Interest expense on long-term debt in 1994 was comparable to 1993, whereas 1993 interest expense was substantially lower than 1992 due to long-term debt refinancings, which lowered CSW's embedded cost of long-term debt from 8.3% in 1992 to 7.8% in 1993. CSW's embedded cost of long-term debt decreased slightly to 7.7% in 1994. Short-term interest expense increased in 1994 due primarily to higher short-term interest rates combined with higher general corporate borrowings, and in 1993 because of increased borrowings attributable to the expansion of CSW Credit's business, interim financing of CSWE's projects, and various corporate initiatives.
Cumulative Effect of Changes in Accounting Principles In 1993, CSW implemented SFAS No. 112, SFAS No. 109, and changed the method of accounting for unbilled revenues. These changes had a cumulative effect of increasing net income approximately $46 million.
2-26 Consolidated Statements of Income Central and South West Corporation For the Years Ended December 31, 1994 1993 1992 Operating Revenues (millions, except per share amounts) Electric Residential $1,156 $1,160 $1,046 Commercial 836 832 773 Industrial 733 736 659 Sales for resale 204 179 177 Other 136 148 135 Total Electric 3,065 3,055 2,790 Gas 518 603 496 Other diversified 40 29 3 3,623 3,687 3,289 Operating Expenses and Taxes Fuel and purchased power 1,161 1,209 1,035 Gas purchased for resale 276 396 306 Gas extraction and marketing 98 86 72 Other operating 596 593 490 Restructuring charges (9) 97 -- Maintenance 176 197 170 Depreciation and amortization 356 330 311 Taxes, other than federal income 196 197 175 Federal income taxes 179 125 142 3,029 3,230 2,701 Operating Income 594 457 588
Other Income and Deductions Mirror CWIP liability amortization 68 76 83 Other 43 17 (1) 111 93 82 Income Before Interest Charges 705 550 670
Interest Charges Interest on long-term debt 218 219 230 Interest on short-term debt and other 75 50 36 293 269 266 Income Before Cumulative Effect of Changes in Accounting Principles 412 281 404
Cumulative Effect of Changes in -- 46 -- Accounting Principles
Net Income 412 327 404 Preferred stock dividends 18 19 22 Net Income for Common Stock $394 $308 $382
Average Common Shares Outstanding 189.3 188.4 188.3 Earnings per Share of Common Stock before Cumulative Effect of Changes in Accounting Principles $ 2.08 $ 1.39 $ 2.03 Cumulative Effect of Changes in Accounting Principles -- .24 -- Earnings per Share of Common Stock $ 2.08 $ 1.63 $ 2.03 Dividends Paid per Share of Common Stock $ 1.70 $ 1.62 $ 1.54
The accompanying notes to consolidated financial statements are an integral part of these statements.
Consolidated Statements of Retained Earnings Central and South West Corporation For the Years Ended December 31, 1994 1993 1992 (millions)
Retained Earnings at Beginning of Year $1,753 $1,751 $1,659 Net income for common stock 394 308 382 Deduct: Common stock dividends 323 306 290 Retained Earnings at End of Year $1,824 $1,753 $1,751
The accompanying notes to consolidated financial statements are an integral part of these statements.
2-28 Consolidated Balance Sheets Central and South West Corporation As of December 31, 1994 1993 (millions) ASSETS Plant Electric utility Production $ 5,802 $ 5,775 Transmission 1,377 1,228 Distribution 2,539 2,362 General 764 709 Construction work in progress 412 361 Nuclear fuel 161 160 Total Electric 11,055 10,595 Gas 798 738 Other diversified 15 10 11,868 11,343 Less - Accumulated depreciation 3,870 3,550 7,998 7,793 Current Assets Cash and temporary cash investments 27 62 Special deposits -- 2 Accounts receivable 761 801 Materials and supplies, at average cost 162 149 Electric utility fuel inventory, substantially at average cost 118 102 Gas inventory/products for resale 23 24 Unrecovered fuel costs 54 70 Prepayments and other 44 44 1,189 1,254 Deferred Charges and Other Assets Deferred plant costs 516 518 Mirror CWIP asset 322 332 Other non-utility investments 394 266 Income tax related regulatory assets, net 216 182 Other 274 259 1,722 1,557 $10,909 $10,604
The accompanying notes to consolidated financial statements are an integral part of these statements.
2-29 Consolidated Balance Sheets Central and South West Corporation As of December 31, 1994 1993 (millions) CAPITALIZATION AND LIABILITIES Capitalization Common stock: $3.50 par value Authorized: 350 million shares Issued and outstanding: 190.6 million shares in 1994 and 188.4 million shares in 1993 $ 667 $ 659 Paid-in capital 561 518 Retained earnings 1,824 1,753 Total Common Stock Equity 3,052 2,930 Preferred stock Not subject to mandatory redemption 292 292 Subject to mandatory redemption 35 58 Long-term debt 2,940 2,749 Total Capitalization 6,319 6,029 Current Liabilities Long-term debt and preferred stock due within twelve months 7 26 Short-term debt 910 769 Short-term debt - CSW Credit 573 641 Accounts payable 286 313 Accrued taxes 111 90 Accrued interest 61 55 Accrued restructuring charges 4 97 Other 155 152 2,107 2,143 Deferred Credits Income taxes 2,048 1,935 Investment tax credits 320 335 Mirror CWIP liability and other 115 162 2,483 2,432 $10,909 $10,604
The accompanying notes to consolidated financial statements are an integral part of these statements.
2-30 Consolidated Statements of Cash Flows Central and South West Corporation For the Years Ended December 31, 1994 1993 1992 (millions) OPERATING ACTIVITIES Net Income $ 412 $ 327 $ 404 Non-cash Items Included in Net Income Depreciation and amortization 402 366 351 Deferred income taxes and investment tax credits 87 94 71 Mirror CWIP liability amortization (68) (76) (83) Restructuring charges (9) 97 -- Cumulative effect of changes in accounting principles -- (46) -- Changes in Assets and Liabilities Accounts receivable 29 (52) (52) Unrecovered fuel costs 16 (63) (4) Accounts payable (27) 34 53 Accrued taxes 21 37 (41) Accrued restructuring charges (57) -- -- Other (42) (24) (13) 764 694 686 INVESTING ACTIVITIES Capital expenditures (578) (508) (422) Acquisitions (21) (106) (27) Non-affiliated accounts receivable collections (purchases), net 11 (314) 11 CSW Energy projects (includes $73, $19 and $8 of equity investments for 1994, 1993 and 1992, respectively) (115) (127) (37) Other (14) (14) (8) (717) (1,069) (483) FINANCING ACTIVITIES Common stock sold 50 1 2 Proceeds from issuance of long-term debt 199 904 1,009 Retirement of long-term debt (4) (50) (4) Reacquisition of long-term debt (27) (987) (652) Special deposits for reacquisition of long-term debt -- 199 (199) Redemption of preferred stock (33) (17) (13) Change in short-term debt 73 602 17 Payment of dividends (340) (325) (312) (82) 327 (152)
Net Change in Cash and Cash Equivalents (35) (48) 51 Cash and Cash Equivalents at Beginning of Year 62 110 59 Cash and Cash Equivalents at End of Year $ 27 $ 62 $ 110
SUPPLEMENTARY INFORMATION Interest paid less amounts capitalized $ 280 $ 260 $ 268 Income taxes paid $ 93 $ 53 $ 108
The accompanying notes to consolidated financial statements integral part of these statements.
2-31 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.Summary of Significant Accounting Policies Public Utility Regulation CSW is subject to regulation by the SEC as a registered holding company under the Holding Company Act. CSW's Operating Companies are also regulated by the SEC under the Holding Company Act. CSW's four Electric Operating Companies, Central Power and Light Company, Public Service Company of Oklahoma, Southwestern Electric Power Company, and West Texas Utilities Company, are subject to regulation by the FERC under the Federal Power Act and follow the Uniform System of Accounts prescribed by the FERC. The Operating Companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.
CSW Credit CSW Credit, as a wholly-owned subsidiary of CSW, purchases, without recourse, the billed and unbilled accounts receivable of the Operating Companies and certain non-affiliated companies.
The more significant accounting policies of CSW and its subsidiaries are summarized below:
Principles of Consolidation The consolidated financial statements include the accounts of CSW and its subsidiary companies. All significant intercompany items and transactions have been eliminated.
Plant Electric utility plant is stated at the original cost of construction, which includes the cost of contracted services, direct labor, materials, overhead items and allowances for borrowed and equity funds used during construction. Transok's gas plant acquisitions are stated at fair market value based on the purchase price while other gas plant is stated at original cost of construction, which includes the cost of contracted services, direct labor, materials, overhead items and capitalized interest.
Depreciation Provisions for depreciation of plant are computed using the straight-line method, generally at individual rates applied to the various classes of depreciable property. The annual average consolidated composite rate was 3.2% for 1994, 1993 and 1992.
Nuclear Decommissioning At the end of STP's service life, decommissioning is expected to be accomplished using the decontamination method, which is one of the techniques acceptable to the NRC. Using this method, the decontamination activities occur as soon as possible after the end of plant operations. Contaminated equipment is cleaned or removed to a permanent disposal location and the site is generally returned to its pre-plant state.
CPL's decommissioning costs are accrued and funded to an external trust over the expected service life of the STP units. The existing NRC operating licenses will allow the operation of STP Unit 1 until 2027, and Unit 2 until 2028. The accrual is an annual level cost based on the estimated future cost to decommission STP, including escalations for expected inflation to the expected time of decommissioning, and is net of expected earnings on the trust fund.
CPL's portion of the costs of decommissioning STP were estimated to be $85 million in 1986 dollars based on a site specific study completed in 1986. CPL is recovering these decommissioning costs through rates based on the service life of STP at a rate of $4.2 million per year. The $4.2 million annual cost of decommissioning is reflected on the income statement in other operating expense. Decommissioning costs are paid to an irrevocable external trust
2-32 and as such are not reflected on CPL's balance sheet. At December 31, 1994, the trust balance was $19.3 million.
In May 1994, CPL received a new decommissioning study updating the cost estimates to decommission STP that indicated that CPL's share of such costs would increase from $85 million, as stated in 1986 dollars, to $251 million, as stated in 1994 dollars. The increase in costs occurred primarily as a result of extended on-site storage of high level waste, much higher estimates of low-level waste disposal costs and increased labor costs since the prior study. These costs are expected to be incurred during the years 2027 through 2062. While this is the best estimate available at this time, these costs may change between now and when the funds are actually expended because of changes in the assumptions used to derive the estimates, including the prices of the goods and services required to accomplish the decommissioning. Additional studies will be completed periodically to update this information.
Based on this projected cost to decommission STP, CPL estimates that its annual funding level should increase to $10.0 million. CPL has requested this amount as part of its cost of service in its current rate filing. Other parties to the rate proceeding have filed their projections of the annual amount, which have ranged from $4.5 million to $8.1 million. CPL expects to fund at the level ultimately ordered by the Texas Commission although CPL cannot predict what that level will be. Historically, the Texas Commission has allowed full recovery of nuclear decommissioning costs. For further information on CPL's current rate filing, see NOTE 10, Litigation and Regulatory Proceedings - Texas Commission Proceedings, below.
Electric Revenues and Fuel Prior to January 1, 1993, electric revenues were recorded at the time billings were made to customers on a cycle-billing basis. Electric service provided subsequent to billing dates through the end of each calendar month became part of operating revenues of the next month. To conform to general industry standards, the Electric Operating Companies changed their method of accounting to accrue for estimated unbilled revenues. The effect of this change on 1993 net income was pre-tax increase of $75 million, and an after-tax increase of $49 million, included in cumulative effect of changes in accounting principles.
CPL, SWEPCO and WTU recover fuel costs in Texas as a fixed component of base rates whereby over-recoveries of fuel are payable to customers and under-recoveries may be billed to customers after Texas Commission approval. The cost of fuel is charged to expense as consumed. See NOTE 10, Litigation and Regulatory Proceedings, for further information about fuel recovery.
PSO recovers fuel costs in Oklahoma and SWEPCO recovers fuel costs in Arkansas and Louisiana through automatic fuel recovery mechanisms. The application of these mechanisms varies by jurisdiction.
Each of the Electric Operating Companies recovers fuel costs applicable to wholesale customers, which are regulated by the FERC, through an automatic fuel adjustment clause.
CPL amortizes the costs of nuclear fuel to fuel expense based on a ratio of the estimated Btu's used and available to generate electric energy, and includes a provision for the disposal of spent nuclear fuel.
Accounts Receivable Each of the Operating Companies sells its billed and unbilled accounts receivable, without recourse, to CSW Credit.
Regulatory Assets and Liabilities For their regulated activities, each of the Electric Operating Companies follows SFAS No. 71 which defines the criteria for establishing regulatory assets and regulatory liabilities. Regulatory assets represent probable future revenue to the company associated with certain costs which will be recovered from customers through the ratemaking process. Regulatory liabilities
2-33 represent probable future refunds to customers. At December 31, 1994 and 1993, the CSW System had recorded the following significant regulatory assets and liabilities:
1994 1993 (millions) Regulatory Assets Deferred plant costs $516 $518 Mirror CWIP asset 322 332 Income tax related regulatory assets, net 216 182 Unrecovered fuel costs 54 70 Other 33 34
Regulatory Liabilities Mirror CWIP liability 41 109
Deferred Plant Costs In accordance with orders of the Texas Commission, WTU and CPL deferred operating, depreciation and tax costs incurred for Oklaunion Power Station Unit 1 and STP, respectively. These deferrals were for the period beginning on the date when the plants began commercial operation until the date the plants were included in rate base. The deferred costs are being amortized and recovered through rates over the lives of the respective plants. See NOTE 10, Litigation and Regulatory Proceedings, for further discussion of WTU's and CPL's deferred accounting proceedings.
Mirror CWIP In accordance with Texas Commission orders, CPL previously recorded a Mirror CWIP asset, which is being amortized over the life of STP. For more information regarding Mirror CWIP, reference is made to NOTE 10, Litigation and Regulatory Proceedings. Statements of Cash Flows Cash equivalents are considered to be highly liquid debt instruments purchased with a maturity of three months or less. Accordingly, temporary cash investments are considered cash equivalents.
Reclassification Certain financial statement items for prior years have been reclassified to conform to the 1994 presentation.
Accounting Changes Effective January 1, 1993, the CSW System adopted SFAS No. 106, SFAS No. 112 and SFAS No. 109. See NOTE 2, Federal Income Taxes, for further information regarding SFAS No. 109. In addition, the Electric Operating Companies also changed their method of accounting for unbilled revenues. See Electric Revenues and Fuel above for further information.
The adoption of SFAS No. 106 resulted in an increase in 1993 operating expenses of $16 million. The adoption of SFAS No. 109, SFAS No. 112 and the change in accounting for unbilled revenues are presented as a cumulative effect of changes in accounting principles as shown below:
2-34 Pre-Tax Tax Net Income EPS CSW Effect Effect Effect Effect (millions, except EPS) SFAS No. 109 $ -- $ 6 $ 6 $0.03 SFAS No. 112 (13) 4 (9) (0.05) Unbilled revenues 75 (26) 49 0.26 Total $62 $(16) $46 $0.24
Pro forma amounts, assuming that the change in accounting for unbilled revenues had been adopted retroactively, are not materially different from amounts previously reported for prior years.
2.Federal Income Taxes The CSW System adopted the provisions of SFAS No. 109 effective January 1, 1993. The net effect on CSW's earnings was a one-time adjustment to increase net income by $6 million or $0.03 per share. This adjustment was recorded as a cumulative effect of change in accounting principle. The benefit was attributable to the reduction in deferred taxes associated with CSW's non-utility operations previously recorded at rates higher than current rates.
For utility operations, there were no material effects of SFAS No. 109 on CSW's earnings. As a result of this change, CSW recognized additional accumulated deferred income taxes from its utility operations and corresponding regulatory assets and liabilities to ratepayers in amounts equal to future revenues or the reduction in future revenues required when the income tax temporary differences reverse and are recovered or settled in rates. As a result of a favorable earnings history, the CSW System did not record any valuation allowance against deferred tax assets at December 31, 1994 and 1993.
CSW files a consolidated federal income tax return and participates in a tax sharing agreement with its subsidiaries. The components of income taxes follow:
1994 1993 1992 Included in Operating Expenses and Taxes (millions) Current $ 88 $ 28 $ 64 Deferred 105 112 95 Deferred ITC (14) (15) (17) 179 125 142 Included in Other Income and Deductions Current (14) (3) (7) Deferred (4) (5) 7 (18) (8) --
Tax effects of cumulative effect of changes in Accounting Principles -- 14 -- -- 14 -- $161 $131 $142
2-35 Investment tax credits deferred in prior years are included in income over the lives of the related properties. Total income taxes differ from the amounts computed by applying the statutory income tax rates to income before taxes. The reasons for the differences follow:
1994 % 1993 % 1992 % (dollars in millions) Tax at statutory rates $201 35 $160 35 $186 34 Differences Amortization of ITC (14) (2) (15) (3) (15) (3) Mirror CWIP (20) (4) (23) (5) (25) (4) Prior period adjustments -- -- 18 4 (10) (2) Cumulative effect of change in method of accounting for income taxes Other -- -- (8) (2) -- -- (6) (1) (1) -- 6 1 $161 28 $131 29 $142 26
The significant components of the net deferred income tax liability follow: December 31, December 31, 1994 1993 (millions) Deferred Income Tax Liabilities Depreciable utility plant $ 1,683 $ 1,589 Deferred plant costs 181 181 Mirror CWIP asset 113 116 Income tax related regulatory assets 229 239 Other 262 234 Total Deferred Income Tax Liabilities 2,468 2,359
Deferred Income Tax Assets Income tax related regulatory liability (155) (177) Unamortized ITC (115) (120) Alternative minimum tax carryforward (96) (68) Other (56) (65) Total Deferred Income Tax Assets (422) (430) Net Accumulated Deferred Income Taxes - Total $ 2,046 $ 1,929
Net Accumulated Deferred Income Taxes - Noncurrent $ 2,048 $ 1,935 Net Accumulated Deferred Income Taxes - Current (2) (6) Net Accumulated Deferred Income Taxes - Total $ 2,046 $ 1,929
2-36 3.Long-Term Debt The long-term debt of the Operating Companies outstanding as of the end of the last two years follow: Maturities Interest Rates December 31, From To From To 1994 1993 (millions) First mortgage bonds 1995 1999 5.25% 7.50% $443 $343 2000 2004 5.25% 7.75% 836 796 2005 2009 6.20% 7.75% 247 248 2010 2014 7.50% 7.50% 112 112 2015 2019 9.125% 9.75% 226 240 2020 2024 7.25% 7.50% 295 295 2025 2029 6.875% 6.875% 80 80
Pollution control bonds 2000 2004 6.90% 7.125% 21 21 2005 2009 5.90% 6.00% 83 83 2010 2014 7.875% 10.125% 231 231 2015 2019 7.60% 7.875% 114 114 2025 2029 6.00% 6.00% 120 120
Notes and lease obligations 1996 2023 6.25% 9.75% 328 273 Unamortized discount (21) (22) Unamortized cost of reacquired debt (175) (185) $2,940 $2,749
The mortgage indentures, as amended and supplemented, securing first mortgage bonds issued by the Electric Operating Companies, constitute a direct first mortgage lien on substantially all electric utility plant.
The Operating Companies may offer additional first mortgage bonds and medium-term notes subject to market conditions and other factors.
Annual Requirements Certain series of outstanding first mortgage bonds have annual sinking fund requirements, which are generally 1% of the amount of each such series issued. These requirements may be, and generally have been, satisfied by the application of net expenditures for bondable property in an amount equal to 166-2/3% of the annual requirements. Certain series of pollution control bonds also have sinking fund requirements. At December 31, 1994, the annual sinking fund requirements and annual maturities for first mortgage bonds and pollution control bonds for the next five years follow:
Sinking Fund Requirements Maturities (millions) 1995 $ 4 $ 9 1996 4 33 1997 4 207 1998 4 34 1999 4 98
2-37 Dividends The subsidiary companies' mortgage indentures, as amended and supplemented, contain certain restrictions on the use of their retained earnings for cash dividends on their common stock. These restrictions do not limit the ability of CSW to pay dividends to its stockholders. At December 31, 1994, $1,375 million of the subsidiary companies' retained earnings were available for payment of cash dividends to CSW.
Reacquired Long-term Debt During 1994, 1993 and 1992, the Electric Operating Companies reacquired $27 million, $987 million and $652 million of long-term debt, respectively, including reacquisition premiums, prior to maturity. The premiums and related reacquisition costs and discounts are included in long-term debt on the consolidated balance sheets and are being amortized over 5 to 35 years, consistent with its expected ratemaking treatment.
The weighted average cost of long-term debt was 7.7% for 1994, 7.8% for 1993 and 8.3% for 1992.
Reference is made to MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources, for further information related to long-term debt, including new issues and reacquisition.
4.Preferred Stock The outstanding preferred stock of the Electric Operating Companies as of the end of the last two years follow:
Current 1994 Dividend Rate December 31, Redemption Prices Shares Outstanding From To 1994 1993 From To (millions) Not subject to mandatory redemption
592,900 4.00% 5.00% 59 59 102.75 107.00 760,000 7.12% 8.72% 76 76 100.00 101.00 1,600,000 auction 160 160 100.00 100.00
Issuance expenses and unamortized redemption costs (3) (3) $292 $292
Subject to mandatory redemption 352,000 6.95% 6.95% $ 35 $ 37 104.64 104.64 -- 10.05% 10.05% -- 22 -- --
Issuance expenses and unamortized redemption costs -- (1) $ 35 $ 58
The outstanding preferred stock not subject to mandatory redemption is redeemable at the option of the Electric Operating Companies upon 30 days notice at the current redemption price per share. CPL's auction preferred stock totaling $160 million also may be redeemed at par on any dividend payment date. The CSW System's authorized number of shares of preferred stock totaled 6.4 million at December 31, 1994 and 1993.
Redemption prices of certain preferred stock decline at specified intervals in future periods. The preferred stock issues subject to mandatory redemption are refundable at various times during the period 1995 through 1999. The minimum annual sinking fund requirements of the preferred stock are $1.2 million for the years 1995 through 1999. During 1994 and 1993, the Electric Operating Companies redeemed $33 million and $17 million, respectively, of preferred stock, including redemption premiums.
2-38 CPL The dividends on CPL's $160 million auction and money market preferred stocks are adjusted every 49 days, based on current market rates. The dividend rates averaged 3.5%, 2.7%, and 3.6% during 1994, 1993 and 1992.
CPL retired its remaining 10.05% preferred stock during August 1994.
WTU In July 1993, WTU redeemed 100,000 shares of its 7.25% Series, $100 par value, Preferred Stock, for $10 million, in accordance with mandatory and optional sinking fund provisions. The capital required for this transaction was provided by short-term borrowings from the CSW System money pool and internal sources.
In July 1994, WTU redeemed the remaining 47,000 shares of its 7.25% Series, $100 par value, Preferred Stock.
5.Common Stock On March 6, 1992, CSW effected a two-for-one split of CSW's common stock by means of a 100% stock dividend paid to stockholders of record on February 10, 1992. All references to number of shares outstanding, to per share information in the Consolidated Financial Statements, and to the notes thereto have been adjusted to reflect the stock split on a retroactive basis.
CSW has a restricted stock plan and a stock option plan. Under the stock option plan, 3,833,000 shares of common stock are available for grant and 491,000 shares are reserved for exercise of options which were outstanding at December 31, 1994.
The PowerShare dividend reinvestment plan is available to all CSW stockholders, employees, eligible retirees, utility customers and other residents of the four states where the Electric Operating Companies operate. Plan participants are able to make optional cash payments and reinvest all or any portion of their dividends in CSW common shares. During 1994, CSW raised approximately $50 million in common stock equity through PowerShare.
6.Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value.
Cash and temporary cash investments The carrying amount approximates fair value because of the short maturity of those instruments.
Short-term investments The carrying amount approximates fair value because of the short maturity of those instruments. Short-term investments are classified in accounts receivable on the consolidated balance sheets.
Long-term debt The fair value of the CSW System's long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to CSW for debt of the same remaining maturities.
Preferred stock subject to mandatory redemption The fair value of the Electric Operating Companies' preferred stock subject to mandatory redemption is estimated based on quoted market prices for the same or similar issues or on the current rates offered to CSW for preferred stock with the same or similar remaining redemption provision.
2-39 Long-term debt and preferred stock due within 12 months The fair value of current maturities of long-term debt and preferred stock due within 12 months are estimated based on quoted market prices for the same or similar issues or on the current rates offered for long-term debt or preferred stock with the same or similar remaining redemption provisions.
Short-term debt The carrying amount approximates fair value because of the short maturity of those instruments.
The fair value does not affect CSW's liabilities unless the issues are redeemed prior to their maturity dates.
The estimated fair values of CSW's financial instruments follow:
1994 1993 Carrying Fair Carrying Fair Amount Value Amount Value (millions) Cash and temporary cash investments $27 $27 $62 $62 Short-term investments -- -- 13 13 Long-term debt 2,940 2,795 2,749 2,947 Preferred stock subject to mandatory redemption 35 32 58 61 Long-term debt and preferred stock due within 12 months 7 7 26 26 Short-term debt 1,483 1,483 1,410 1,410
7.Short-Term Financing The CSW System has established a money pool to coordinate short- term borrowings and to make borrowings outside the money pool through CSW's issuance of commercial paper. At December 31, 1994, the CSW System had bank lines of credit aggregating $930 million to back up its commercial paper program.
CSW Credit, which does not participate in the money pool, issues commercial paper that is secured by the assignment of its receivables. CSW Credit maintains a secured revolving credit agreement which aggregated $900 million at December 31, 1994, to back up its commercial paper program.
8.Benefit Plans Defined Benefit Pension Plan The CSW System maintains a tax qualified, non-contributory defined benefit pension plan covering substantially all employees. Benefits are based on employees' years of credited service, age at retirement, and final average annual earnings with an offset for the participant's primary Social Security benefit. The CSW System's funding policy is based on actuarially determined contributions, taking into account amounts which are deductible for income tax purposes and minimum contributions required by the ERISA. Pension plan assets consist primarily of common stocks and short-term and intermediate-term fixed income investments.
Contributions to the plan for the years ended December 31, 1994, 1993 and 1992 were $28 million, $32 million and $29 million, respectively.
The approximate maximum number of participants in the plan during 1994 were 8,500 active participants, 3,600 retirees and beneficiaries and 1,000 terminated employees.
2-40 The components of net periodic pension cost and the assumptions used in accounting for pensions follow:
1994 1993 1992 (dollars in millions) Net Periodic Pension Cost Service cost $22 $20 $18 Interest cost on projected benefit obligation 62 56 50 Actual return on plan assets (4) (68) (43) Net amortization and deferral (70) -- (20) $10 $ 8 $ 5
Discount rate 8.25% 7.75% 8.50% Long-term compensation increase 5.46% 5.46% 5.96% Return on plan assets 9.50% 9.50% 9.50%
A reconciliation of the funded status of the plan to the amounts recognized on the balance sheets is shown below:
December 31, 1994 1993 (millions) Plan assets, at fair value $794 $790 Actuarial present value of Accumulated benefit obligation for service rendered to date 685 649 Additional benefit for future salary levels 112 133 Projected benefit obligation 797 782 Plan assets in excess/(below) the projected benefit obligation (3) 8 Unrecognized net gain 60 62 Unrecognized prior service cost (8) (8) Unrecognized net obligation 15 17 Prepaid pension cost $ 64 $ 79
The vested portion of the accumulated benefit obligations at December 31, 1994 and 1993 was $626 million and $586 million, respectively. The unrecognized net obligation is being amortized over the average remaining service life of employees or 16 years. Prepaid pension cost is included in other deferred charges on the consolidated balance sheets.
In addition to the amounts shown in the above table, the CSW System has a non-qualified excess benefit plan. This plan is available to all pension plan participants who are entitled to receive a pension benefit from CSW which is in excess of the limitations imposed on benefits by the Internal Revenue Code through the qualified plan. CSW's net periodic cost for this non- qualified plan for the years ended December 31, 1994, 1993 and 1992 was $1.8 million, $1.8 million and $0.5 million, respectively.
Health and Welfare Plans The CSW System had medical, dental, group life insurance, dependent life insurance, and accidental death and dismemberment plans for substantially all active CSW System employees during 1994. The contributions, recorded on a pay-as-you-go basis, for the years ended December 31, 1994 and 1993 were approximately $17
2-41 million and $23 million, respectively. Effective January 1993, the CSW System's method of providing health benefits was modified to include such benefits as a health maintenance organization, preferred provider options, managed prescription drug and mail- order program and a mental health and substance abuse program in addition to the self-insured indemnity plans.
Postretirement Benefits Other Than Pensions The CSW System adopted SFAS No. 106 effective January 1, 1993. The effect on operating expense in 1993 was an increase of $16 million. The transition obligation is being amortized over twenty years, with eighteen years remaining. In prior years, these benefits were accounted for on a pay-as-you-go basis.
The components of net periodic postretirement benefit cost follow:
1994 1993 (millions) Net Periodic Postretirement Benefit Cost Service cost $ 9 $ 8 Interest cost on APBO 19 17 Actual return on plan assets (1) (1) Amortization of transition obligation 9 9 Net amortization and deferral (4) (2) $32 $31
A reconciliation of the funded status of the plan to the amounts recognized on the consolidated balance sheets follow:
December 31, 1994 1993 APBO (millions) Retirees $141 $146 Other fully eligible participants 31 30 Other active participants 55 64 Total APBO 227 240 Plan assets at fair value (69) (51) APBO in excess of plant assets 158 189 Unrecognized transition obligation (162) (171) Unrecognized gain or (loss) 4 (18) (Accrued)/Prepaid Cost $ -- $ --
The following assumptions were used in accounting for SFAS No. 106.
1994 1993 Discount rate 8.25% 7.75% Return on plan assets 9.50% 9.00% Tax rate for taxable trusts 39.60% 39.60%
Health Care Cost Trend Rate Assumptions Pre-65 Participants: 1994 rate of 11.75% grading down .75% per year to an ultimate rate of 6.5% in 2001. Post-65 Participants: 1994 rate of 11.25% grading down .75% per year to an ultimate rate of 6.0% in 2001.
2-42 Increasing the assumed health care cost trend rates by one percentage point in each year would increase the APBO by $26 million and increase the aggregate of the service and interest costs components by $4 million as of December 31, 1994.
9.Jointly Owned Electric Utility Plant The Electric Operating Companies are parties to various joint ownership agreements with other non-affiliated entities. Such agreements provide for the joint ownership and operation of generating stations and related facilities, whereby each participant bears its share of the project costs. At December 31, 1994, the companies have undivided interests in five such generating stations and related facilities as shown below:
CPL SWEPCO SWEPCO SWEPCO CSW South Flint Dolet System Texas Creek Pirkey Hills Oklaunion Nuclear Coal Lignite Lignite Coal Plant Plant Plant Plant Plant (dollars in millions) Plant in service $2,343 $ 79 $ 431 $ 226 $ 397 Accumulated depreciation $ 380 $ 39 $ 135 $ 62 $ 91 Plant capacity-MW 2,500 480 650 650 676 Participation 25.2% 50.0% 85.9% 40.2% 78.1% Share of capacity-MW 630 240 559 262 528
10. Litigation and Regulatory Proceedings
CPL STP From February 1993 until May 1994, STP experienced an unscheduled outage which has resulted in significant rate and regulatory proceedings involving CPL. These matters, including a base rate case and fuel reconciliation proceedings, are discussed immediately below.
Texas Commission Proceedings Base Rates Rate Inquiry - Docket No. 12820 Several Cities, the Texas Commission General Counsel and others initiated actions in late 1993 and early 1994 which, if approved by the Texas Commission, would lower CPL's base rates. The requests for a review of CPL's rates arose out of the unscheduled outage at STP which began in February 1993. The STP outage did not affect CPL's ability to meet customer demand because of existing capacity and CPL's purchase of additional energy.
Pursuant to a scheduling and procedural settlement agreement among the parties challenging CPL's rates, which was approved by a Texas Commission ALJ on April 1, 1994, CPL submitted a rate filing package on July 1, 1994 to the Texas Commission justifying its current base rate structure. In that filing, CPL stated that it had a $111 million retail revenue deficiency and would be justified in seeking a base rate increase. However, consistent with the procedural settlement agreement, CPL has not sought to increase base rates as a part of this docket but seeks to maintain its rates at the same levels agreed to in the settlement of its last two rate cases in 1990 and 1991. As part of the 1990 and 1991 settlements, CPL agreed to freeze base rates from January 1, 1991 through 1994, subject to certain force majeure events including double digit inflation, major tax increases, extraordinary increases in operating expenses or serious declines in operating revenues. On October 31, 1994, CPL filed rebuttal testimony that revised its retail revenue deficiency to approximately $103 million. CPL continues to maintain that its rates are reasonable and that its earnings are within established regulatory guidelines.
2-43 Parties to CPL's base rate case have filed testimony with the Texas Commission recommending reductions in CPL's base rates. Among the parties that filed testimony were OPUC which initially recommended an annual $100 million retail rate reduction. After hearings on the rate case, OPUC claimed that CPL did not meet its burden of proof concerning deferred accounting and as a result OPUC changed its proposed reduction to $147 million. The Cities, which are parties to the rate case, have recommended an annual $75 million retail rate reduction and the write-off of $219 million of CPL's Mirror CWIP asset. See Deferred Accounting below.
The Staff filed testimony recommending an annual reduction in retail rates of $99.6 million resulting from a combination of proposed rate base and cost of service reductions, which it subsequently revised during the hearings to $83.9 million. In its final brief to the ALJ, the Texas Commission's Staff withdrew its recommendation that short-term debt be included in the calculation of CPL's weighted cost of capital. CPL estimates that this change in the Staff's position will lower its revised proposed retail rate reduction by approximately $6 million. The Staff recommended a rate base disallowance of $407 million, or approximately 17% of CPL's investment in STP, based upon the Staff's calculation of historical performance for STP compared to a peer group of other nuclear facilities. The Staff also recommended that accumulated depreciation and accumulated deferred federal income taxes related to the disallowed portion of STP be adjusted to reflect a net reduction to rate base of $325 million. Additionally, the Staff proposed to disallow depreciation expense related to the recommended STP disallowed plant.
In its testimony, the Staff argued that its proposed STP rate base reduction was a historical performance-based disallowance that could be temporary in nature and would not have to result in a permanent disallowance. The Staff indicated that, in the future, CPL could seek recovery in rates of the proposed STP rate base disallowance, subject to the performance of STP.
The Texas Commission held hearings in November and December 1994, and all parties have filed briefs in the case. The ALJ is expected to issue a recommended order for consideration by the Texas Commission in April 1995, with a final order from the Texas Commission expected in May 1995. Testimony filed by parties to the rate case, including the Staff, is not binding on either the ALJ or the Texas Commission.
CPL strongly believes that 100 percent of its investment in both units of STP belong in rate base. This belief is based on, among other factors, Units 1 and 2 providing output at high capacity factors since April and June 1994, respectively. In addition, the long-term benefits nuclear generation provides to customers supports their inclusion in rate base. Furthermore, there are no Texas Commission precedents addressing the removal of a nuclear plant from rate base as a performance-based disallowance. Assuming both units of STP are included in rate base, CPL believes it is not collecting excessive revenues, notwithstanding that market rates of return on common equity are generally lower today than they were in 1990 and 1991, when CPL's base rates were last set.
Fuel Introduction Pursuant to the substantive rules of the Texas Commission, CPL generally is allowed to recover its fuel costs through a fixed fuel factor. These fuel factors are in the nature of temporary rates, and CPL's collection of revenues by such fuel factors is subject to adjustment at the time of a fuel reconciliation proceeding before the Texas Commission. The difference between fuel revenues billed and fuel expense incurred is recorded as an addition to or a reduction of revenues, with a corresponding entry to unrecovered fuel costs or other current liabilities, as appropriate. Any fuel costs, not limited to under- or over- recoveries, which the Texas Commission determines as unreasonable in a reconciliation proceeding are not recoverable from customers.
Fuel Surcharge - Docket No. 12154 In July 1993, CPL filed a fuel surcharge petition, which is separate from a fuel reconciliation proceeding, with the Texas Commission to comply with the mandatory provisions of the Texas Commission's fuel rules. The petition requested approval of a
2-44 customer surcharge to recover under-recovered fuel and purchased power costs resulting from the STP outage, increased natural gas costs and other factors. The petition also requested that the Texas Commission postpone consideration of the surcharge until the STP outage concluded or at the time fuel costs are next reconciled as discussed above. In August 1993, a Texas Commission ALJ granted CPL's request to postpone consideration of the surcharge. In January and July of 1994, CPL updated its fuel surcharge petition to reflect amounts of under-recovery through November 1993 and May 1994, respectively. Also, CPL further updated its petition in January 1995 to reflect amounts of under-recovery through November 1994. Likewise, CPL requested and was granted postponement of the updated petitions until the STP outage concluded or at the time fuel costs are next reconciled. On January 4, 1995, Docket No. 12154 was consolidated into Docket No. 13650.
Prudence Inquiry - Docket No. 13126 In April 1994, the Texas Commission's General Counsel and Staff issued a Request for Proposal for an audit of the STP outage, and in July 1994 a consultant was selected to perform the audit. The purpose of the audit is to evaluate the prudence of management activities at STP, including the actions of HLP and the STP management committee, of which CPL is a participant. Such review will include the time from original commercial operation of each unit until they were returned to service from the outage. The findings of this audit are expected to be incorporated into this proceeding. CPL and HLP will pay the costs of the audit but will have no control over the ultimate work product of the consultant.
In June 1994, the Texas Commission's General Counsel initiated an inquiry into the operation and management of STP which resulted in the establishment of this proceeding. As part of the inquiry, CPL presented certain information concerning the prudence of management activities at STP relating to the STP outage. Testimony filed by CPL stated that the cause of the STP outage was the result of an accidental equipment failure rather than imprudent management activities at STP. Based on this information, CPL will seek full recovery in its fuel reconciliation case of incremental energy costs related to the STP outage.
As a part of this proceeding, CPL was required to reconstruct its production costs assuming STP was available 100% of the time during the actual outage. Testimony filed by CPL stated that it is unrealistic to expect any generating unit to operate all the time. The testimony provided calculations of STP replacement power cost estimates for availability factor scenarios at (i) 100%, (ii) 75% and (iii) 65% average availability. Based on these average availability factors, STP net replacement power costs for the entire outage period were estimated to be (i) $104.5 million at 100%, (ii) $79.0 million at 75% and (iii) $68.2 million at 65% average availability.
The results of this prudence inquiry are expected to be used in CPL's pending fuel reconciliation proceeding in Docket No. 13650, as discussed below, and possibly CPL's next base rate proceeding should a return on equity penalty be ordered by the Texas Commission. Such penalty could lower CPL's allowed return on equity in its next base rate case from what it otherwise would be permitted to earn.
Fuel Reconciliation - Docket No. 13650 On November 15, 1994, CPL filed a fuel reconciliation case with the Texas Commission seeking to reconcile approximately $1.2 billion of fuel costs from March 1, 1990 through June 30, 1994. This period includes the STP outage where CPL's fuel and purchased power costs were increased as the power normally generated by STP was replaced through sources with higher costs. At December 31, 1994, CPL's under-recovered fuel balance was $54.1 million, exclusive of interest. This under-recovery of fuel costs, while due primarily to the STP outage, was also affected by changes in fuel prices and timing differences. CPL cannot accurately estimate the amount of any future under- or over-recoveries due to the nature of the above factors. CPL cannot predict how the Texas Commission will ultimately resolve the reasonableness of higher replacement energy costs associated with the STP outage. Although the Texas Commission could disallow all or a portion of the STP replacement energy costs, such determination cannot be made until a final order is issued by the Texas Commission in this docket.
2-45 If a significant portion of the fuel costs were disallowed by the Texas Commission, CSW could experience a material adverse effect on its consolidated results of operations in the year of disallowance but not on its financial condition.
CPL continues to negotiate with the intervening parties to resolve Docket Nos. 12820, 13126 and the STP portions of Docket No. 13650 through settlement. However, no settlement has been reached.
Management cannot predict the ultimate outcome of these regulatory proceedings. However, management believes that the ultimate resolution of the various issues will not have a material adverse effect on CSW's consolidated results of operations or financial condition.
STP Background Final Orders In October 1990, the Texas Commission issued the STP Unit 1 Order which fully implemented a stipulated agreement filed in February 1990 to resolve dockets then pending before the Texas Commission. In December 1990, the Texas Commission issued the STP Unit 2 Order which fully implemented a stipulated agreement to resolve all issues regarding CPL's investment in STP Unit 2.
The STP Unit 1 Order allowed CPL to increase retail base rates by $144 million. This base rate increase made permanent a $105 million interim base rate increase placed into effect in March 1990 and a $39 million interim base rate increase placed into effect in September 1989. The STP Unit 2 Order provided for a retail base rate increase of $120 million effective January 1, 1991. The STP Unit 1 Order also provided for the deferral of operating expenses and carrying costs on STP Unit 2. A prior Texas Commission order had authorized deferral of STP Unit 1 costs. See Deferred Accounting below. Such costs are being recovered through rates over the remaining life of STP. Also, the STP Unit 1 Order authorized use of Mirror CWIP, pursuant to which CPL recognized $360 million of carrying costs as deferred costs, and established a corresponding liability to customers recorded in Mirror CWIP Liability and Other Deferred Credits on the balance sheets. In compliance with the order, carrying costs collected through rates during periods when CWIP was included in rate base were recognized as a loan from customers. The loan is being repaid through lower rates from 1991 through 1995. The Mirror CWIP liability is being reduced by the recognition of non-cash income during the period 1991 through 1995. The Mirror CWIP asset is being amortized to expense over the life of the plant.
The STP Unit 1 and 2 Orders resolved all issues pertaining to the reasonable original costs of STP and the appropriate amount to be included in rate base. Pursuant to the Texas Commission orders, the original costs of CPL's total investment in STP is included in rate base. As indicated under the heading Texas Commission Proceedings above, however, CPL is currently involved in base rate and fuel proceedings which challenge CPL's right to recover certain costs associated with the STP outage.
As part of the stipulated agreement, CPL agreed to freeze base rates from January 1, 1991 through 1994, subject to certain force majeure events including double-digit inflation, major tax increases, extraordinary increases in operating expenses or serious declines in operating revenues. CPL may file for increases in base rates, which would be effective after 1994 and subject to certain limitations. The fuel portion of customers' bills is subject to adjustment following the normal review and approval by the Texas Commission.
The stipulated agreements, as discussed above, were entered into by CPL, the Staff and a majority of intervenors including major cities in CPL's service territory and major industrial customers. These intervenors represent a significant majority of CPL's customers. CPL and the TSA reached agreements, which were subsequently approved by the Staff and other signatories, whereby TSA agreed not to oppose the stipulated agreements in any respect, except with regard to deferred accounting and rate design issues
2-46 in the STP Unit 1 Order. OPUC and a coalition of low-income customers declined to enter into the stipulated agreements.
In January 1991, the TSA, OPUC and the coalition of low-income customers filed appeals of the STP Unit 1 Order in District Court requesting reversal of the deferred accounting for STP Unit 2 and other aspects of that order. In March 1991, the TSA, OPUC and the coalition of low-income customers filed appeals of the STP Unit 2 Order in the District Court requesting reversal of that order. These appeals are pending before the District Court. If these orders are ultimately reversed on appeal, the stipulated agreements would be nullified and CSW could experience a significant adverse effect on its consolidated results of operations and financial condition. However, the parties to the stipulated agreement, should it be nullified, are bound to renegotiate and try to reach a revised agreement that would achieve the same economic results. Management believes that the STP Unit 1 and 2 Orders will be upheld.
Deferred Accounting CPL was granted deferred accounting for STP Unit 1 and 2 costs by Texas Commission orders. These orders allowed CPL to defer post- in-service operating and maintenance costs, including taxes and depreciation, and carrying costs until these costs were reflected in retail rates. Deferred accounting had an immediate positive effect on net income in the years allowed, but cash earnings were not increased until rates went into effect reflecting STP in service. See Final Orders above. The total deferrals for the periods affected were approximately $492 million with an after-tax net income effect of approximately $325 million. This total deferral included approximately $270 million of pre-tax debt carrying costs. Pursuant to the STP Unit 1 and 2 Orders, CPL's retail rates include recovery of STP Unit 1 and 2 deferrals over the remaining life of the plant.
In July 1989, OPUC and the TSA filed appeals of the Texas Commission's final order in District Court requesting reversal of deferred accounting for STP Unit 1. In September 1990, the District Court issued a judgment affirming the Texas Commission's order for STP Unit 1, which was subsequently appealed to the Court of Appeals by OPUC and the TSA. The hearing of CPL's STP Unit 1 deferred accounting order was combined by the Court of Appeals with similar appeals of HLP deferred accounting orders.
In September 1992, the Court of Appeals issued a decision that allows CPL to include STP Unit 1 deferred post-in-service operating and maintenance costs in rate base. However, the Court of Appeals held that deferred post-in-service carrying costs could not be included in rate base, thereby prohibiting CPL from earning a return on such costs.
After the Court of Appeals' denial of each party's motion for rehearing of the decision, CPL and the Texas Commission in December 1992 filed Applications for Writ of Error petitioning the Supreme Court of Texas to review the September 1992 decision denying rate base treatment of deferred post-in-service carrying costs by the Court of Appeals. Additionally, the TSA and OPUC filed Applications for Writ of Error petitioning the Supreme Court of Texas to reverse the Court of Appeals' decision, challenging generally the legality of deferred accounting for rate base treatment of any deferred costs. In May 1993, the Supreme Court of Texas granted CPL's Application for Writ of Error. CPL's case was consolidated with the deferred accounting cases of El Paso and HLP. In June 1994, the Supreme Court of Texas sustained deferred accounting as an appropriate mechanism for the Texas Commission to use in preserving the financial integrity of utilities. The Supreme Court of Texas held that the Texas Commission can authorize utilities to defer those costs that are incurred between the in-service date of a plant and the effectiveness of new rates, which include such costs. On October 6, 1994, the Supreme Court of Texas denied a motion for rehearing CPL's deferred accounting matter filed by the State of Texas. The language of the Supreme Court of Texas opinion suggests that the appropriateness of allowing deferred accounting may need to again be reviewed under a financial integrity standard at the time the costs begin being recovered through rates. For CPL, that would be the STP Unit 1
2-47 and Unit 2 Orders discussed above. To the extent that additional review is required, it should occur in those dockets.
If these deferred accounting matters are not favorably resolved, CSW could experience a material adverse effect on its consolidated results of operations and financial condition. While CPL's management cannot predict the ultimate outcome of these matters, management believes CPL will receive approval of its deferred accounting orders or will be successful in renegotiation of its rate orders, so that there will be no material adverse effect on CSW's consolidated results of operations or financial condition.
Westinghouse Litigation CPL and other owners of STP are plaintiffs in a lawsuit filed in October 1990 in the District Court in Matagorda County, Texas against Westinghouse, seeking damages and other relief. The suit alleges that Westinghouse supplied STP with defective steam generator tubes that are susceptible to stress corrosion cracking. Westinghouse filed an answer to the suit in March 1992, denying the plaintiff's allegations. The suit is set for trial in July 1995.
Inspections during the STP outage have detected early signs of stress corrosion cracking in tubes at STP Unit 1. Management believes additional problems would develop gradually and will be monitored by the Project Manager of STP. An accurate estimate of the costs of remedying any further problems currently is unavailable due to many uncertainties, including among other things, the timing of repairs, which may coincide with scheduled outages, and the recoverability of amounts from Westinghouse. Management believes that the ultimate resolution of this matter will not have a material adverse effect on CSW's consolidated results of operations or financial condition.
Civil Penalties In October 1994, the NRC staff advised HLP that it proposes to fine HLP $100,000 for what the NRC believes was discrimination against a contractor employee at STP who brought complaints of possible safety problems to the NRC's attention. These actions resulted from the findings of a NRC investigation of alleged violations of STP security and work process procedures in 1992. The incident cited by the NRC is the subject of a contested hearing that is scheduled to be held in the spring of 1995 before a United States Department of Labor judge. Until the Department of Labor issues a final decision in this matter, the NRC is not requiring HLP to respond to its notice of violation.
PSO
Rate Review In December 1993, the Oklahoma Commission issued an order unanimously approving a joint stipulation between PSO, the Oklahoma Commission Staff, and the Office of the Attorney General of the State of Oklahoma, as recommended by the ALJ. The order allowed PSO an increase in retail prices of $14.4 million on an annual basis which represents a $4.3 million increase above those authorized by the March 1993 interim order. In January 1994, the Oklahoma Commission issued an order unanimously approving PSO's price schedules reflecting the $14.4 million price increase. The new prices became effective beginning with the billing month of February 1994.
The December 1993 order addresses, among other things, the following issues. PSO will recover $4.5 million annually in expenses associated with OPEBs, which, for PSO, are primarily health care related benefits. Such expenses will be recovered along with amortization of the deferred 1993 OPEBs at a rate of $0.5 million per year for 10 years. PSO will amortize deferred storm expenses associated with both a 1987 ice storm and a 1992 wind storm, amounting to $1.2 million per year for five years. In addition, the order recognizes the increase in federal income tax expenses resulting from the recent increase in the federal corporate income tax rate from 34 percent to 35 percent. PSO will continue to use the depreciation rates previously approved by the
2-48 Oklahoma Commission. PSO agreed that it will not file another retail price increase application until after June 30, 1995.
Gas Transportation and Fuel Management Fees An order issued by the Oklahoma Commission in 1991 required that the level of gas transportation and fuel management fees, paid to Transok by PSO, permitted for recovery through the fuel adjustment clause be reviewed in the aforementioned price proceeding. This portion of the price review was bifurcated. In February 1995, an agreement was reached which allows PSO to recover approximately $28.4 million of transportation and fuel management fees in base rates using 1991 determinants and approximately $1 million through the fuel adjustment clause. The agreement also requires the phase- in of competitive bidding of natural gas transportation requirements in excess of 165 MMcf/d per day. An ALJ has recommended approval of the agreement to the Oklahoma Commission. A final order is expected in the first quarter of 1995.
Gas Purchase Contracts PSO has been named defendant in complaints filed in federal and state courts of Oklahoma and Texas in 1984 through February 1995 by gas suppliers alleging claims arising out of certain gas purchase contracts. Cases currently pending seek approximately $29 million in actual damages, together with claims for punitive damages which, in compliance with pleading code requirements, are alleged to be in excess of $10,000. The plaintiffs seek relief through the filing dates as well as attorney fees. As a result of settlements among the parties, certain plaintiffs dismissed their claims with prejudice to further action. The settlements did not have a significant effect on CSW's consolidated results of operations. The remaining suits are in the preliminary stages. Management cannot predict the outcome of these proceedings. However, management believes that PSO has defenses to these complaints and intends to pursue them vigorously. Management also believes that the ultimate resolution of the remaining complaints will not have a material adverse effect on CSW's consolidated results of operations or financial condition.
PCB Cases PSO has been named a defendant in complaints filed in state court in Oklahoma alleging, among other things, that some of the plaintiffs were contaminated with PCBs and other toxic by-products following transformer malfunctions. The complaints currently total approximately $383 million of which approximately one-third represents punitive damages. Some claims have been dismissed, certain of which resulted in settlements among the parties. The settlements did not have a significant effect on CSW's consolidated results of operations. Although management cannot predict the outcome of these proceedings, management believes that PSO has defenses to these claims and intends to pursue them vigorously. Moreover, management has reason to believe that PSO's insurance may cover some of the claims. Management also believes that the ultimate resolution of these cases will not have a material adverse effect on CSW's consolidated results of operations or financial condition.
Burlington Northern Transportation Contract In June 1992, PSO filed suit in Federal District Court in Tulsa, Oklahoma, against Burlington Northern seeking declaratory relief under a long-term contract for the transportation of coal. In July 1992, Burlington Northern asserted counterclaims against PSO alleging that PSO breached the contract. The counterclaims sought damages in an unspecified amount. In December 1993, PSO amended its suit against Burlington Northern seeking damages and declaratory relief under federal and state anti-trust laws. PSO and Burlington Northern filed motions for summary judgment on certain dispositive issues in the litigation. In March 1994, the court issued an order granting PSO's motions for summary judgment and denying Burlington Northern's motion. It was not necessary for the court to decide the federal and state anti-trust claims raised by PSO. Judgment was rendered in favor of PSO by the United States District Court in May 1994. In June 1994, Burlington Northern appealed this judgment to the United States Court of Appeals for the Tenth Circuit. This appeal is now pending.
2-49 Burlington Northern Arbitration In May 1994, in a related arbitration, an arbitration panel made an award favorable to PSO concerning basic transportation rates under the coal transportation contract described above, and concerning the contract mechanism for adjustment of future transportation rates. These arbitrated issues were not involved in the related lawsuit described above. Burlington Northern filed an action to vacate the arbitrated award in the District Court for Dallas County, Texas. PSO removed this action to the United States District Court for the Northern District of Texas, and filed a motion to either dismiss this action or have it transferred to the United States District Court for the Northern District of Oklahoma. Burlington Northern moved to remand the action to state court. In September 1994, the United States District Court for the Northern District of Texas denied Burlington Northern's motion to remand, and granted PSO's motion to transfer the action to the United States District Court for the Northern District of Oklahoma. Separately, PSO filed an action to confirm the arbitration award in the United States District Court for the Northern District of Oklahoma, and Burlington Northern filed a motion to dismiss this confirmation action. On December 6, 1994, the District Court entered an order denying the Burlington Northern's motion to vacate the arbitration award, and granting PSO's motion to confirm the arbitration award. On December 29, 1994, the District Court entered judgment confirming the arbitration award, including a money judgment in PSO's favor for $16.4 million, with interest at 7.2% per annum compounded annually from December 21, 1994 until paid. On January 6, 1995, Burlington Northern appealed the District Court's judgment to the United States Court of Appeals for the Tenth Circuit. This appeal is now pending.
SWEPCO Fuel Reconciliation On March 17, 1994, SWEPCO filed a petition with the Texas Commission to reconcile fuel costs for the period November 1989 through December 1993. Total Texas jurisdictional fuel expenses subject to reconciliation for this 50-month period were approximately $559 million. SWEPCO's net under-recovery for the reconciliation period was approximately $0.9 million. SWEPCO and the intervening parties in this proceeding were able to negotiate a stipulated agreement providing a $3.2 million fuel cost disallowance and settling all issues except one. That issue involved the recovery of certain fuel related litigation and settlement negotiation expenses. The Texas Commission, at its Final Order hearing on January 18, 1995, approved the stipulated disallowance and granted SWEPCO recovery of the fuel related litigation expense. The $3.2 million disallowance is included in SWEPCO's 1994 results of operations. SWEPCO recognized the litigation costs as expenses in prior periods.
Burlington Northern Transportation Contract On January 20, 1995, a state district court in Bowie County, Texas, entered judgment in favor of SWEPCO against Burlington Northern in a lawsuit between the parties regarding rates charged under two rail transportation contracts for delivery of coal to SWEPCO's Welsh and Flint Creek power plants. The court awarded SWEPCO approximately $72 million covering damages for the period from April 27, 1989 through September 26, 1994 and prejudgment interest fees and grant certain declaratory relief requested by SWEPCO.
Kansas City Southern Railway Company Transportation Contracts In March 1994, SWEPCO entered into a settlement with the Kansas City Southern Railway Company of litigation between parties regarding two coal transportation contracts. Pursuant to the settlement, SWEPCO and the Kansas City Southern Railway Company executed a new coal transportation agreement. The settlement is expected to result in a reduction of SWEPCO's coal transportation costs now and in the future. Burlington Northern, another party to the prior contracts and to the litigation, did not participate in the settlement and the litigation is still pending between SWEPCO and Burlington Northern.
2-50 WTU
Rate Proceeding - Docket No. 13369 On August 25, 1994, WTU filed a petition with the Texas Commission and with cities with original jurisdiction to review WTU's rates, proposed an interim across-the-board base rate reduction of 3.25% or, approximately $5.7 million, effective October 1, 1994, and sought until February 28, 1995, the time to develop and file a RFP. WTU also requested the ability to "true-up", back to October 1, 1994, any difference in revenue requirements upon final order of the Texas Commission, and proposed that any increases over the pre-October 1, 1994, base rates be implemented prospectively on the effective date of the final order.
As discussed below, WTU's fuel reconciliation was consolidated with this proceeding in September 1994. Reconcilable fuel costs during the reconciliation period were approximately $300 million. At June 30, 1994, the fuel cost under-recovery totaled approximately $5.1 million, including interest. At December 31, 1994, this amount had become an over-recovery of approximately $0.2 million. WTU is not seeking a change in fuel factors.
On February 28, 1995, WTU filed with the Texas Commission and cities with original jurisdiction the rate filing package which indicates a revenue deficiency of approximately $14.5 million. However, WTU simultaneously filed with the parties a settlement proposal to reduce overall base rate revenue by 3.25%, effective October 1, 1994, an annual impact in the rate year beginning January 1, 1996 of approximately $5.9 million. The settlement proposal reflects WTU's desire to maintain competitive rates, recognizes the importance of competitive rates in the changing electric service marketplace, and demonstrates WTU's strong commitment to the long-term success of WTU and its customers.
Unless a settlement accelerates the schedule, WTU anticipates hearings in mid-1995 with a final order in the fourth quarter of 1995. Management cannot predict the outcome of the rate proceeding, the fuel reconciliation, or the settlement proposal, but believes that the ultimate resolution of these matters will not have a material adverse effect on CSW's consolidated results of operations or financial condition.
Fuel Reconciliation - Docket No. 13172 On June 30, 1994, WTU filed a petition with the Texas Commission to reconcile fuel costs for the period January 1991 through February 1994. Subsequently, in September 1994, this fuel reconciliation proceeding was consolidated into Docket No. 13369 described above, and the reconciliation period was extended through June 1994.
Rate Case Proceeding - Docket No. 7510 In November 1987, the Texas Commission issued a final order in WTU's retail rate case providing for WTU to receive an annual increase in base retail revenues of $34.9 million. Rates reflecting the final order were implemented in December 1987. WTU, along with certain intervenors in the retail rate proceeding, appealed the Texas Commission's final order to the District Court seeking reversal of various provisions of the final order, including the inclusion of deferred accounting in rate base.
The appeals were consolidated and in September 1988, the District Court affirmed the final order of the Texas Commission. In November 1988, certain intervenors filed appeals of the District Court's judgment with the Court of Appeals. In February 1990, the Court of Appeals ruled that an intervenor had improperly been excluded from presenting its appeal to the District Court, reversed the District Court's judgment and remanded the case to the District Court for further proceedings.
In October 1992, the District Court heard the remanded appeals of the final order of the Texas Commission and in March 1993 issued an order affirming the Texas Commission's order in all material respects with the single exception of the inclusion of deferred
2-51 Oklaunion carrying costs in rate base. In its treatment of deferred costs, the District Court followed a then-current opinion of the Court of Appeals which precluded recovery of deferred post- in-service carrying costs. In April 1993, WTU and other parties filed appeals, and oral argument was held on the appeals in December 1993 on the non-deferred accounting issues. With respect to the deferred accounting issues, the parties recognized certain Supreme Court of Texas decisions regarding other deferred accounting cases would be influential in WTU's case.
In June 1994, the Supreme Court of Texas issued its opinion in the three other cases involving deferred accounting holding that the Texas Commission has the authority to allow deferred accounting treatment during the deferral period, including deferred post-in- service carrying costs. The Supreme Court of Texas upheld the Court of Appeals in all respects except it reversed the Court of Appeals to the extent it disallowed carrying costs deferrals and remanded to the Court of Appeals for consideration of the unresolved arguments of the improperly excluded intervenor. Motions for rehearing were filed by certain parties which were denied by the Supreme Court of Texas. These rulings influenced the Court of Appeals' decision in WTU's rate case appeals, as described below.
On February 15, 1995, the Court of Appeals affirmed all aspects of the District Court judgment relating to the Texas Commission's allowance of non-Oklaunion depreciation rates and the surcharge of rate case expenses, reversed the District Court's judgment relating to the exclusion of deferred Oklaunion carrying costs in rate base, and remanded the cause to the Texas Commission to reexamine the issue of deferred costs in light of the remand of Docket No. 7289, as described above. However, on March 3, 1995, WTU filed a motion for rehearing at the Court of Appeals seeking clarification of certain aspects of its order and arguing that the Court of Appeals erred in remanding the case to the Texas Commission for it to determine to what extent deferred costs are necessary to preserve WTU's financial integrity because the issue has been waived since it was not briefed or argued to the Court of Appeals. WTU expects other parties may also file motions for rehearing.
WTU's motion for rehearing may, if granted, prevent further review of financial integrity issues with respect to deferred accounting in any remand of Docket No. 7510. If a broader remand is permitted and if the Texas Commission concludes in Docket No. 7289 that deferred accounting was necessary to preserve WTU's financial integrity during the deferral period, the Texas Commission must decide to what extent the deferred Oklaunion costs, including carrying costs, were necessary to preserve WTU's financial integrity. If WTU's deferred accounting treatment is ultimately reversed or is substantially reduced, WTU could experience a material adverse impact on its results of operations. While management can give no assurances as to the outcome of the remanded proceeding or the motion for rehearing, management believes that 100 percent of the Oklaunion deferred costs will be determined by the Texas Commission to have been necessary to preserve WTU's financial integrity during the deferral period so that there will be no material adverse effect on CSW's consolidated results of operations or financial condition.
Deferred Accounting - Docket No. 7289 WTU received approval from the Texas Commission in September 1987 to defer operating expenses and carrying costs associated with Oklaunion incurred subsequent to its December 1986 commercial operation date until December 1987 (the deferral period) when retail rates including Oklaunion in WTU's rate base became effective. WTU has recorded approximately $32 million of Oklaunion deferred costs, of which $25 million are carrying costs. The deferred costs are being recovered and amortized over the remaining life of the plant. In November 1987, OPUC filed an appeal in the District Court challenging the Texas Commission's final order authorizing WTU to defer the costs associated with Oklaunion. In October 1988, the District Court affirmed the final order of the Texas Commission. In December 1988, OPUC filed an appeal of the District Court judgment in the Court of Appeals. In September 1990, the Court of Appeals upheld the District Court's affirmance of the Texas Commission's final order and in October 1990, OPUC filed a motion for rehearing of the Court of Appeals' decision, which was denied in November 1990. On further appeal,
2-52 the Supreme Court heard oral argument in September 1993, in WTU's case as well as three other cases involving deferred accounting and in June 1994 issued its opinions in these cases affirming the Texas Commission's authority to allow deferred accounting treatment, but establishing a financial integrity standard rather than the measurable harm standard used by the Texas Commission.
In October 1994, the Supreme Court of Texas issued a mandate remanding WTU's deferred accounting case to the Texas Commission. While no schedule has yet been established for the proceedings on remand at the Texas Commission, this remand may be considered in tandem with WTU's pending rate case, Docket No. 13369. In the remanded proceeding, the Texas Commission must make a formal finding that the deferral of Oklaunion costs was necessary to prevent WTU's financial integrity during the deferral period from being jeopardized.
If WTU's deferred accounting treatment is ultimately reversed and not favorably resolved, WTU could experience a material adverse impact on its results of operations. While management cannot predict the ultimate outcome of these proceedings, management believes that WTU's deferred accounting will be ultimately sustained by the Texas Commission on the basis of the financial integrity standard set forth by the Supreme Court of Texas, so that there will be no material adverse effect on CSW's consolidated results of operations or financial condition.
WTU FERC Order On April 4, 1994, the FERC issued an order pursuant to section 211 of the Federal Power Act forcing a regional utility to transmit power to Tex-La on behalf of WTU. The order was one of the first issued by FERC under that provision, which was added by the Energy Policy Act to increase competition in wholesale power markets. WTU began serving Tex-La, which has requirements of approximately 120 MW of electric power. WTU will serve Tex-La until facilities are completed to connect Tex-La to SWEPCO, an affiliated system, at which time SWEPCO will provide 85 MW and WTU will retain 35 MW of the Tex-La electric load.
Other Cimmaron On January 12, 1994, Cimmaron brought suit against CSW and its wholly-owned subsidiary, CSWE, in the 125th District Court of Houston, Harris County, Texas. Cimmaron alleges that CSW and CSWE breached commitments to participant with Cimmaron in the failed BioTech Cogeneration project located in Colorado. Cimmaron claims breach of contract, fraud and negligent misrepresentation with alleged damages totaling $250 million, punitive damages of an unspecified amount, as well as attorney's fees.
CSWE filed a counterclaim against Cimmaron and third-party claims against the principals of Cimmaron on December 22, 1994, alleging that they misrepresented and omitted material facts about their experience and background and about the proposed cogeneration project. CSWE seeks damages of $500,000, the earnest money paid when the letter of intent was executed, the costs associated with due diligence and punitive damages. On January 10, 1995, Cimmaron filed a first amended original petition suing CSWE board members at the time, personally.
Pre-trial discovery on the case is presently underway with depositions of the parties being taken during March, 1995. Trial was originally set for the week of April 10, 1995, but the parties have filed a joint motion for continuance which is set for hearing on March 20, 1995. Management of CSW cannot predict the outcome of this litigation, but believes that CSW and CSWE have defenses to these complaints and are pursuing them vigorously and that the ultimate resolution will not have a material adverse effect on CSW's consolidated results of operations or financial condition.
2-53 General Matters CSW and the Operating Companies are party to various other legal claims, actions and complaints arising in the normal course of business. Management does not expect disposition of these matters to have a material adverse effect on CSW's consolidated results of operations or financial condition.
11. Commitments and Contingent Liabilities Proposed Acquisition of El Paso Background In May 1993, CSW entered into a Merger Agreement pursuant to which El Paso would emerge from bankruptcy as a wholly-owned subsidiary of CSW. El Paso is an electric utility company headquartered in El Paso, Texas, engaged principally in the generation and distribution of electricity to approximately 262,000 retail customers in west Texas and southern New Mexico. El Paso also sells electricity under contract to wholesale customers in a number of locations including southern California and Mexico. El Paso had filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code on January 8, 1992.
On July 30, 1993, El Paso filed the Modified Plan and a related proposed form of Disclosure Statement providing for the acquisition of El Paso by CSW. On November 15, 1993, all voting classes of creditors and shareholders of El Paso voted to approve the Modified Plan. On December 8, 1993, the Bankruptcy Court confirmed the Modified Plan.
Under the Modified Plan, the total value of CSW's offer to acquire El Paso is approximately $2.2 billion. The Modified Plan generally provides for El Paso creditors and shareholders to receive shares of CSW Common, cash and/or securities of El Paso, or to have their claims cured and reinstated. The Modified Plan also provides for claims of secured creditors generally to be paid in full with debt securities of reorganized El Paso, and for unsecured creditors to receive a combination of debt securities of reorganized El Paso and CSW Common equal to 95.5 percent of their claims, and for small trade creditors to be paid in full with cash. The Modified Plan provides for El Paso's preferred shareholders to receive preferred shares of reorganized El Paso, or cash, and for options to purchase El Paso Common to be converted into options to purchase a proportionate number of shares of CSW Common. In addition, the Modified Plan provides for certain creditor classes of El Paso to accrue interest on their claims and to receive periodic interim distributions of such interest through the Effective Date or the withdrawal or revocation of the Modified Plan, subject to certain conditions and limitations set forth in the Modified Plan. To date, all such accrued interest payments to creditors have been made by El Paso on a timely basis. If, under certain circumstances, the Merger is not consummated, the Merger Agreement provides for CSW to pay El Paso for a portion of such interim interest payments paid or accrued prior to the termination of the Merger Agreement. The Merger Agreement also provides for CSW to pay for a portion of fees and expenses, including legal expenses of certain El Paso creditors under such circumstances. CSW's potential exposure as of December 31, 1994 is estimated to be approximately $17.5 million; however, the actual amount, if any, that CSW may be required to pay pursuant to these provisions depends on a number of contingencies and cannot presently be predicted.
On June 14, 1994, Las Cruces filed a motion with the Bankruptcy Court to lift the automatic stay imposed by the bankruptcy filing to allow it to (i) commence action against El Paso for failure to pay franchise fees after the expiration of its franchise agreement with Las Cruces in March 1994, (ii) enter El Paso's property to conduct an appraisal of the electric distribution system and any suitability studies, (iii) give notice of intent to file a condemnation action and (iv) commence state court condemnation proceedings against El Paso to condemn El Paso's distribution system within Las Cruces' city limits.
On June 29 and July 1, 1994, El Paso and CSW filed responses in the Bankruptcy Court opposing the Las Cruces motion. On August 1, 1994, CSW filed an amended response to the Las Cruces motion which states that the threat or actual commencement of condemnation proceedings by Las Cruces or the elimination of El Paso's service
2-54 to Las Cruces by condemnation or otherwise may constitute an El Paso material adverse effect, as defined in the Merger Agreement, the absence of which is a condition of CSW's obligation to consummate the Merger. The existence of an El Paso material adverse effect would preclude consummation of the Merger and the Modified Plan, unless CSW waives this condition in writing. CSW's amended response concludes that Las Cruces' intention to file a condemnation proceeding creates a situation that must be favorably resolved before the closing of the Merger.
By letter dated August 5, 1994, El Paso protested CSW's filing of the amended response and asserted its disagreement with CSW's position regarding Las Cruces as summarized above. In addition, El Paso asserted that CSW's filing of the amended response over El Paso's objection was contrary to the terms of the Merger Agreement.
On August 22, 1994, Las Cruces entered into a wholesale full requirements power contract with SPS to supply power to a municipal utility proposed to be established by Las Cruces. On August 30, 1994, voters in Las Cruces approved by nearly a two-to- one margin a referendum authorizing Las Cruces to proceed with efforts to acquire from El Paso, through negotiated purchase or condemnation proceedings, the electric utility system of El Paso within Las Cruces, including certain distribution, substation and associated transmission facilities.
On September 12, 1994, CSW delivered a response to El Paso's August 5 letter. In its September 12 letter, CSW reiterated its position that Las Cruces is a material element of CSW's bargain with El Paso and advised El Paso that the municipalization efforts in Las Cruces and other matters, including (i) the potential loss of other customers in El Paso's service area, including the Holloman Air Force Base and the White Sands Missile Range in New Mexico, (ii) cracking in steam generator tubes at Palo Verde, (iii) intense political and regulatory opposition to the Merger, and (iv) a new "comparable transmission service" standard being imposed on the Merger by the FERC, place the completion of the Merger in jeopardy. CSW's September 12 letter further advised El Paso that the foregoing matters, individually and cumulatively, constitute a material adverse effect or failure of other closing conditions under the Merger Agreement which, unless timely resolved in accordance with the Merger Agreement, will preclude closing of the proposed Merger.
Since CSW's September 12 letter, CSW has exchanged letters with El Paso and others regarding the interpretation of the Merger Agreement and the legal significance of the matters cited by CSW in its September 12 letter. Most of these letters are summarized below.
On September 14, 1994, CSW filed a second amended response to Las Cruces' motion to lift the stay in bankruptcy. In its second amended response, CSW stated that the intent and plan of Las Cruces to file a condemnation proceeding creates a situation that must be timely and favorably resolved by El Paso before the consummation of the Merger, whether or not the stay is modified or maintained. Further, CSW supported the maintenance of the stay as a means of avoiding disruption pending resolution of the Las Cruces dispute and because El Paso had taken the position that maintenance of the stay was in the best interests of the Merger and the El Paso estate and put El Paso in a better position to resolve the Las Cruces dispute.
By letter dated September 16, 1994, El Paso disagreed with the positions set forth by CSW in its September 12 letter and asserted that CSW's September 12 letter "had inflicted irreparable harm on El Paso and the Merger process."
On September 20, 1994, following a hearing on the June 14, 1994 motion of Las Cruces discussed above, the Bankruptcy Court judge indicated orally that, effective January 1, 1995, he would lift the bankruptcy stay on certain actions against El Paso and allow Las Cruces to pursue condemnation proceedings against El Paso with respect to the electric distribution system within Las Cruces under applicable New Mexico law. El Paso filed a motion seeking clarification of this oral ruling as to whether Las Cruces may
2-55 take immediate possession of the El Paso distribution system under the New Mexico condemnation statutes. On November 22, 1994, the Bankruptcy Court judge orally ruled that Las Cruces can commence condemnation proceedings but can not take possession of the distribution system when the stay is lifted until returning to the Bankruptcy Court and obtaining an order which permits that action.
By letter dated September 23, 1994, El Paso requested CSW's consent to meet with the City of Las Cruces to discuss the possibility of a resolution of El Paso's dispute with Las Cruces.
By letter dated October 3, 1994, CSW responded to El Paso's September 16 letter and reaffirmed the positions set forth in CSW's September 12 letter. In addition, CSW consented to El Paso's meeting with Las Cruces, but advised El Paso that CSW would not participate directly in negotiations between Las Cruces and El Paso.
By letter dated October 5, 1994, counsel to the El Paso Unsecured Creditors Committee, with the concurrence of certain other creditor groups, advised CSW that the committee disagreed with certain positions set forth in CSW's September 12 letter to El Paso. By letter dated October 27, 1994, CSW responded to and stated its disagreement with various statements set forth in the Unsecured Creditors Committee's letter.
By letter dated October 5, 1994, El Paso's New Mexico regulatory counsel asserted that CSW's September 12 letter had "adversely affected proceedings before the New Mexico Commission" relating to the Merger and that the letter "is being widely interpreted as a statement from CSW that the Merger will not close." By letter dated October 7, 1994, CSW's New Mexico regulatory counsel set forth CSW's disagreement with statements made in El Paso's New Mexico regulatory counsel's October 5 letter. The New Mexico Commission had delayed the New Mexico proceedings prior to September 12, 1994. On October 12, 1994, a New Mexico Commission hearing examiner held a prehearing conference covering scheduling and other matters. On October 14, 1994, CSW filed a Statement of Position and Request for Procedural Schedule in the New Mexico proceeding. El Paso filed a separate position statement in the New Mexico proceeding and advised CSW, by letter dated October 14, 1994, that CSW's statement of position did not "state a sufficiently clear and strong commitment by CSW to closing the Merger." By letter dated October 25, 1994, CSW's New Mexico regulatory counsel stated that the filing by El Paso of a separate position statement "impairs our ability to obtain necessary regulatory approvals from the New Mexico Commission on a timely basis by implying that there are severe problems in the relationship between El Paso and CSW." CSW's October 25 letter also stated that "the lack of a favorable resolution of Las Cruces municipalization efforts continues to not only prevent the closing of the Merger, but is also hindering our ability to obtain New Mexico regulatory approvals."
By letter dated October 18, 1994, El Paso reasserted its position that the Merger Agreement does not condition CSW's obligation to consummate the Merger on a favorable resolution of the Las Cruces situation. El Paso asserted it was not clear from CSW's October 3 letter whether CSW consented to El Paso's proposed discussion with Las Cruces and again requested CSW's consent to a meeting between El Paso and Las Cruces.
By letter dated October 27, 1994, CSW reaffirmed the positions taken in its September 12 and October 3 letters, and again consented to El Paso's meeting with Las Cruces and reiterated CSW's willingness to discuss with El Paso possible resolutions of the Las Cruces situation.
On October 11, 1994, the Bankruptcy Court granted an application by El Paso to employ special litigation counsel to advise El Paso as to ongoing activities with CSW and to assist El Paso as to the best means of preserving its rights. El Paso's application stated that special litigation counsel was needed to evaluate El Paso's rights, remedies and obligations with respect to CSW, the Plan and the Merger Agreement and to advise key officers of El Paso on a course of action to preserve and enforce El Paso's rights and remedies. The application also stated that special litigation
2-56 counsel "should also be in a position to conduct any litigation which may be necessary," and noted that another law firm then representing El Paso "would not be in a position to represent the Debtor in litigation against CSW." On October 28, 1994, CSW filed a response to El Paso's application, in which CSW stated that while it did not oppose El Paso's motion to employ special litigation counsel, the hiring and future use of litigation counsel may be incongruous with the goal of consummating the Merger. The response also stated that El Paso's Disclosure Statement, pursuant to which it obtained confirmation of its Plan of Reorganization, contained projections that explicitly assume the continuation of service to Las Cruces and two military installations in New Mexico.
By letter dated December 21, 1994, El Paso objected to CSW's motion filed with the New Mexico Commission to extend the procedural schedule by two-weeks. CSW responded to El Paso in a letter dated January 11, 1995, that CSW considered the short two week extension to be in the best interest of obtaining favorable and timely regulatory approval in New Mexico. The two weeks were to be used to facilitate efforts to narrow and resolve outstanding issues in the proceedings and thereby expedite the progress of those proceedings. El Paso restated its disagreement to CSW's motion for extension in a letter dated January 16, 1995.
By letter dated January 13, 1995, CSW recommended that El Paso object to a request by the Equity Committee to renew its engagement of Salomon Brothers as financial advisor to said committee. CSW stated that the Merger Agreement requires the parties to cooperate in limiting professional fees and that the cost and timing of the reengagement is inappropriate. By letter dated January 20, 1995, El Paso responded to CSW that the Equity Committee's request to reemploy Salomon is a direct consequence of CSW's September 12 letter to El Paso and that it supports the Equity Committee's application. El Paso subsequently filed a statement of support of the Equity Committee's request in the Bankruptcy Court. On February 6, 1995, the Equity Committee of El Paso filed a response in the Bankruptcy Court to objections made by other parties to its rehiring of financial advisors in which the committee accused CSW of taking moves to back out of the Merger Agreement, thereby causing harm to the equity holders.
On January 3, 1995, a PFD was issued by the presiding officers in the proceedings pending before the Texas Commission relating to the Merger. On January 17, 1995, CSW and El Paso filed joint exceptions to the proposed decision, stating, among other things, that, "in CSW's view, the rate relief recommended . . . falls far short of what is necessary for the consummation of the merger." That same day, CSW issued a press release describing the filing of the exceptions and repeating CSW's view that the terms of the proposed interim decision failed to provide sufficient revenue and adequate rate-making treatment for CSW to consummate the proposed Merger.
In a letter dated January 19, 1995, El Paso objected to the tenor of CSW's January 17 press release and claimed that CSW's press release harmed El Paso, its creditors, and shareholders and poisoned the regulatory approval process. CSW responded in a letter dated January 31 that it is El Paso's actions that have hindered obtaining the regulatory approvals necessary to consummate the Merger and that these actions were contrary to El Paso's obligations under the Merger Agreement. Further, CSW called on El Paso again to detail the steps it proposes to take to solve the problems identified by CSW in its September 12 letter cited in the PFD by the hearing examiners of the Texas Commission, and to desist from further actions which undercut CSW's efforts to obtain the rate relief, asset treatment and required regulatory approvals necessary to consummate the Merger.
On February 17, 1995, El Paso responded to CSW's January 31, 1995 letter stating that CSW's assertion that El Paso has breached the Merger Agreement are unfounded. El Paso further accused CSW of searching for a "viable contractual excuse" not to close the Merger.
2-57 On February 20, 1995, El Paso sent a letter to CSW inquiring whether CSW would consent to the sale of the Las Cruces service territory by El Paso and, if so, on what terms and at what price. In addition, the letter inquired whether CSW would consent to a rate reduction in New Mexico and, if so, at what percentage reduction over what period of time. CSW responded in a February 27, 1995 letter that CSW is unwilling to give up any more of the value it bargained for in the Merger Agreement, or to accept the risk of a litigated outcome with Las Cruces. However, CSW encouraged dialogue between El Paso and Las Cruces and stated it continues to support El Paso's efforts to resolve its dispute with Las Cruces. CSW stated it is amenable to considering any alternatives negotiated between Las Cruces and El Paso that would not deprive the Merger of further value and that would enable El Paso to continue to serve the Las Cruces service area or provide El Paso with full compensation for the loss of Las Cruces. CSW looks to El Paso to resolve this situation prior to consummation of the proposed Merger.
Texas Commission Applications On January 10, 1994, CSW and El Paso filed a joint application with the Texas Commission requesting a determination that the Merger is consistent with the public interest. As a part of the application, CSW proposed a three-step rate settlement plan, contingent upon the Texas Commission's approval of the Merger, that seeks to limit El Paso's proposed $41.4 million initial base rate increase for Texas customers, discussed below, to $25 million. In addition, the settlement rate plan proposed to reduce El Paso's fixed fuel factors by $12.8 million and refund $16.4 million from a one-time fuel reconciliation. As a result of the proposed annual reductions in fuel cost, El Paso's rates would not increase during the first year of the settlement plan. The settlement plan also provided for a three-year freeze on additional base rate increases, a limitation on the frequency of base rate increases following the rate freeze period through 2001 to not more than once every other year (i.e., 1997, 1999, and 2001), and a limitation on the amount of the 1997, 1999 and 2001 base rate increases to an amount not to exceed eight percent of total revenues. No party to the proceedings accepted CSW's rate settlement plan.
On January 10, 1994, El Paso separately filed with the Texas Commission for a base rate increase, exclusive of fuel, of approximately $41.4 million. The proposed rate increase represents what El Paso has stated it believes is supported under Texas law and prior Texas Commission orders, adjusted to reflect El Paso's proposed Merger with CSW. If the Texas Commission were to approve El Paso's request, the net effect would be to raise rates significantly higher than those proposed in the settlement plan.
On June 23, 1994, the El Paso City Council voted to reduce El Paso's rates $15.7 million following a recommendation from the City of El Paso's Public Utility Regulation Board. The City of El Paso's decision was appealed to the Texas Commission and consolidated with the rate case pending before that commission.
On June 24, 1994, the Staff filed testimony in the case before the Texas Commission recommending an increase in base rates of $17.1 million and taking the position that the proposed Merger is not in the public interest because of the possible cost increases to CSW's subsidiaries, which the Staff attributed to increased financial risk associated with the proposed acquisition of El Paso. The Staff's recommendation was revised and increased to a $21.5 million increase in base rates for El Paso in October 1994. In addition, the Staff determined that the proposed purchase price for El Paso is too high by $300 to $500 million and disagreed with the estimates of the Merger-related savings presented by CSW and El Paso in the case. Hearings at the Texas Commission began on July 20, 1994 and were completed in early November 1994.
Effective July 16, 1994, El Paso implemented under bond, a base rate increase of approximately $25 million annually for its Texas jurisdiction, which is subject to refund depending on the outcome of the rate case. The bonded increase in rates is authorized under PURA. Because of the current uncertainty as to the final outcome of the rate proceeding, El Paso has stated that it is deferring on its books the recognition of the revenues resulting from the increased rates.
2-58 On January 3, 1995, the Texas Commission presiding officers who heard El Paso's pending rate case and the CSW and El Paso Merger case filed their proposed interim decision with the Texas Commission. The presiding officers proposed an initial base-rate increase for El Paso of $21.2 million. The PFD recommends a determination by the Texas Commission that the Merger and the reacquisition of the leased Paso Verde assets are in the public interest and that the purchase price to be paid to El Paso's creditors and equity holders is fair, subject to satisfactory resolution of the Las Cruces and Palo Verde problems. The presiding officers found Merger related benefits ranging from $309 million to $379.4 million over the first ten years of the Merger which the presiding officers allocated to El Paso's customers under the PFD.
In addition to recommending the imposition of conditions in the determination that the Merger is in the public interest, the PFD failed to provide sufficient revenue and adequate rate-making treatment for CSW to consummate the proposed Merger. Specifically, the presiding officers propose to reduce El Paso's rates by allocating to customers certain potential tax benefits related to the payment of lease rejection damages on the leased Palo Verde assets. Reallocation of these tax benefits to customers effectively increases the acquisition cost to CSW by $133 million. The presiding officers attempted to mitigate the economic effect of their allocation of these tax benefits by allowing recovery through rates of an acquisition adjustment over the remaining 33 year life of Palo Verde. However, CSW believes that the proposed recovery through rates of an acquisition adjustment has considerably less economic value than the tax deductions. The presiding officers also recommended a reduction in El Paso's rate moderation plan and disallowance of El Paso's Palo Verde Unit 3 deferred accounting assets. CSW believes that, in recommending these rate treatments, the PFD fails to recognize rate relief to which El Paso is entitled under previous Texas Commission decisions in El Paso rate cases. Additionally, the PFD proposed an 11.5% return on equity rather than a 12.5% return which CSW believes is necessary for El Paso to have the opportunity to earn a reasonable return on its equity. Finally, the presiding officers proposed that the Texas Commission's interim order be conditioned on the successful resolution of the loss of Las Cruces as a customer of El Paso and on the successful resolution of the Palo Verde steam generator problems.
On March 3, 1995, the Texas Commission issued an interim order in the El Paso rate case and proposed Merger with CSW. The interim order found the proposed Merger to be in the public interest and provides for a $24.9 million base rate increase for El Paso. The interim order adopted most of the recommendations of the presiding officers. The most significant revision to the presiding officers recommendations was an increase in the allowed return on equity from 11.5% to 12%. The presiding officers' recommendations were adopted in the interim decision for several significant issues even though agreement was not reached by the Texas Commission. The interim decision allows for motions for reconsideration to be filed on these issues. The Texas Commission has indicated that the motions for reconsideration will be granted to allow for a consensus of the Texas Commission to be reached on these issues prior to the effective date of the merger. These issues included conditioning approval of the merger on resolution of the Las Cruces and Palo Verde issues, the rate treatment of the tax effects of lease rejection damages, recovery of any acquisition adjustment and deferred costs associated with the regulatory lag period prior to the rate treatment of Palo Verde Unit 3. Pending resolution of these issues, the Texas Commission allowed El Paso's bonded rates to remain in effect until a subsequent interim decision is issued.
The Texas Commission severed fuel related issues from the El Paso rate case and issued a final order which allows for El Paso to lower fixed fuel factors by $14.3 million annually and to refund $13.7 million in fuel costs over a twelve month period.
New Mexico Commission Application On March 14, 1994, CSW and El Paso filed an application with the New Mexico Commission seeking approval of the pending Merger, the reacquisition of the leased Palo Verde assets and certain accounting treatments. On February 10, 1995, the New Mexico Commission Staff filed testimony recommending approval of each of
2-59 these requests. El Paso plans to seek approval for the issuance of securities in connection with the Merger.
On October 27, 1994, the hearing examiner assigned to hear CSW and El Paso's Merger application before the New Mexico Commission issued an order amending the procedural schedule to provide for hearings beginning February 13, 1995. On December 21, 1994, the hearing examiner issued an order granting a two week extension to the procedural schedule, resulting in hearings beginning February 27, 1995. Hearings in New Mexico were completed on March 2, 1995. This revised schedule allows for the issuance of a final order by the New Mexico Commission by June 1995. However, CSW cannot predict when a final order may be issued by the New Mexico Commission.
FERC Applications On November 4, 1993, CSWS, as agent for the Electric Operating Companies and El Paso, filed an application with the FERC under Section 211 of the Federal Power Act seeking an order of the FERC and requiring SPS to provide firm and non-firm transmission services in connection with the transfers of power between PSO and El Paso in connection with the post-Merger coordinated operations of the Electric Operating Companies and El Paso. The intent of the transmission services is to obtain the benefits of integrated operations and thereby meet the requirement of the Holding Company Act that the Electric Operating Companies and El Paso be physically interconnected or capable of physical interconnection and economically operated as a single interconnected and coordinated electric system. SPS subsequently requested that the application be dismissed or, in the alternative, be set for hearing.
On January 10, 1994, as supplemented on January 13, 1994, CSWS, on behalf of the Electric Operating Companies and El Paso, filed a joint application with the FERC under Sections 203 and 205 of the Federal Power Act requesting approval by the FERC of the Merger. CSWS and El Paso have requested expedited consideration of the joint application. However, CSW cannot predict at this time when the FERC will issue a final decision on the joint application.
On August 1, 1994, the FERC issued orders in two proceedings that relate to the Merger. In an order issued under Section 211 of the Federal Power Act, the FERC preliminarily found that "a final order requiring SPS to provide the transmission service requested by the Applicants would comply with the statutory standards, once reliability concerns have been met." The FERC's order rejects assertions made by SPS that the FERC has no authority under Section 211 to order transmission service where the purpose of the service is to allow coordination of merging utilities' operations. The order directed SPS to perform studies so that the FERC can determine whether provision of the requested transmission service will unreasonably impair reliability. Such studies and supplemental pleadings analyzing the studies were filed with the FERC in early October and November 1994. If, after reviewing the studies and comments filed by SPS, CSWS and El Paso, the FERC concludes that reliability will not be unreasonably impaired, the FERC will issue a further "proposed order" requiring El Paso, CSWS and SPS to negotiate the rates, terms and conditions on which the requested transmission service will be provided.
The FERC also issued an order under Section 203 of the FPA in which the FERC ruled that it will require merging utilities to offer transmission service to others on a basis that is comparable to their own uses of their transmission systems. On August 10, 1994, CSW and El Paso notified the FERC that they will accept, as a condition to the FERC's approval of CSW's acquisition of El Paso, the requirement to amend their non-ERCOT transmission tariffs to offer "comparable service." On August 31, 1994, CSW and El Paso filed with the FERC a request for rehearing that, among other things, asks the FERC to reconsider the imposition of the comparable service requirement. On August 31, 1994, CSW and El Paso also filed the form of transmission tariffs they would propose to file with the FERC in order to meet the comparable service requirement if the requirement is upheld and the Merger is consummated. In agreeing to accept, as a condition to the Merger, the requirement that comparable service be provided over CSW's and El Paso's non-ERCOT transmission facilities, both CSW and El Paso
2-60 do not intend to waive or otherwise prejudice any of their rights, including but not limited to the right to seek rehearing of the order or any other order the FERC later enters in these proceedings. In addition, both CSW and El Paso do not intend to waive or otherwise prejudice their right under the FPA to seek judicial review of the order or any subsequent order or orders, if and to the extent CSW and El Paso deem such action necessary or advisable.
The FERC has not yet determined what "comparable service" is. However, the FERC said it will establish what uses PSO, SWEPCO and El Paso make of their own systems. The FERC will also examine likely costs and benefits of the Merger and determine whether the Merger is consistent with the public interest. The FERC has instructed one of its administrative law judges to issue an initial decision by April 14, 1995. A FERC administrative law judge established a procedural schedule whereby hearings began January 3, 1995. Hearings ended January 25, 1995, and the judge's initial decision is expected to be issued on or before April 5, 1995.
On November 15, 1994, the FERC trial staff filed its testimony in the Merger proceeding. The FERC staff determined that the proposed Merger will result in total savings of $414 million, $265 million in net present value for the period 1995 through 2004 of post-Merger operations. This compares to Merger savings projected by CSW for the same period of $420 million, or $280 million in net present value. The staff found $140.7 million in non-fuel O&M expense savings, $109.0 million in financial savings, and $15.3 million in production cost savings.
The FERC staff has recommended that approval of the Merger be made subject to two conditions. As required in the FERC's August 1, 1994 order, the merged companies must offer the use of their non- ERCOT transmission system to others under rates, terms and conditions comparable to the rates, terms and conditions under which CSW will use their non-ERCOT transmission system. The FERC staff has also recommended that the Merger be approved, conditioned on the existing CSW Operating Companies not being allocated any transmission costs associated with firm transmission service across SPS's system in excess of $24.6 million, which is the amount CSW projects through 2004.
The FERC staff also determined that "hold harmless conditions" proposed by various state utility commissions and other intervenors to protect CSW Operating Companies from certain potential effects of the Merger are unnecessary to assure that the Merger is in the public interest. The FERC staff concluded that:
As proposed, the Merger is beneficial to El Paso and is roughly neutral with respect to the four present CSW Operating Companies. If enacted as proposed, with the Applicants' voluntary offer to exclude Merger-related transmission expenses of non-affiliates from the transmission customers of CSW's four current Operating Companies, the Merger should not substantially harm any class of wholesale customers.
SEC Application On January 10, 1994, CSW filed with the SEC an application under the Holding Company Act seeking authorization of (i) the Merger and reacquisition of the Palo Verde leased assets, (ii) the issuance of securities by CSW and El Paso in connection with the Modified Plan and Merger and certain related transactions, and (iii) to engage in certain hedging transactions in connection with the Merger. CSW subsequently amended the application to eliminate the request for authorization to engage in certain hedging transactions, at the request of the SEC staff. CSW has subsequently amended and supplemented the application and has filed a brief in response to intervention petitions. CSW cannot predict what action the SEC will take with respect to the application, or when such action will be taken.
2-61 NRC Application On January 13, 1994, APS, as operating agent for Palo Verde, joined by El Paso, filed a request with the NRC for (i) consent to the indirect transfer of El Paso's interest in the operating licenses for Palo Verde Units 1, 2, and 3 that will occur as a result of the Merger, and (ii) to amend the operating licenses for Units 2 and 3 to delete provisions of those licenses related to El Paso's sale and leaseback transactions involving those units. The request to the NRC specifies that the proposed amendments to the operating licenses and consent become effective on the Effective Date, but CSW cannot predict at this time whether and, if so, when the approvals and consent will be granted.
Palo Verde The operating agent of Palo Verde, APS, discovered axial cracking in steam generator tubes in Unit 2 following a tube rupture in March 1993. APS began an ongoing examination and analysis of the tubes in each of the two steam generators in each unit of Palo Verde and, as a result, has identified axial cracking in Unit 3 and another more common type of cracking in the steam generator tubes of all three units. APS has indicated that it believes the axial cracking in Units 2 and 3 is due to the susceptibility of tube materials to a combination of deposits on the tubes and the relatively high temperatures at which all three units at Palo Verde are designed to operate. According to statements by APS and El Paso, the form of the degradation experienced in the steam generators is uncommon in the nuclear industry. APS has stated that it believes it can retard further tube degradation to acceptable levels by remedial actions, which include chemically cleaning the steam generators and performing analyses and adjustments that will allow the units to be operated at lower temperatures without appreciably reducing their power output. These analyses and adjustments have been performed on all three units, with each unit operating at 100% of capability. All remedial actions have been completed on each of the three units, except for chemically cleaning Unit 1 which is scheduled for April 1995. El Paso has stated that it is incurring increased maintenance costs related to the mid-cycle inspections of the steam generator tubes and the remedial actions being undertaken to retard tube degradation. El Paso also incurs additional costs for fuel and/or purchased power during periods in which one or more units are removed from service every 6 months for inspections. In its September 12, 1994 letter to El Paso, CSW stated that the significance of the tube cracking problems will have to be determined before CSW will close the Merger.
Other El Paso is subject to the informational requirements of the Securities and Exchange Act of 1934, as amended, and in accordance therewith files reports and other information with the SEC. See El Paso's Quarterly Reports on Form 10-Q, its Current Reports on Form 8-K and its Annual Report on Form 10-K and the documents referenced therein.
CSW continues to use its best efforts to consummate the Merger. At the same time, however, CSW continues to monitor contingencies which may preclude the consummation of the Merger, including without limitation the potential loss of significant portions of El Paso's service area and significant El Paso customers, including Las Cruces and two military installations, Holloman Air Force Base and White Sands Missile Range, regulatory risks principally related to approval of the Merger and El Paso's request for a rate increase in Texas as well as the effects of the conditions imposed by federal or state regulatory agencies on the approval of the Merger, and operating risks associated with the ownership of an interest in Palo Verde.
Based upon El Paso's written response to the concerns identified in CSW's September 12 letter and the failure of El Paso to resolve items set forth in the preceding paragraph, CSW cannot predict whether, and if so when, the Merger will be consummated. In the event that the proposed Merger is not consummated, there may be ensuing litigation between El Paso and CSW or among other parties to El Paso's bankruptcy proceedings and either or both of El Paso and CSW.
2-62 See MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Proposed Acquisition of El Paso, for further information.
Other Commitments and Contingencies
Construction It is estimated that the CSW System will spend approximately $385 million in construction expenditures during 1995. Substantial commitments have been made in connection with this construction expenditure program.
Fuel To supply a portion of the fuel requirements of the CSW System, the subsidiary companies have entered into various commitments for the procurement of fuel.
SWEPCO Henry W. Pirkey Power Plant In connection with the South Hallsville lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCO has agreed, under certain conditions, to assume the obligations of the mining contractor. As of December 31, 1994, the maximum amount SWEPCO would have to assume was $73.7 million. The maximum amount may vary as the mining contractor's need for funds fluctuates. The contractor's actual obligation outstanding at December 31, 1994 was $60.9 million.
South Hallsville Lignite Mine As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining at the South Hallsville lignite mine, SWEPCO has agreed to provide bond guarantees on mine reclamation in the amount of $70 million. Since SWEPCO uses self- bonding, the guarantee provides for SWEPCO to commit to use its resources to complete the reclamation in the event the work is not completed by the third party miner. The current estimate of cost to reclaim the mine is estimated to be approximately $25 million.
Coal Transportation SWEPCO has entered into various financing arrangements primarily with respect to coal transportation and related equipment, which are treated as operating leases for rate-making purposes. At December 31, 1994, leased assets of $46 million, net of accumulated amortization of $30.1 million, were included in electric plant on the balance sheet and at December 31, 1993, leased assets were $46 million, net of accumulated amortization of $26.8 million. Total charges to operating expenses for leases were $6.8 million, $7.1 million, and $6.9 million for the years 1994, 1993, and 1992.
Suspected MGP Site in Marshall, Texas SWEPCO owns a suspected former MGP site in Marshall, Texas. SWEPCO has notified the TNRCC that evidence of contamination has been found at the site. As a result of sampling conducted at the end of 1993 and early 1994, SWEPCO is evaluating the extent, if any, to which contamination has impacted soil, groundwater and other conditions in the area. A final range of clean-up costs has not yet been determined, but, based on a preliminary estimate, SWEPCO has accrued approximately $2 million as a liability for this site on SWEPCO's books as of December 31, 1993. As more information is obtained about the site, and SWEPCO discusses the site with the TNRCC, the preliminary estimate may change.
Suspected MGP Site in Texarkana, Texas and Arkansas and Shreveport, Louisiana SWEPCO also owns a suspected former MGP site in Texarkana, Texas and Arkansas. The EPA ordered an initial investigation of this site, as well as one in Shreveport, Louisiana, which is no longer owned by SWEPCO. The contractor who performed the investigations of these two sites recommended to the EPA that no further action be taken at this time.
2-63 Biloxi, Mississippi MGP Site SWEPCO has been notified by Mississippi Power Company that it may be a PRP at the former Biloxi MGP site formerly owned and operated by a predecessor of SWEPCO. SWEPCO is working with Mississippi Power Company to investigate the extent of contamination at this site. The MDEQ approved a site investigation work plan and, in January 1995, SWEPCO and Mississippi Power Company initiated sampling pursuant to that work plan. On an interim basis, SWEPCO and Mississippi Power Company are each paying fifty percent of the cost of implementing the site investigation work plan. That interim allocation is subject to a final allocation in the future. SWEPCO and Mississippi Power Company are investigating whether there are other PRPs at the Biloxi site. Until the extent of the contamination at the Biloxi site is identified, it is unknown what, if any, additional investigation or cleanup may be required.
Management does not expect these matters to have a material effect on CSW's consolidated results of operations or financial position.
WTU WTU has a sale/leaseback agreement with Transok for full capacity use of a natural gas pipeline to WTU's Ft. Phantom generating plant. The lease agreement also provides for full capacity use of Transok's natural gas pipelines serving WTU's San Angelo and Oak Creek generating plants. The initial terms of the agreement are for twelve years with renewable options thereafter.
CPL Nuclear Insurance In connection with the licensing and operation of STP, the owners have purchased the maximum limits of nuclear liability insurance, as required by law, and have executed indemnification agreements with the NRC in accordance with the financial protection requirements of the Price-Anderson Act.
The Price-Anderson Act, a comprehensive statutory arrangement providing limitations on nuclear liability and governmental indemnities, is in effect until August 1, 2002. The limit of liability under the Price-Anderson Act for licensees of nuclear power plants is $8.92 billion per incident, effective as of January 1995. The owners of STP are insured for their share of this liability through a combination of private insurance amounting to $200 million and a mandatory industry-wide program for self-insurance totaling $8.72 billion. The maximum amount that each licensee may be assessed under the industry-wide program of self-insurance following a nuclear incident at an insured facility is $75.5 million per reactor, which may be adjusted for inflation plus a five percent charge for legal expenses, but not more than $10 million per reactor for each nuclear incident in any one year. CPL and each of the other STP owners are subject to such assessments, which CPL and other owners have agreed will be allocated on the basis of their respective ownership interests in STP. For purposes of these assessments, STP has two licensed reactors.
The owners of STP currently maintain on-site decontamination liability and property damage insurance in the amount of $2.75 billion provided by ANI and NEIL. Policies of insurance issued by ANI and NEIL stipulate that policy proceeds must be used first to pay decontamination and clean-up costs before being used to cover direct losses to property. Under project agreements, CPL and the other owners of STP will share the total cost of decontamination liability and property insurance for STP, including premiums and assessments, on a pro rata basis, according to each owner's respective ownership interest in STP.
CPL purchases, for its own account, a NEIL I Business Interruption and/or Extra Expense policy. This insurance will reimburse CPL for extra expenses incurred, up to $1.65 million per week, for replacement generation or purchased power as the result of a covered accident that shuts down production at STP for more than 21 weeks. The maximum amount recoverable for Unit 1 is $111.3 million and for Unit 2 is $111.8 million. CPL is subject to an additional assessment up to $2.1 million for the current policy
2-64 year in the event that losses as a result of a covered accident at a nuclear facility insured under the NEIL I policy exceeds the accumulated funds available under the policy.
On August 28, 1994, CPL filed a claim under the NEIL I policy related to the outage at STP Units 1 and 2. NEIL is currently reviewing the claim. CPL management is unable to predict the ultimate outcome of this matter.
CSWE CSWE has provided construction services to the Mulberry cogeneration facility through a wholly-owned subsidiary, CSW Development-I, Inc. The project achieved commercial operation in August 1994 and added 117 MWs of on-line capacity of which CSWE owns 50%. CSWE's maximum potential liability under the fixed price contract is $83 million and will decrease to zero over the next two years as contractual standards are met. Additionally, CSW Development-I, Inc. has entered into a fixed price contract to construct the Mulberry thermal host facility. The maximum potential liability under this fixed price contract is $14 million. The thermal host facility is expected to be completed by the first quarter of 1995. CSW has provided additional guarantees to the project totaling approximately $57 million.
CSWE has entered into a purchase agreement on the Ft. Lupton project to provide $79.5 million of equity upon the occurrence of certain events. As of January 9, 1995, $43 million has been paid. CSWE has provided three letters of credit to the project totaling $14.3 million. During March 1995, CSWE closed permanent project financing on the Ft. Lupton facility in the amount of $208 million.
CSWE has committed to provide up to $125 million of construction financing to the Orange cogeneration project in which CSWE owns a 50% interest. Of this total, CSWE has provided $62 million at December 31, 1994. CSWE expects to obtain third party permanent financing for this project in 1995.
In November 1994, CSWE transferred its 50% interest in the 40 MW Oildale cogeneration facility to two non-affiliated third parties, Oildale Holdings, Inc. and Oildale Holdings II, Inc. The Oildale project, which was financed with third party non-recourse project financing, had been in default of certain provisions of its loan agreement since December 1993. Under the terms of the project transfer, CSWE contributed $3 million in equity in exchange for the return of a letter of credit in the same amount in favor of a third party lender.
In addition, CSWE has posted security deposits and other security instruments of approximately $14 million on six additional projects in various stages of development, construction, and operation.
2-65 12. Business Segments CSW's business segments include electric utility operations (CPL, PSO, SWEPCO, WTU), and gas operations (Transok). Seven non- utility companies are included in corporate items (CSWE, CSWI, CSW Communications, CSW Credit, CSW Leasing, CSWS and CSW). CSW's business segment information follows: 1994 1993 1992 (millions) Operating Revenues Electric $ 3,065 $ 3,055 $ 2,790 Gas 518 603 496 Corporate items and other 40 29 3 $ 3,623 $ 3,687 $ 3,289 Operating Income Electric $ 728 $ 559 $ 694 Gas 49 25 42 Corporate items and other 6 5 1 Total operating income before taxes 783 589 737 Income taxes 189 132 149 $ 594 $ 457 $ 588 Depreciation and Amortization Electric $ 316 $ 296 $ 284 Gas 32 29 22 Corporate items and other 8 5 5 $ 356 $ 330 $ 311 Identifiable Assets Electric $ 9,066 $ 8,927 $ 8,575 Gas 724 684 674 Corporate items and other 1,119 993 580 $10,909 $10,604 $ 9,829 Capital expenditures and acquisitions Electric $ 493 $ 481 $ 325 Gas 65 88 101 Corporate items and other (1) 114 64 31 $ 672 $ 633 $ 457
(1) Includes CSWE Equity Investments.
2-66 13. Quarterly Information (Unaudited) The following unaudited quarterly information includes, in the opinion of management, all adjustments necessary for a fair presentation of such amounts. Earnings per Share Operating Operating Net of Common Quarter Ended Revenues Income Income Stock (millions) March 31 $ 850 $ 93 $ 48 $0.23 June 30 908 157 107 0.55 September 30 1,070 239 189 0.97 December 31 795 105 68 0.33 $3,623 $ 594 $ 412 $2.08
March 31 $ 810 $ 97 $ 92 $0.47 June 30 894 144 96 0.48 September 30 1,140 219 181 0.93 December 31 843 (3) (42) (0.25) $3,687 $ 457 $ 327 $1.63
Information for quarterly periods is affected by seasonal variations in sales, rate changes, timing of fuel expense recovery and other factors.
2-67 Report of Independent Public Accountants
To the Stockholders and Board of Directors of Central and South West Corporation:
We have audited the accompanying consolidated balance sheets of Central and South West Corporation (a Delaware corporation) and subsidiary companies, as of December 31, 1994 and 1993, and the related consolidated statements of income, retained earnings and cash flows, for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Central and South West Corporation and subsidiary companies as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
In 1993, as discussed in NOTE 1, Central and South West Corporation and subsidiary companies changed their methods of accounting for unbilled revenues, postretirement benefits other than pensions, income taxes and postemployment benefits.
Our audits were made for the purpose of forming an opinion on the financial statements taken as a whole. The supplemental Schedule II is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Arthur Andersen LLP
Dallas, Texas February 13, 1995
2-68 Report of Management
Management is responsible for the preparation, integrity and objectivity of the consolidated financial statements of Central and South West Corporation and subsidiary companies as well as other information contained in this Annual Report. The consolidated financial statements have been prepared in conformity with generally accepted accounting principles applied on a consistent basis and, in some cases, reflect amounts based on the best estimates and judgments of management, giving due consideration to materiality. Financial information contained elsewhere in this Annual Report is consistent with that in the consolidated financial statements.
The consolidated financial statements have been audited by the independent accounting firm, Arthur Andersen LLP, which was given unrestricted access to all financial records and related data, including minutes of all meetings of stockholders, the board of directors and committees of the board. CSW and its subsidiaries believe that representations made to the independent auditors during their audit were valid and appropriate. Arthur Andersen LLP's audit report is presented elsewhere in this report.
CSW, together with its subsidiary companies, maintains a system of internal controls to provide reasonable assurance that transactions are executed in accordance with management's authorization, that the consolidated financial statements are prepared in accordance with generally accepted accounting principles and that the assets of CSW and its subsidiaries are properly safeguarded against unauthorized acquisition, use or disposition. The system includes a documented organizational structure and division of responsibility, established policies and procedures including a policy on ethical standards which provides that the companies will maintain the highest legal and ethical standards, and the careful selection, training and development of our employees.
Internal auditors continuously monitor the effectiveness of the internal control system following standards established by the Institute of Internal Auditors. Actions are taken by management to respond to deficiencies as they are identified. The board, operating through its audit committee, which is comprised entirely of directors who are not officers or employees of CSW or its subsidiaries, provides oversight to the financial reporting process.
Due to the inherent limitations in the effectiveness of internal controls, no internal control system can provide absolute assurance that errors will not occur. However, management strives to maintain a balance, recognizing that the cost of such a system should not exceed the benefits derived.
CSW and its subsidiaries believe that, in all material respects, its system of internal controls over financial reporting and over safeguarding of assets against unauthorized acquisition, use or disposition functioned effectively during 1994.
E. R. Brooks Glenn D. Rosilier Wendy G. Hargus Chairman, President and Senior Vice President and Controller Chief Executive Officer Chief Financial Officer
2-70
CPL
CENTRAL POWER AND LIGHT COMPANY Selected Financial Data CPL The following selected financial data for each of the five years ended December 31 are provided to highlight significant trends in the financial condition and results of operations for CPL.
1994 1993 1992 1991 1990 (thousands, except ratios) Electric Operating Revenues $1,217,979 $1,223,528 $1,113,423 $1,098,730 $ 948,520 Income Before Cumulative Effect of Changes in Accounting Principles 205,439 145,130 218,511 217,206 204,870 Cumulative Effect of Changes in Accounting Principles (1) -- 27,295 -- -- -- Net Income 205,439 172,425 218,511 217,206 204,870 Preferred Stock Dividends 13,804 14,003 16,070 19,844 23,528 Net Income for Common Stock 191,635 158,422 202,441 197,362 181,342
Total Assets (2) 4,822,699 4,781,745 4,583,660 4,458,063 4,516,375
Common Stock Equity 1,431,354 1,424,195 1,437,876 1,428,547 1,449,409 Preferred Stock Not Subject to Mandatory Redemption 250,351 250,351 250,351 250,351 250,351 Subject to Mandatory Redemption -- 22,021 28,393 35,331 40,584 Long-term Debt 1,466,393 1,362,799 1,347,887 1,350,854 1,346,587
Ratio of Earnings to Fixed Charges (SEC Method) Before Cumulative Effect of Changes in Accounting Principles 3.24 2.69 3.23 3.18 3.11
Capitalization Ratios Common Stock Equity 45.5% 46.6% 46.9% 46.6% 47.0% Preferred Stock 7.9 8.9 9.1 9.3 9.4 Long-term Debt 46.6 44.5 44.0 44.1 43.6
(1) The 1993 cumulative effect relates to the changes in accounting for unbilled revenues and adoption of SFAS No. 112. See NOTE 1, Summary of Significant Accounting Policies.
(2) The 1992-1990 total assets have been reclassified to reflect the effects of the adoption in 1993 of SFAS No. 109. See NOTE 2, Federal Income Taxes.
CPL changed its method of accounting for unbilled revenues in 1993. Pro forma amounts, assuming that the change in accounting for unbilled revenues had been adopted retroactively, are not materially different from amounts reported for prior years and therefore has not been restated.
2-71 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CENTRAL POWER AND LIGHT COMPANY
Reference is made to CPL's Financial Statements and related Notes and Selected Financial Data. The information contained therein should be read in conjunction with, and is essential in understanding, the following discussion and analysis.
Overview Net income for common stock for 1994 increased 21% to $192 million from $158 million in 1993. The increase was due primarily to an increase in base revenues, a decrease in restructuring costs and a decrease in maintenance expense. Such increases were partially offset by the cumulative effect of changes in accounting principles recorded in 1993.
Restructuring As previously reported, CPL has taken steps to implement a restructuring and early retirement program designed to consolidate and restructure its operations in order to meet the challenges of the changing electric utility industry and to compete effectively in the years ahead. The underlying goal of the restructuring is to enable CPL to focus on and be accountable for serving the customer. The restructuring costs were initially estimated to be $29 million and were expensed in 1993. The final costs of the restructuring were approximately $29 million. Approximately $28 million of the restructuring expenditures were incurred during 1994, with the remaining $1 million expected to be incurred during 1995. Approximately $4 million of the restructuring expenses relate to employee termination benefits, $15 million relate to enhanced benefit costs and $10 million relate to employees that will not be terminated. Approximately $21 million of the restructuring costs were paid from or will be paid from general corporate funds. The remaining $8 million represents the present value of enhanced benefit amounts to be paid from the benefit plan trusts to participants over future years in accordance with the early retirement program. The cost of these enhanced benefit amounts will be paid from general corporate funds to the benefit plan trusts over future years. The restructuring is substantially completed, with the remaining activity to take place during 1995. Certain aspects of the restructuring are pending SEC approval under the Holding Company Act.
CPL expects to realize a number of benefits from the restructuring. Beginning in 1994 and continuing into the future, increased efficiencies and synergies are expected to be realized with the elimination of previously duplicated functions. This leads to enhanced communication and efficiency, which should translate into a reduction in the rate of growth in O&M costs. The CSW System expects that all restructuring costs will be recovered by early 1996 with reductions in the rate of growth of O&M costs continuing thereafter.
STP Introduction CPL owns 25.2% of STP, a two-unit nuclear power plant which is located near Bay City, Texas. In addition to CPL, HLP, the Project Manager, owns 30.8%, San Antonio owns 28.0%, and Austin owns 16.0%. STP Unit 1 was placed in service in August 1988 and STP Unit 2 was placed in service in June 1989.
From February 1993 until May 1994, STP experienced an unscheduled outage which has resulted in significant rate and regulatory proceedings involving CPL. These matters, including a base rate case and fuel reconciliation proceedings, are discussed immediately below.
STP Outage In February 1993, Units 1 and 2 of STP were shut down by HLP in an unscheduled outage resulting from mechanical problems. HLP determined that the units would not be restarted until the equipment failures had been corrected and the NRC was briefed on the causes of
2-72 these failures and the corrective actions that were taken. The NRC formalized that commitment in a confirmatory action letter that it supplemented to identify additional issues to be resolved and verified by the NRC before STP could be restarted.
During the outage, the necessary improvements were made by HLP to address the issues in the confirmatory action letter, as supplemented. On February 15, 1994, the NRC agreed that the confirmatory action letter issues had been resolved with respect to Unit 1, and that it agreed with HLP's recommendation that Unit 1 was ready to restart. Unit 1 restarted on February 25, 1994 and reached 100% power on April 8, 1994. Subsequently, the issues with respect to Unit 2 were resolved and the NRC on May 17, 1994 agreed with HLP's recommendation to restart Unit 2. Unit 2 resumed operation on May 30, 1994 and reached 100% power on June 16, 1994. During 1994, Unit 1 and Unit 2 achieved annual net capacity factors of 75.3% and 54.7%, respectively. During the last six months of 1994, the STP units operated at capacity factors of 98.6% for Unit 1 and 99.2% for Unit 2.
In June 1993, the NRC placed STP on its "watch list" of plants with "weaknesses that warrant increased NRC attention." The decision to place STP on the watch list followed the June 1993 issuance of a report by an NRC Diagnostic Evaluation Team which conducted a review of STP operations.
On February 3, 1995, the NRC removed STP from the "watch list". The NRC noted that the four key areas for their decision were sustained improvement throughout 1994, high standards of performance exhibited by the plant, effective maintenance and engineering support resulting in reduced equipment repair backlogs and improved plant reliability, and the open and positive employee climate at the plant. With the NRC reviewing the "watch list" status every 6 months and with Unit 2 achieving 100% power in June of 1994, the February review was the first realistic opportunity for STP to be considered for a change in status. On average, plants previously placed on the "watch list" have stayed on the list for 29 months.
Rates and Regulatory Matters CPL Rate Inquiry Several Cities, the Texas Commission General Counsel and others initiated actions in late 1993 and early 1994 which, if approved by the Texas Commission, would lower CPL's base rates. The requests for a review of CPL's rates arose out of the unscheduled outage at STP which began in February 1993. The STP outage did not affect CPL's ability to meet customer demand because of existing capacity and CPL's purchase of additional energy.
CPL submitted an RFP on July 1, 1994, to the Texas Commission justifying its current base rate structure. Parties to CPL's base rate case have filed testimony with the Texas Commission recommending reductions in CPL's retail base rates of up to $147 million annually, resulting from a combination of proposed rate base and cost of service reductions, as well as a rate base disallowance of up to $400 million.
The Texas Commission held hearings in November and December 1994, and all parties have filed briefs in the case. The ALJ is expected to issue a recommended order for consideration by the Texas Commission in April 1995 with a final order from the Texas Commission expected in May 1995. Testimony filed by parties to the rate case, including the Staff, is not binding on either the ALJ or the Texas Commission.
CPL continues to maintain that its rates are reasonable and that its earnings are within established regulatory guidelines. In addition, CPL strongly believes that 100 percent of its investment in both units of STP belongs in rate base. This belief is based on, among other factors, Units 1 and 2 providing output at high capacity factors since April and June 1994, respectively. In addition, the long-term benefits nuclear generation provides to customers further support their inclusion in rate base. Furthermore, there are no Texas Commission precedents addressing the removal of a nuclear plant from rate base as a performance disallowance. Assuming both units of STP are included in rate base, CPL believes it is not collecting excessive revenues, notwithstanding that market rates of return on
2-73 common equity are generally lower today than they were in 1990 and 1991, when CPL's base rates were last set.
CPL Fuel Pursuant to the substantive rules of the Texas Commission, CPL generally is allowed to recover its fuel costs through a fixed fuel factor. These fuel factors are in the nature of temporary rates, and CPL's collection of revenues by such fuel factors is subject to adjustment at the time of a fuel reconciliation proceeding before the Texas Commission. The difference between fuel revenues billed and fuel expense incurred is recorded as an addition to or a reduction from revenues, with a corresponding entry to unrecovered fuel costs or other current liabilities, as appropriate. Any fuel costs, not limited to under- or over-recoveries, which the Texas Commission determines as unreasonable in a reconciliation proceeding are not recoverable from customers.
CPL is currently involved in two proceedings before the Texas Commission relating to the recovery of fuel and purchased power costs. CPL originally filed Docket No. 12154 seeking approval of a customer surcharge to recover fuel and purchased power costs, including those resulting from the STP outage. In Docket No. 13126, the Texas Commission General Counsel and others are reviewing the prudence of management activities at STP. In November 1994, CPL filed a fuel reconciliation case in Docket No. 13650 with the Texas Commission seeking to reconcile fuel costs since March 1, 1990, including the period during which CPL's fuel and purchased power costs were increased due to the STP outage. At December 31, 1994, CPL's under-recovered fuel balance was $54.1 million, exclusive of interest, which was due primarily to the STP outage. If a significant portion of the fuel costs were disallowed by the Texas Commission, CPL could experience a material adverse effect on its results of operations in the year of disallowance but not on its financial condition. Finally, in Docket No. 13126, the Texas Commission General Counsel is reviewing the prudence of management activities at STP. On January 4, 1995, Docket No. 12154 was consolidated into Docket No. 13650. The results of the prudence inquiry in Docket No. 13126 are expected to be incorporated into the fuel reconciliation proceedings in Docket No. 13650.
CPL continues to negotiate with the intervening parties to resolve these matters through settlement. However, no settlement has been reached to date.
Management cannot predict the ultimate outcome of the CPL rate inquiry and CPL fuel regulatory proceedings. However, management believes that the ultimate resolution of the various issues will not have a material adverse effect on CPL's results of operations or financial condition.
See NOTE 9, Litigation and Regulatory Proceedings - STP, for a discussion of regulatory proceedings arising out of the STP outage and background on STP rate orders and deferred accounting.
Nuclear Decommissioning CPL's decommissioning costs are accrued and funded to an external trust over the expected service life of the STP units. The existing NRC operating licenses will allow the operation of STP Unit 1 until 2027, and Unit 2 until 2028. The accrual is an annual level cost based on the estimated future cost to decommission STP, including escalations for expected inflation to the expected time of decommissioning and is net of expected earnings on the trust fund.
The staff of the SEC has questioned certain of the current accounting practices of the electric utility industry regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations. In response to these questions, FASB has agreed to review the accounting for removal costs, including decommissioning. If current electric utility industry accounting practices for such decommissioning are changed, (i) annual provisions for decommissioning could increase, (ii) the estimated cost for decommissioning could be recorded as a liability rather than as accumulated depreciation, and (iii) trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense.
2-74 See NOTE 1, Summary of Significant Accounting Policies - Nuclear Decommissioning, for further information regarding CPL's decommissioning of STP.
New Accounting Standards SFAS No. 115 was effective for fiscal years beginning after December 15, 1993. CPL adopted SFAS No. 115 in 1994. The adoption of SFAS No. 115 did not have a material effect on CPL's results of operations or financial condition.
In June 1993 the FASB issued SFAS No. 116. The statement, effective for fiscal years beginning after December 15, 1994, will be adopted by CPL for 1995. The statement establishes accounting standards for contributions and applies to all entities that receive or make contributions. Management does not believe the adoption of SFAS No. 116 will have a material impact on CPL's results of operations or financial condition.
SFAS No. 119 was effective for fiscal years ending after December 15, 1994. CPL does not currently use derivative instruments, but may use these instruments in the future to manage the increased market risks associated with greater competition in the electric utility industry. The adoption of this new statement had no material effect on CPL's results of operations or financial condition.
Liquidity and Capital Resources Overview CPL's need for capital results primarily from its construction of facilities to provide reliable electric service to its customers. Accordingly, internally generated funds should meet most of the capital requirements. However, if internally generated funds are not sufficient, CPL's financial condition should allow it access to the capital markets.
Capital Expenditures Construction expenditures, including AFUDC, were approximately $178 million in 1994, $180 million in 1993, and $102 million in 1992. It is estimated that construction expenditures, including AFUDC, during the 1995 through 1997 period will aggregate $357 million. Such expenditures primarily will be made to improve and expand distribution facilities. These improvements are expected to meet the needs of new customers and to satisfy changing requirements of existing customers. No new baseload power plants are currently planned until after year 2000.
The construction program continues to be monitored, reviewed and adjusted to reflect changes in estimated load growth in CPL's service area, variations in prices of alternative fuel sources, the cost of labor, materials, equipment and capital, and other external factors.
The CSW System facilities plan presently includes projected coal- and lignite-fired generating plants for which CPL has invested approximately $21 million in prior years for plant sites, engineering studies and lignite reserves. Should future plans exclude these plants for environmental or other reasons, CPL would evaluate the probability of recovery of these investments and may record appropriate reserves.
Long-Term Financing As of December 31, 1994, the capitalization ratios of CPL were 45% common stock equity, 8% preferred stock and 47% long-term debt. CPL continually monitors the capital markets for opportunities to lower its cost of capital through refinancing. CPL continues to be committed to maintaining financial flexibility by maintaining a strong capital structure and favorable securities ratings which should allow funds to be obtained from the capital markets when required.
2-75 CPL's long-term financing activity for 1994 is summarized as follows:
In May, CPL issued $100 million of 7-1/2% First Mortgage Bonds, Series JJ, due May 1, 1999. Net proceeds were used to repay a portion of CPL's short-term borrowings.
In July and August, CPL reacquired $0.6 million of 9-3/8% First Mortgage Bonds, Series Z, due December 1, 2019. The funds required for this transaction were provided from internal sources.
In August, CPL retired $22.4 million, all remaining shares outstanding, of its 10.05% Series Preferred Stock. The funds required for this transaction were provided from internal sources and short- term borrowings.
CPL has $260 million remaining for the issuance of first mortgage bonds under a shelf registration statement filed with the SEC in 1993. CPL may offer additional first mortgage bonds subject to market conditions and other factors. The proceeds of any such offerings will be used principally to redeem higher cost first mortgage bonds in order to lower CPL's embedded cost of debt.
CPL has $75 million available for issuance of preferred stock under a shelf registration statement filed with the SEC in March 1994. CPL may offer preferred stock subject to market conditions and other factors. The proceeds of any such offerings will be used principally to redeem higher cost preferred stock and to repay short-term debt.
Short-Term Financing CPL, together with other members of CSW System, has established a CSW System money pool to coordinate short-term borrowings. These loans are unsecured demand obligations at rates approximating the CSW System's commercial paper borrowing costs. CPL's short-term borrowing limit from the money pool is $300 million. During 1994, the annual weighted average interest rate was 4.5% and the average amount of short- term month-end borrowings outstanding was $129 million. The maximum amount of short-term borrowings outstanding at any month-end during 1994 was $232 million, which was the amount outstanding at February 28, 1994.
Internally Generated Funds Internally generated funds consist of cash flows from operating activities less common and preferred stock dividends. CPL uses short- term debt to meet fluctuations in working capital requirements due to the seasonal nature of energy sales. CPL anticipates that capital requirements for the period 1995 to 1997 will be met, in large part, from internal sources. CPL also anticipates that some external financing will be required during the period, but the nature, timing and extent have not yet been determined. Information concerning internally generated funds follows:
1994 1993 1992 (millions) Internally Generated Funds $114 $92 $95
Construction Expenditures Provided by Internally Generated Funds 65% 52% 94%
Sales of Accounts Receivable CPL sells its billed and unbilled accounts receivable, without recourse, to CSW Credit. The sales provided CPL with cash immediately, thereby reducing working capital needs and revenue requirements. The average and year end amounts of accounts receivable sold were $121.9 million and $113.5 million in 1994, as compared to $112.3 million and $105.8 million in 1993.
2-76 Recent Developments and Trends Competition and Industry Challenges Competitive forces at work in the electric utility industry are impacting CPL and electric utilities generally. Increased competition facing electric utilities is driven by complex economic, political and technological factors. These factors have resulted in legislative and regulatory initiatives that are likely to result in even greater competition at both the wholesale and retail level in the future. As competition in the industry increases, CPL will have the opportunity to seek new customers and at the same time be at risk of losing customers to other competitors. CPL believes that its prices for electricity and the quality and reliability of its service currently places it in a position to compete effectively in the marketplace.
The Energy Policy Act, which was enacted in 1992, significantly alters the way in which electric utilities compete. The Energy Policy Act creates exemptions from regulation under the Holding Company Act and permits utilities, including registered utility holding companies and non-utility companies, to form EWGs. EWGs are a new category of non-utility wholesale power producer that are free from most federal and state regulation, including the principal restrictions of the Holding Company Act. These provisions enable broader participation in wholesale power markets by reducing regulatory hurdles to such participation. The Energy Policy Act also allows the FERC, on a case- by-case basis and with certain restrictions, to order wholesale transmission access and to order electric utilities to enlarge their transmission systems. A FERC order requiring a transmitting utility to provide wholesale transmission service must include provisions generally that permit (i) the utility to recover from the FERC applicant all of the costs incurred in connection with the transmission services and (ii) any enlargement of the transmission system and associated services. While CPL believes that the Energy Policy Act will continue to make the wholesale markets more competitive, CPL is unable to predict the extent to which the Energy Policy Act will impact its operations.
Increasing competition in the utility industry brings an increased need to stabilize or reduce rates. The retail regulatory environment is beginning to shift from traditional rate base regulation to incentive regulation. Incentive rate and performance- based plans encourage efficiencies and increased productivity while permitting utilities to share in the results. Retail wheeling, a major industry issue which may require utilities to "wheel" or move power from third parties to their own retail customer, is evolving gradually.
Wholesale energy markets, including the market for wholesale electric power, have been extremely competitive since the enactment of the Energy Policy Act. CPL competes in the wholesale energy markets with other public utilities, cogenerators, qualified facilities, exempt wholesale generators and others for sales of electric power.
Under the Energy Policy Act, the FERC has approved several proposals by utility companies to sell wholesale power at market-based rates and provide to electric utilities "open access" to transmission systems, subject to certain requirements. The adoption of these proposals increases marketing opportunities for electric utilities, but also exposes them to the risk of loss of load or reduced revenues due to competition with alternative suppliers.
CPL believes that, compared to other electric utilities, it is well positioned to meet future competition. CPL benefits from economies of scale and scope by virtue of its size and its relationship to the CSW System. Moreover, CPL is taking steps to enhance its marketing and customer service, reduce costs, improve and standardize business practices, and grow through strategic acquisitions, in order to position itself for increased competition in the future.
CPL is unable to predict the ultimate outcome or impact of competitive forces on the electric utility industry or on CPL. As the wholesale and retail electricity markets become more competitive, however, the principal factor determining success is likely to be price, and to a lesser extent, reliability, availability of capacity, and customer service.
2-77 Public Utility Regulatory Act PURA is the legal foundation for electric utility regulation in Texas. PURA will expire on September 1, 1995, in accordance with the sunset policy of the Texas Legislature, which applies to all state agencies, unless the Texas Legislature reenacts PURA in its current form or in modified form. Several proposals have been made to amend PURA which, among other things, provide for a market-driven integrated resource planning process, pricing flexibility for utilities faced with competitive challenges, incentive regulation and deregulation of the wholesale bulk power market in ERCOT. CPL is unable to predict the ultimate outcome of the 1995 session of the Texas Legislature and in particular whether amendments to PURA will be adopted. If, however, the Texas Legislature passes legislation permitting any form of retail wheeling, such legislation could have an adverse impact on CPL and CPL's sales to its retail customers.
Regulatory Accounting Consistent with industry practice and the provisions of SFAS No. 71, which allows for the recognition and recovery of regulatory assets, CPL has recognized significant regulatory assets and liabilities. Management believes that CPL will continue to meet the criteria for following SFAS No. 71. However, in the event CPL no longer meets the criteria for following SFAS No. 71, a write-off of regulatory assets and liabilities would be required. For additional information regarding SFAS No. 71 reference is made to NOTE 1, Summary of Significant Accounting Policies - Regulatory Assets and Liabilities.
Consolidated Taxes The Texas Commission before 1992 allowed income taxes to be recovered in rates based on the federal income tax incurred by a utility as if it were a stand-alone company. This stand-alone approach treated the regulated activities of a utility as a separate entity and considered only those revenues and expenses that are included in the utility's cost of service to calculate the federal income tax liability for ratemaking purposes.
Beginning in 1992, the Texas Commission changed its method of calculating the federal income tax component of rates to the "actual tax approach." The actual tax approach is an evolving concept but generally seeks to reflect in rates the actual tax liability of the utility irrespective of its relationship to the utility's cost of service. The approach reduces rates by the tax benefits of deductions which are not considered for or included in setting rates for the utility.
The Texas Commission is expected to use the actual tax approach for calculating the recovery of federal income tax in the pending rate case for CPL. The impact of the actual tax approach on the prospective rates for CPL cannot be determined since the application of the concept is unsettled.
CPL believes that the recovery of federal income taxes in rates should be determined on the stand-alone approach for ratemaking purposes, but there is no assurance this approach will be adopted in the pending CPL rate case.
Environmental Matters CERCLA and Related Matters The operations of CPL, like those of other utilities, generally involve the use and disposal of substances subject to environmental laws. The CERCLA, the federal "Superfund" law, addresses the cleanup of sites contaminated by hazardous substances. Superfund requires that PRPs fund remedial actions regardless of fault or the legality of past disposal activities. PRPs include owners and operators of contaminated sites and transporters and/or generators of hazardous substances. Many states have similar laws. Theoretically, any one PRP can be held responsible for the entire cost of a cleanup. Typically, however, cleanup costs are allocated among PRPs.
CPL is subject to various pending claims alleging it is a PRP under federal or state remedial laws for investigating and cleaning up contaminated property. CPL anticipates that resolution of these claims, individually or in the aggregate, will not have a material adverse effect on CPL's results of operations or financial condition.
2-78 Although the reasons for this expectation differ from site to site, factors that are the basis for the expectation for specific sites include the volume and/or type of waste allegedly contributed by CPL, the estimated amount of costs allocated to CPL and the participation of other parties.
Clean Air Act Amendments In November 1990, the United States Congress passed the Clean Air Act which places restrictions on the emission of sulfur dioxide from gas-, coal- and lignite-fired generating plants. Beginning in the year 2000, CPL will be required to hold allowances in order to emit sulfur dioxide. The EPA issues allowances to owners of existing generating units based on historical operating conditions. Based on the CSW System facilities plan, CPL believes that its allowances will be adequate to meet its needs at least through 2008. Public and private markets are developing for trading of excess allowances. CPL presently has no intention of engaging in trading of allowances, but may seek to do so in the future if market conditions warrant and appropriate regulatory approvals are obtained.
The Clean Air Act also establishes a federal operating source permit program to be administered by the states.
The Clean Air Act also directs the EPA to issue regulations governing nitrogen oxide emissions and requires government studies to determine what controls, if any, should be imposed on utilities to control air toxics emissions. The impact that the nitrogen oxide emission regulations and the air toxics study will have on CPL cannot be determined at this time.
As a result of requirements imposed by the Clean Air Act, CPL expects to spend $1.3 million for annual testing of, software modifications to, and maintenance of continuous emission monitoring equipment from 1995 through 1997.
EMFs Research is ongoing whether exposure to EMFs may result in adverse health effects. Although a few of the studies to date have suggested certain associations between EMFs and some types of effects, the research to date has not established a cause-and-effect relationship between EMFs and adverse health effects. CPL cannot predict the impact on CPL or the electric utility industry if further investigations or proceedings were to establish that the present electricity delivery system is contributing to increased risk or incidence of health problems.
Results of Operations Electric Operating Revenues Total revenues decreased $5.5 million in 1994 and increased $110.1 million in 1993. The 1994 decrease reflects lower fuel- related revenues of $41.5 million partially offset by higher base revenues of $35.9 million. Fuel-related revenues declined as a result of lower per unit fuel and purchased power costs, as discussed below.
Total KWH sales were up 8%, reflecting growth of 7% in retail sales and 41% in lower margin sales for resale. All of CPL's retail classes showed KWH growth with increases of 6% in both residential and commercial sales. An increase in the number of residential and commercial customers served and warmer spring as well as summer weather also contributed to this growth. Industrial sales were up 8% as a result of higher demand in the petrochemical and petroleum industries, where several companies CPL serves had plant expansions and increased load requirements. The rise in sales for resale is attributable to warmer summer and spring weather and lower cost STP generation.
The increase in revenues in 1993 over 1992 reflects higher fuel- related revenues and greater base revenues. Fuel-related revenues were up because of the rise in per unit fuel and purchased power costs, as discussed below, and higher fuel consumption on greater KWH sales.
2-79 Fuel and Purchased Power Fuel expense decreased $21.8 million or 6% due primarily to a decrease in the average unit cost of fuel from $2.17 in 1993 to $1.75 in 1994 partially offset by a 16% increase in generation. The lower average unit cost of fuel reflects increased usage of lower unit cost nuclear fuel since STP Units 1 and 2 restarted and reached 100 percent output level in April and June of 1994, respectively, and lower unit costs of gas and coal in 1994. STP Units 1 and 2 had not operated at full capacity since February 1993 as discussed in Litigation and Regulatory Proceedings in NOTE 9.
Fuel expense increased in 1993 due primarily to higher fuel consumption in both gas and coal as a result of the STP outage and an increase in the average unit cost of fuel from $1.70 in 1992 to $2.17 in 1993.
Purchased power decreased $21.7 million during 1994 and increased $46.9 million in 1993 when compared to the prior year due to the outage at STP.
Other Operating and Maintenance Expenses and Taxes Other operating expenses were relatively stable in 1994 and increased $40.5 million or 22% in 1993 when compared to the prior year.
The 1993 increase in other operating expenses was due primarily to the higher costs associated with the STP outage and increased pension and medical costs, which included implementation of SFAS No. 106.
Restructuring charges reflect the initial estimated cost of $29 million as previously discussed. Such expenses include the estimated costs associated with the early retirement program, severance packages and relocation.
Maintenance expense decreased $12.8 million during 1994 and increased $20.0 million in 1993 when compared to the prior year due primarily to maintenance activities at STP associated with the outage.
Depreciation and amortization increased in 1994 and 1993 as a result of increases in depreciable plant. The increase in 1994 is also attributable to a decline in amortization credits related to power plant investment.
Taxes, other than federal income, decreased in 1994 mainly as a result of a franchise tax refund. The increase in 1993 is largely a result of increased ad valorem taxes.
Federal income taxes increased $10.2 million in 1994 due to higher pre-tax income. Federal income taxes decreased $12.1 million in 1993 due to lower pre-tax income partially offset by the increase in the statutory tax rate from 34% to 35% effective retroactive to January 1, 1993.
Inflation Annual inflation rates, as measured by the Consumer Price Index, have averaged 2.7% during the three years ended December 31, 1994. CPL believes that inflation, at these levels, does not materially affect its results of operation or financial condition. However, under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, cash flows designed to provide recovery of historical plant costs may not be adequate to replace plant in future years.
Mirror CWIP Liability Amortization CPL is amortizing its Mirror CWIP liability in declining amounts over the years 1991 through 1995. Non-cash earnings of $68 million were recognized in 1994, a decrease from the $75.7 million recognized in 1993. The remaining liability to be amortized for 1995 is $41 million, which will fully amortize the Mirror CWIP liability.
2-80 Cumulative Effect of Changes in Accounting Principles In 1993, CPL changed its method of accounting for unbilled revenues and implemented SFAS No. 112. These accounting changes had a cumulative effect of increasing net income by $27.3 million.
2-81 Statements of Income Central Power and Light Company For the Years Ended December 31, 1994 1993 1992 (thousands)
Electric Operating Revenues Residential $ 474,480 $ 474,426 $ 432,295 Commercial 368,405 369,426 342,201 Industrial 271,738 281,247 240,341 Sales for resale 50,777 45,369 50,342 Other 52,579 53,060 48,244 1,217,979 1,223,528 1,113,423 Operating Expenses and Taxes Fuel 328,460 350,268 306,939 Purchased power 42,342 64,025 17,160 Other operating 224,852 225,034 184,514 Restructuring charges 98 29,365 -- Maintenance 68,537 81,352 61,399 Depreciation and amortization 141,622 131,825 129,131 Taxes, other than federal income 80,461 86,394 70,343 Federal income taxes 75,356 65,186 77,272 961,728 1,033,449 846,758
Operating Income 256,251 190,079 266,665
Other Income and Deductions Allowance for equity funds used during construction 1,215 1,074 408 Mirror CWIP liability amortization 68,000 75,702 82,527 Other 1,272 1,663 890 70,487 78,439 83,825
Income Before Interest Charges 326,738 268,518 350,490
Interest Charges Interest on long-term debt 111,408 112,939 125,476 Interest on short-term debt and other 12,365 11,993 7,266 Allowance for borrowed funds used during construction (2,474) (1,544) (763) 121,299 123,388 131,979
Income Before Cumulative Effect of Changes in Accounting Principles 205,439 145,130 218,511
Cumulative Effect of Changes in Accounting Principles -- 27,295 --
Net Income 205,439 172,425 218,511 Preferred stock dividends 13,804 14,003 16,070 Net Income for Common Stock $ 191,635 $ 158,422 $ 202,441
The accompanying notes to financial statements are an integral part of these statements.
2-82 Statements of Retained Earnings Central Power and Light Company For the Years Ended December 31, 1994 1993 1992 (thousands)
Retained Earnings at Beginning of Year $850,307 $863,988 $854,659 Net income for common stock 191,635 158,422 202,441 Deduct: Common stock dividends 183,000 172,000 193,000 Preferred stock redemption costs 1,476 103 112 Retained Earnings at End of Year $857,466 $850,307 $863,988
The accompanying notes to financial statements are an integral part of these statements.
2-83 Balance Sheets Central Power and Light Company As of December 31, 1994 1993 (thousands) ASSETS Electric Utility Plant Production $3,070,005 $3,061,911 Transmission 451,050 351,584 Distribution 828,350 765,266 General 216,888 209,170 Construction work in progress 142,724 168,421 Nuclear fuel 161,152 160,326 4,870,169 4,716,678 Less - Accumulated depreciation 1,400,343 1,263,372 3,469,826 3,453,306 Current Assets Cash and temporary cash investments 642 2,435 Special deposits 668 1,967 Accounts receivable 29,865 23,850 Materials and supplies, at average cost 66,209 64,359 Fuel inventory, at average cost 22,916 16,934 Accumulated deferred income taxes -- 4,831 Unrecovered fuel costs 54,126 52,959 Prepayments and other 2,316 2,255 176,742 169,590 Deferred Charges and Other Assets Deferred STP costs 488,987 489,773 Mirror CWIP asset 321,825 331,845 Income tax related regulatory assets, net 288,444 266,597 Other 76,875 70,634 1,176,131 1,158,849 $4,822,699 $4,781,745
The accompanying notes to financial statements are an integral part of these statements.
2-84 Balance Sheets Central Power and Light Company As of December 31, 1994 1993 (thousands) CAPITALIZATION AND LIABILITIES Capitalization Common stock: $25 par value Authorized: 12,000,000 shares Issued and outstanding: 6,755,535 shares $ 168,888 $ 168,888 Paid-in capital 405,000 405,000 Retained earnings 857,466 850,307 Total Common Stock Equity 1,431,354 1,424,195 Preferred stock Not subject to mandatory redemption 250,351 250,351 Subject to mandatory redemption -- 22,021 Long-term debt 1,466,393 1,362,799 Total Capitalization 3,148,098 3,059,366 Current Liabilities Long-term debt and preferred stock due within twelve months 723 3,928 Advances from affiliates 161,320 171,165 Accounts payable 75,051 79,604 Accrued taxes 59,386 33,769 Accumulated deferred income taxes 13,812 -- Accrued interest 24,681 24,683 Accrued restructuring charges 1,325 29,365 Other 30,151 28,020 366,449 370,534 Deferred Credits Income taxes 1,087,317 1,057,453 Investment tax credits 158,533 164,322 Mirror CWIP liability and other 62,302 130,070 1,308,152 1,351,845 $4,822,699 $4,781,745
The accompanying notes to financial statements are an integral part of these statements.
2-85 Statements of Cash Flows Central Power and Light Company For the Years Ended December 31, 1994 1993 1992 (thousands) OPERATING ACTIVITIES Net Income $205,439 $172,425 $218,511 Non-cash Items Included in Net Income Depreciation and amortization 170,971 140,223 154,716 Deferred income taxes and investment tax credits 20,870 84,714 42,773 Mirror CWIP liability amortization (68,000) (75,702) (82,527) Restructuring charges 98 29,365 -- Allowance for equity funds used during construction (1,215) (1,074) (408) Cumulative effect of changes in accounting principles -- (27,295) -- Changes in Assets and Liabilities Accounts receivable (6,015) (3,554) (6,415) Fuel inventory (5,982) 12,325 (3,137) Accounts payable (4,553) 19,151 6,209 Accrued taxes 25,617 (9,311) (2,165) Unrecovered fuel costs (1,167) (57,386) (1,195) Accrued restructuring charges (20,245) -- -- Other deferred credits 232 (35,242) (4,133) Other (4,575) 29,928 (18,479) 311,475 278,567 303,750 INVESTING ACTIVITIES Construction expenditures (174,993) (177,120) (100,805) Allowance for borrowed funds used during construction (2,474) (1,544) (763) (177,467) (178,664) (101,568) FINANCING ACTIVITIES Proceeds from issuance of long-term debt 99,190 441,131 435,497 Retirement of long-term debt (459) (431) (405) Reacquisition of long-term debt (618) (573,776) (304,650) Retirement of preferred stock (27,021) (6,578) (7,050) Special deposits for reacquisition of long-term debt -- 145,482 (145,482) Change in advances from affiliates (9,845) 79,399 29,618 Payment of dividends (197,048) (186,361) (209,196) (135,801) (101,134) (201,668)
Net Change in Cash and Cash Equivalents (1,793) (1,231) 514 Cash and Cash Equivalents at Beginning of Year 2,435 3,666 3,152 Cash and Cash Equivalents at End of Year $ 642 $ 2,435 $ 3,666
SUPPLEMENTARY INFORMATION Interest paid less amounts capitalized $114,980 $116,664 $130,078 Income taxes paid $ 28,166 $ 3,631 $ 45,314
The accompanying notes to financial statements are an integral part of these statements.
2-86 Statements of Capitalization Central Power and Light Company As of December 31, 1994 1993 (thousands)
COMMON STOCK EQUITY $1,431,354 $1,424,195
PREFERRED STOCK Cumulative $100 Par Value, Authorized 3,035,000 shares Number Current of Shares Redemption Series Outstanding Price
Not Subject to Mandatory Redemption 4.00% 100,000 $105.75 10,000 10,000 4.20% 75,000 103.75 7,500 7,500 7.12% 260,000 101.00 26,000 26,000 8.72% 500,000 100.00 50,000 50,000 Auction Money Market 750,000 100.00 75,000 75,000 Auction SeriesA 425,000 100.00 42,500 42,500 Auction SeriesB 425,000 100.00 42,500 42,500 Issuance Expense (3,149) (3,149) 250,351 250,351 Subject to Mandatory Redemption 10.05% -- 25,900 Issuance Expense -- (410) Amount to be Redeemed Within One Year -- (3,469) -- 22,021 LONG-TERM DEBT First Mortgage Bonds Series J, 6 5/8%, due January 1, 1998 28,000 28,000 Series L, 7%, due February 1, 2001 36,000 36,000 Series T, 7 1/2%, due December 15, 2014 * 111,700 111,700 Series U, 9 3/4%, due July 1, 2015 * 31,765 31,765 Series Z, 9 3/8%, due December 1, 2019 139,405 140,000 Series AA, 7 1/2%, due March 1, 2020 * 50,000 50,000 Series BB, 6%, due October 1, 1997 200,000 200,000 Series CC, 7 1/4%, due October 1, 2004 100,000 100,000 Series DD, 7 1/8%, due December 1, 1999 25,000 25,000 Series EE, 7 1/2%, due December 1, 2002 115,000 115,000 Series FF, 6 7/8% due February 1, 2003 50,000 50,000 Series GG, 7 1/8%, due February 1, 2008 75,000 75,000 Series HH, 6%, due April 1, 2000 100,000 100,000 Series II, 7 1/2%, due April 1, 2023 100,000 100,000 Series JJ, 7 1/2%, due May 1, 1999 100,000 -- Installment Sales Agreements - PCRBs Series 1974A, 7 1/8%, due June 1, 2004 8,700 8,955 Series 1977, 6%, due November 1, 2007 34,235 34,235 Series 1984, 7 7/8%, due September 15, 2014 6,330 6,330 Series 1984, 10 1/8%, due October 15, 2014 68,870 68,870 Series 1986, 7 7/8%, due December 1, 2016 60,000 60,000 Series 1993, 6%, due July 1, 2028 120,265 120,265 Notes Payable, 6 1/2%, due December 8, 1995 448 652 Unamortized Discount (11,655) (12,265) Unamortized Costs of Reacquired Debt (81,947) (86,249) Amount to be Redeemed Within One Year (723) (459) 1,466,393 1,362,799 TOTAL CAPITALIZATION $3,148,098 $3,059,366
*Obligations incurred in connection with the sale by public authorities of tax-exempt PCRBs.
The accompanying notes to financial statements are an integral part of these statements.
2-87 NOTES TO FINANCIAL STATEMENTS
1.Summary of Significant Accounting Policies Public Utility Regulation CPL is subject to regulation by the SEC under the Holding Company Act and the FERC under the Federal Power Act, and follows the Uniform System of Accounts prescribed by the FERC. CPL is subject to further regulation with regard to rates and other matters by the Texas Commission. CPL, as a member of the CSW System, engages in transactions and coordinates its activities and operations with other members of the CSW System.
The more significant accounting policies of CPL are summarized below:
Electric Utility Plant Electric utility plant is stated at the original cost of construction, which includes the cost of contracted services, direct labor, materials, overhead items and allowances for borrowed and equity funds used during construction.
Depreciation Provisions for depreciation of utility plant are computed using the straight-line method, generally at individual rates applied to the various classes of depreciable property. The annual average consolidated composite rates were 3.0% for 1994, 1993 and 1992.
Nuclear Decommissioning At the end of STP's service life, decommissioning is expected to be accomplished using the decontamination method, which is one of the techniques acceptable to the NRC. Using this method the decontamination activities occur as soon as possible after the end of plant operations. Contaminated equipment is cleaned or removed to a permanent disposal location and the site is generally returned to its pre-plant state.
CPL's decommissioning costs are accrued and funded to an external trust over the expected service life of the STP units. The existing NRC operating licenses will allow the operation of STP Unit 1 until 2027, and Unit 2 until 2028. The accrual is an annual level cost based on the estimated future cost to decommission STP, including escalations for expected inflation to the expected time of decommissioning, and is net of expected earnings on the trust fund.
CPL's portion of the costs of decommissioning STP were estimated to be $85 million in 1986 dollars based on a site specific study completed in 1986. CPL is recovering these decommissioning costs through rates based on the service life of STP at a rate of $4.2 million per year. The $4.2 million annual cost of decommissioning is reflected on the income statement in other operating expense. Decommissioning costs are paid to an irrevocable external trust and as such are not reflected on CPL's balance sheet. At December 31, 1994, the trust balance was $19.3 million.
In May 1994, CPL received a new decommissioning study updating the cost estimates to decommission STP that indicated that CPL's share of such costs would increase from $85 million, as stated in 1986 dollars, to $251 million, as stated in 1994 dollars. The increase in costs occurred primarily as a result of extended on-site storage of high level waste, much higher estimates of low-level waste disposal costs and increased labor costs since the prior study. These costs are expected to be incurred during the years 2027 through 2062. While this is the best estimate available at this time, these costs may change between now and when the funds are actually expended because of changes in the assumptions used to derive the estimates, including the prices of the goods and services required to accomplish the decommissioning. Additional studies will be completed periodically to update this information.
2-88 Based on this projected cost to decommission STP, CPL estimates that its annual funding level should increase to $10.0 million. CPL has requested this amount as part of its cost of service in its current rate filing. Other parties to the rate proceeding have filed their projections of the annual amount, which have ranged from $4.5 million to $8.1 million. CPL expects to fund at the level ultimately ordered by the Texas Commission although CPL cannot predict what that level will be. Historically, the Texas Commission has allowed full recovery of nuclear decommissioning costs. For further information on CPL's current rate filing see NOTE 9, Litigation and Regulatory Proceedings - Texas Commission Proceedings.
Electric Revenues and Fuel Prior to January 1, 1993, electric revenues were recorded at the time billings were made to customers on a cycle-billing basis. Electric service provided subsequent to billing dates through the end of each calendar month became part of operating revenues of the next month. To conform to general industry standards, CPL changed its method of accounting to accrue for estimated unbilled revenues. The effect of this change on 1993 net income was an increase of $29.5 million included in cumulative effect of changes in accounting principles.
CPL recovers fuel costs in Texas as a fixed component of base rates whereby over-recoveries of fuel are payable to customers and under-recoveries may be billed to customers after Texas Commission approval. The cost of fuel is charged to expense as consumed. See NOTE 9, Litigation and Regulatory Proceedings, for further information about fuel recoveries. CPL recovers fuel costs applicable to wholesale customers, which are regulated by the FERC, through an automatic fuel adjustment clause. CPL amortizes direct nuclear fuel costs to fuel expense on the basis of a ratio of the estimated energy used in the core to the energy expected to be derived from such fuel assembly over its life in the core. In addition to fuel amortization, CPL also incurs nuclear fuel expense as a result of other items, including spent fuel disposal fees assessed on the basis of net KWHs sold from STP, and DOE special assessment fees for decontamination and decommissioning of the enrichment facilities on the basis of prior usage of enrichment services.
Accounts Receivable CPL sells its billed and unbilled accounts receivable, without recourse, to CSW Credit.
Regulatory Assets and Liabilities For its regulated activities, CPL follows SFAS No. 71, which defines the criteria for establishing regulatory assets and regulatory liabilities. Regulatory assets represent probable future revenue to CPL associated with certain costs which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future refunds to customers. At December 31, 1994 and 1993, CPL had recorded the following significant regulatory assets and liabilities:
1994 1993 (thousands) Regulatory Assets Deferred plant costs $488,987 $489,773 Mirror CWIP asset 321,825 331,845 Income tax related regulatory assets, net 288,444 266,597 Unrecovered fuel costs 54,126 52,959
Regulatory Liabilities Mirror CWIP liability $ 41,000 $109,000
2-89 Deferred Plant Costs In accordance with orders of the Texas Commission, CPL deferred operating, depreciation and tax costs incurred for STP. This deferral was for the period beginning on the date when the plant began commercial operation until the date the plant was included in rate base. The deferred costs are being amortized and recovered through rates over the life of the plant. See NOTE 9, Litigation and Regulatory Proceedings, for further discussion of CPL's deferred accounting proceedings.
Mirror CWIP In accordance with Texas Commission orders, CPL previously recorded Mirror CWIP, which is being amortized over the life of STP. For more information regarding Mirror CWIP, reference is made to NOTE 9, Litigation and Regulatory Proceedings. Statements of Cash Flows Cash equivalents are considered to be highly liquid debt instruments purchased with a maturity of three months or less. Accordingly, temporary cash investments are considered cash equivalents.
Reclassification Certain financial statement items for prior years have been reclassified to conform to the 1994 presentation.
Accounting Changes Effective January 1, 1993, CPL adopted SFAS Nos. 106, 112 and 109. See NOTE 2, Federal Income Taxes, for further information regarding SFAS No. 109. In addition, CPL also changed its method of accounting for unbilled revenues. See Electric Revenues and Fuel above for further information.
The adoption of SFAS No. 106 resulted in an increase in 1993 operating expenses of $5.9 million. The adoption of SFAS No. 112 and the change in accounting for unbilled revenues are presented as a cumulative effect of changes in accounting principles as shown below:
Pre-Tax Tax Net Income Effect Effect Effect (thousands) SFAS No. 112 $(3,371) $ 1,180 $ (2,191) Unbilled revenues 45,363 (15,877) 29,486 Total $41,992 $(14,697) $27,295
Pro forma amounts, assuming that the change in accounting for unbilled revenues had been adopted retroactively, are not materially different from amounts previously reported for prior years.
2.Federal Income Taxes CPL adopted the provisions of SFAS No. 109 effective January 1, 1993. The implementation of SFAS No. 109 had no material effect on CPL's earnings. As a result of this change, CPL recognized additional accumulated deferred income taxes from its utility operations, and corresponding regulatory assets and liabilities to ratepayers in amounts equal to future revenues or the reduction in future revenues required when the income tax temporary differences reverse and are recovered or settled in rates. As a result of a favorable earnings history, CPL did not record any valuation allowance against deferred tax assets at December 31, 1994 and 1993.
CPL, together with other members of the CSW System, files a consolidated federal income tax return and participates in a tax sharing agreement.
Components of income taxes follow: 1994 1993 1992 Included in Operating Expenses and Taxes (thousands) Current $54,486 $(19,690) $ 34,336 Deferred 26,659 90,682 48,773 Deferred ITC (5,789) (5,806) (5,831) 75,356 65,186 77,272 Included in Other Income and Deductions Current (3,157) 736 390 Deferred -- (162) (163) (3,157) 574 227 Tax Effects of Cumulative Effect of Changes in Accounting Principles -- 14,697 -- $72,199 $80,457 $77,499
Investment tax credits deferred in prior years are included in income over the lives of the related properties.
Total income taxes differ from the amounts computed by applying the statutory income tax rates to income before taxes. The reasons for the differences follow:
1994 % 1993 % 1992 % (dollars in thousands) Tax at statutory $97,174 35.0 $88,509 35.0 $100,643 34.0 Differences Amortization of ITC (5,789) (2.1) (5,806) (3) (5,789) (2.0) Mirror CWIP (20,293) (7.3) (22,989) (9.1) (24,652) (8.3) Prior period adjustments (1,955) (0.7) 19,101 7.6 -- -- Other 3,062 1.1 1,642 .6 7,297 2.5 $72,199 26.0 $80,457 31.8 $77,499 26.2
2-91 The significant components of the net deferred income tax liability follow: 1994 1993 (thousands) Deferred Income Tax Liabilities Depreciable utility plant $ 755,437 $ 745,164 Deferred plant costs 171,145 171,421 Mirror CWIP asset 112,639 116,146 Income tax related regulatory asset 169,104 178,984 Other 49,800 37,989 Total Deferred Income Tax Liabilities 1,258,125 1,249,704
Deferred Income Tax Assets Income tax related regulatory liability (68,149) (85,675) Unamortized ITC (55,486) (57,513) Alternative minimum tax credit - carryforward (26,138) (15,744) Other (7,223) (38,150) Total Deferred Income Tax Assets (156,996) (197,082) Net Accumulated Deferred Income Taxes - Total $1,101,129 $1,052,622
Net Accumulated Deferred Income Taxes - Noncurrent $1,087,317 $1,057,453 Net Accumulated Deferred Income Taxes - Current 13,812 (4,831) Net Accumulated Deferred Income Taxes - Total $1,101,129 $1,052,622
3.Long-Term Debt The mortgage indenture, as amended and supplemented, securing first mortgage bonds issued by CPL, constitutes a direct first mortgage lien on substantially all electric utility plant. CPL may offer additional first mortgage bonds subject to market conditions and other factors.
Annual Requirements Certain series of outstanding first mortgage bonds have annual sinking fund requirements, which are generally 1% of the amount of each such series issued. These requirements may be, and generally have been, satisfied by the application of net expenditures for bondable property in an amount equal to 166-2/3% of the annual requirements. In addition, one series of CPL's pollution control bonds, has a sinking fund requirement. At December 31, 1994, the annual sinking fund requirements and annual maturities for CPL's first mortgage bonds and pollution control bonds for the next five years follow:
Sinking Fund Requirements Maturities (thousands) 1995 $ 2,840 $ 2,840 1996 2,840 2,840 1997 2,585 202,840 1998 2,560 30,560 1999 2,560 27,560
Dividends CPL's mortgage indenture, as amended and supplemented, contains certain restrictions on the use of their retained earnings for cash dividends on their common stock. These restrictions do not
2-92 limit the ability of CSW to pay dividends to its stockholders. At December 31, 1994, the amount of retained earnings available for payment of cash dividends to CSW by CPL was $684 million.
Reacquired Long-term Debt Reference is made to MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources, for further information related to long-term debt, including new issues and reacquisitions.
4.Preferred Stock The dividends on CPL's $160 million auction preferred stocks are adjusted every 49 days, based on current market rates. The dividend rates averaged 3.5%, 2.7%, and 3.6% during 1994, 1993 and 1992.
CPL retired the remaining shares of its 10.05% Series preferred stock during August 1994.
Each series of preferred stock, with the exception of the auction preferred stock, is redeemable at the option of CPL upon 30 days notice at the current redemption price per share. Redemption prices of the 8.72% Series decline at specified intervals in future years. CPL's two issues of auction preferred stock and one issue of money market preferred stock may be redeemed at par on any dividend payment date.
5.Short-Term Financing CPL, together with other members of the CSW System, has established a money pool to coordinate short-term borrowings and to make borrowings outside the money pool through CSW's issuance of commercial paper. Money pool balances are shown as advances to or from affiliates on the Balance Sheets. At December 31, 1994, the CSW System had bank lines of credit aggregating $930 million to back up its commercial paper program. Short-term cash surpluses transferred to the money pool receive interest income in accordance with the money pool arrangement.
6.Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value.
Cash, special deposits and temporary cash investments The carrying amount approximates fair value because of the short maturity of those instruments.
Advances from affiliates The carrying amount approximates fair value because of the short maturity of those instruments.
Long-term debt The fair value CPL's long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to CPL for debt of the same or similar remaining maturities.
Preferred stock The fair value of CPL's preferred stock subject to mandatory redemption is estimated based on quoted market prices for the same or similar issues or on the current rates offered to CPL for preferred stock with the same or similar remaining redemption provisions.
Long-term debt and preferred stock due within twelve months The fair values of CPL's current maturities of long-term debt and preferred stock are estimated based on current rates offered to CPL for long-term debt and preferred stock.
2-93 The estimated fair values of CPL's financial instruments follow:
1994 1993 Carrying Fair Carrying Fair Amount Value Amount Value (thousands) Cash and temporary cash investments $ 642 $ 642 $ 2,435 $ 2,435 Special Deposits 668 668 1,967 1,967 Advances from affiliates 161,320 161,320 171,165 171,165 Long-term debt 1,466,393 1,395,590 1,362,799 1,456,533 Preferred stock subject to mandatory redemption -- -- 22,021 23,086 Long-term debt and preferred stock due within 12 months 723 725 3,928 4,096
The fair value does not affect CPL's liabilities unless the issues are redeemed prior to their maturity dates.
7.Benefit Plans Defined Benefit Pension Plan CPL, together with the other members of the CSW System, maintains a tax qualified, non-contributory defined benefit pension plan covering substantially all employees. Benefits are based on employees' years of credited service, age at retirement, and final average annual earnings with an offset for the participant's primary Social Security benefit. The CSW System's funding policy is based on actuarially determined contributions, taking into account amounts which are deductible for income tax purposes and minimum contributions required by the ERISA. Pension plan assets consist primarily of common stocks and short-term and intermediate- term fixed income investments. Contributions to the plan for the years ended December 31, 1994, 1993 and 1992 were $7.1 million, $11.0 million and $11.7 million, respectively.
The approximate maximum number of participants in the plan during 1994 were 2,300 active employees, 1,200 retirees and beneficiaries and 300 terminated employees.
The components of net periodic pension cost and the assumptions used in accounting for pension follow:
1994 1993 1992 (thousands) Net Periodic Pension Cost Service cost $ 5,796 $ 5,228 $ 4,834 Interest cost on projected benefit obligation 15,989 14,878 13,686 Actual return on plan assets (1,131) (18,079) (11,750) Net amortization and deferral (17,972) 68 (5,330) $ 2,682 $ 2,095 $ 1,440
Discount rate 8.25% 7.75% 8.50% Long-term compensation increase 5.46% 5.46% 5.96% Return on plan assets 9.50% 9.50% 9.50%
2-94 At December 31, 1994, the plan's net assets were approximately equal to the total actuarial present value of the accumulated benefit obligation. At December 31, 1993 the plan's net assets exceeded the total actuarial present value of the accumulated benefit obligation. No reconciliation of the funding status of the plan is presented because such information is unavailable.
Health and Welfare Plans CPL had medical, dental, group life insurance, dependent life insurance, and accidental death and dismemberment plans for substantially all active CPL employees during 1994. The contributions, recorded on a pay-as-you-go basis, for the years ended December 31, 1994 and 1993 were approximately $4.6 million and $6.1 million, respectively. Effective January 1993, CPL's method of providing health benefits was modified to include such benefits as a health maintenance organization, preferred provider options, managed prescription drug and mail-order program and a mental health and substance abuse program in addition to the self- insured indemnity plans.
Postretirement Benefits Other Than Pensions CPL adopted SFAS No. 106 effective January 1, 1993. The effect on operating expense in 1993 was $5.9 million. CPL is amortizing the transition obligation over twenty years, with eighteen years remaining. In prior years, these benefits were accounted for on a pay-as-you-go basis.
The components of net periodic postretirement benefit cost follow:
1994 1993 (thousands) Net Periodic Postretirement Benefit Cost Service cost $ 2,435 $ 2,257 Interest cost on APBO 6,061 5,505 Actual return on plan assets (285) (249) Amortization of transition obligation 2,900 2,900 Net amortization and deferral (913) (703) $10,198 $9,710
A reconciliation of the funded status of the plan to the amounts recognized on the balance sheets follow:
1994 1993 APBO (thousands) Retirees $49,852 $50,032 Other fully eligible participants 9,278 9,147 Other active participants 15,017 17,353 Total APBO 74,147 76,353 Plan assets at fair value (21,457) (14,185) APBO in excess of plan assets 52,690 62,347 Unrecognized transition obligation (52,208) (55,108) Unrecognized gain or (loss) 577 (6,180) Accrued/(Prepaid) Cost $ 1,059 $ 1,059
2-95 The following assumptions were used in accounting for SFAS No. 106.
1994 1993 Discount rate 8.25% 7.75% Return on plan assets 9.50% 9.00% Tax rate for taxable trusts 39.60% 39.60%
Health Care Cost Trend Rate Assumptions Pre-65 Participants: 1994 Rate of 11.75% grading down .75% per year to an ultimate rate of 6.5% in 2001. Post-65 Participants: 1994 Rate of 11.25% grading down .75% per year to an ultimate rate of 6.0% in 2001.
Increasing the assumed health care cost trend rates by one percentage point in each year would increase the APBO by $8.0 million as of December 31, 1994 and increase the aggregate of the service and interest costs components on net postretirement benefits by $1.1 million.
8.Jointly Owned Electric Utility Plant CPL has a joint ownership agreement with other members of the CSW System and other non-affiliated entities. Such agreements provide for the joint ownership and operation of STP and Oklaunion power plants. The statements of income reflect CPL's portion of operating costs associated with jointly owned plants. At December 31, 1994, CPL had interests as shown below: South Texas Oklaunion Nuclear Coal Plant Plant (dollars in millions) Plant in service $2,343 $36 Accumulated depreciation 380 8 Plant capacity-MW 2,500 676 Participation 25.2% 7.8% Share of capacity-MW 630 53
9.Litigation and Regulatory Proceedings STP From February 1993 until May 1994, STP experienced an unscheduled outage which has resulted in significant rate and regulatory proceedings involving CPL. These matters, including a base rate case and fuel reconciliation proceedings, are discussed immediately below.
Texas Commission Proceedings Base Rates Rate Inquiry - Docket No. 12820 Several Cities, the Texas Commission General Counsel and others initiated actions in late 1993 and early 1994 which, if approved by the Texas Commission, would lower CPL's base rates. The requests for a review of CPL's rates arose out of the unscheduled outage at STP which began in February 1993. The STP outage did not affect CPL's ability to meet customer demand because of existing capacity and CPL's purchase of additional energy.
Pursuant to a scheduling and procedural settlement agreement among the parties challenging CPL's rates, which was approved by a Texas Commission ALJ on April 1, 1994, CPL submitted a rate filing package on July 1, 1994 to the Texas Commission justifying its current base rate structure. In that filing, CPL stated that it
2-96 had a $111 million retail revenue deficiency and would be justified in seeking a base rate increase. However, consistent with the procedural settlement agreement, CPL has not sought to increase base rates as a part of this docket but seeks to maintain its rates at the same levels agreed to in the settlement of its last two rate cases in 1990 and 1991. As part of the 1990 and 1991 settlements, CPL agreed to freeze base rates from January 1, 1991 through 1994, subject to certain force majeure events including double digit inflation, major tax increases, extraordinary increases in operating expenses or serious declines in operating revenues. On October 31, 1994, CPL filed rebuttal testimony that revised its retail revenue deficiency to approximately $103 million. CPL continues to maintain that its rates are reasonable and that its earnings are within established regulatory guidelines.
Parties to CPL's base rate case have filed testimony with the Texas Commission recommending reductions in CPL's base rates. Among the parties that filed testimony were OPUC which initially recommended an annual $100 million retail rate reduction. After hearings on the rate case, OPUC claimed that CPL did not meet its burden of proof concerning deferred accounting and as a result OPUC changed its proposed reduction to $147 million. The Cities, which are parties to the rate case, have recommended an annual $75 million retail rate reduction and the write-off of $219 million of CPL's Mirror CWIP asset. See Deferred Accounting below.
The Staff filed testimony recommending an annual reduction in retail rates of $99.6 million resulting from a combination of proposed rate base and cost of service reductions, which it subsequently revised during the hearings to $83.9 million. In its final brief to the ALJ, the Staff withdrew its recommendation that short-term debt be included in the calculation of CPL's weighted cost of capital. CPL estimates that this change in the Staff's position will lower its revised proposed retail rate reduction by approximately $6 million. The Staff recommended a rate base disallowance of $407 million, or approximately 17% of CPL's investment in STP, based upon the Staff's calculation of historical performance for STP compared to a peer group of other nuclear facilities. The Staff also recommended that accumulated depreciation and accumulated deferred federal income taxes related to the disallowed portion of STP be adjusted to reflect a net reduction to rate base of $325 million. Additionally, the Staff proposed to disallow depreciation expense related to the recommended STP disallowed plant.
In its testimony, the Staff argued that its proposed STP rate base reduction was a historical performance-based disallowance that could be temporary in nature and would not have to result in a permanent disallowance. The Staff indicated that, in the future, CPL could seek recovery in rates of the proposed STP rate base disallowance, subject to the performance of STP.
The Texas Commission held hearings in November and December 1994, and all parties have filed briefs in the case. The ALJ is expected to issue a recommended order for consideration by the Texas Commission in April 1995, with a final order from the Texas Commission expected in May 1995. Testimony filed by parties to the rate case, including the Staff, is not binding on either the ALJ or the Texas Commission.
CPL strongly believes that 100 percent of its investment in both units of STP belong in rate base. This belief is based on, among other factors, Units 1 and 2 providing output at high capacity factors since April and June 1994, respectively. In addition, the long-term benefits nuclear generation provides to customers supports their inclusion in rate base. Furthermore, there are no Texas Commission precedents addressing the removal of a nuclear plant from rate base as a performance-based disallowance. Assuming both units of STP are included in rate base, CPL believes it is not collecting excessive revenues, notwithstanding that market rates of return on common equity are generally lower today than they were in 1990 and 1991, when CPL's base rates were last set.
2-97 Fuel Introduction Pursuant to the substantive rules of the Texas Commission, CPL generally is allowed to recover its fuel costs through a fixed fuel factor. These fuel factors are in the nature of temporary rates, and CPL's collection of revenues by such fuel factors is subject to adjustment at the time of a fuel reconciliation proceeding before the Texas Commission. The difference between fuel revenues billed and fuel expense incurred is recorded as an addition to or a reduction of revenues, with a corresponding entry to unrecovered fuel costs or other current liabilities, as appropriate. Any fuel costs, not limited to under- or over- recoveries, which the Texas Commission determines as unreasonable in a reconciliation proceeding are not recoverable from customers.
Fuel Surcharge - Docket No. 12154 In July 1993, CPL filed a fuel surcharge petition, which is separate from a fuel reconciliation proceeding, with the Texas Commission to comply with the mandatory provisions of the Texas Commission's fuel rules. The petition requested approval of a customer surcharge to recover under-recovered fuel and purchased power costs resulting from the STP outage, increased natural gas costs and other factors. The petition also requested that the Texas Commission postpone consideration of the surcharge until the STP outage concluded or at the time fuel costs are next reconciled as discussed above. In August 1993, a Texas Commission ALJ granted CPL's request to postpone consideration of the surcharge. In January and July of 1994, CPL updated its fuel surcharge petition to reflect amounts of under-recovery through November 1993 and May 1994, respectively. Also, CPL updated its petition in January 1995 to reflect amounts of under-recovery through November 1994. Likewise, CPL requested and was granted postponement of the updated petitions until the STP outage concluded or at the time fuel costs are next reconciled. On January 4, 1995, Docket No. 12154 was consolidated into Docket No. 13650.
Prudence Inquiry - Docket No. 13126 In April 1994, the Texas Commission's General Counsel and Staff issued a Request for Proposal for an audit of the STP outage, and in July 1994 a consultant was selected to perform the audit. The purpose of the audit is to evaluate the prudence of management activities at STP, including the actions of HLP and the STP management committee, of which CPL is a participant. Such review will include the time from original commercial operation of each unit until they were returned to service from the outage. The findings of this audit are expected to be incorporated into this proceeding. CPL and HLP will pay the costs of the audit but will have no control over the ultimate work product of the consultant.
In June 1994, the Texas Commission's General Counsel initiated an inquiry into the operation and management of STP which resulted in the establishment of this proceeding. As part of the inquiry, CPL presented certain information concerning the prudence of management activities at STP relating to the STP outage. Testimony filed by CPL stated that the cause of the STP outage was the result of an accidental equipment failure rather than imprudent management activities at STP. Based on this information, CPL will seek full recovery in its fuel reconciliation case of incremental energy costs related to the STP outage.
As a part of this proceeding, CPL was required to reconstruct its production costs assuming STP was available 100% of the time during the actual outage. Testimony filed by CPL stated that it is unrealistic to expect any generating unit to operate all the time. The testimony provided calculations of STP replacement power cost estimates for availability factor scenarios at (i) 100%, (ii) 75% and (iii) 65% average availability. Based on these average availability factors, STP net replacement power costs for the entire outage period were estimated to be (i) $104.5 million at 100%, (ii) $79.0 million at 75% and (iii) $68.2 million at 65% average availability.
The results of this prudence inquiry are expected to be used in CPL's pending fuel reconciliation proceeding in Docket No. 13650, as discussed below, and possibly CPL's next base rate proceeding should a return on equity penalty be ordered by the Texas
2-98 Commission. Such penalty could lower CPL's allowed return on equity in its next base rate case from what it otherwise would be permitted to earn.
Fuel Reconciliation - Docket No. 13650 On November 15, 1994, CPL filed a fuel reconciliation case with the Texas Commission seeking to reconcile approximately $1.2 billion of fuel costs from March 1, 1990 through June 30, 1994. This period includes the STP outage where CPL's fuel and purchased power costs were increased as the power normally generated by STP was replaced through sources with higher costs. At December 31, 1994, CPL's under-recovered fuel balance was $54.1 million, exclusive of interest. This under-recovery of fuel costs, while due primarily to the STP outage, was also affected by changes in fuel prices and timing differences. CPL cannot accurately estimate the amount of any future under- or over-recoveries due to the nature of the above factors. CPL cannot predict how the Texas Commission will ultimately resolve the reasonableness of higher replacement energy costs associated with the STP outage. Although the Texas Commission could disallow all or a portion of the STP replacement energy costs, such determination cannot be made until a final order is issued by the Texas Commission in this docket. If a significant portion of the fuel costs were disallowed by the Texas Commission, CPL could experience a material adverse effect on its results of operations in the year of disallowance but not on its financial condition.
CPL continues to negotiate with the intervening parties to resolve Docket Nos. 12820, 13126 and the STP portions of Docket No. 13650 through settlement. However, no settlement has been reached.
Management cannot predict the ultimate outcome of the CPL rate inquiry and fuel regulatory proceedings. However, management believes that the ultimate resolution of the various issues will not have a material adverse effect on CPL's results of operations or financial condition.
STP Background Final Orders In October 1990, the Texas Commission issued the STP Unit 1 Order which fully implemented a stipulated agreement filed in February 1990 to resolve dockets then pending before the Texas Commission. In December 1990, the Texas Commission issued the STP Unit 2 Order which fully implemented a stipulated agreement to resolve all issues regarding CPL's investment in STP Unit 2.
The STP Unit 1 Order allowed CPL to increase retail base rates by $144 million. This base rate increase made permanent a $105 million interim base rate increase placed into effect in March 1990 and a $39 million interim base rate increase placed into effect in September 1989. The STP Unit 2 Order provided for a retail base rate increase of $120 million effective January 1, 1991. The STP Unit 1 Order also provided for the deferral of operating expenses and carrying costs on STP Unit 2. A prior Texas Commission order had authorized deferral of STP Unit 1 costs. See Deferred Accounting below. Such costs are being recovered through rates over the remaining life of STP. Also, the STP Unit 1 Order authorized use of Mirror CWIP, pursuant to which CPL recognized $360 million of carrying costs as deferred costs, and established a corresponding liability to customers recorded in Mirror CWIP Liability and Other Deferred Credits on the balance sheets. In compliance with the order, carrying costs collected through rates during periods when CWIP was included in rate base were recognized as a loan from customers. The loan is being repaid through lower rates from 1991 through 1995. The Mirror CWIP liability is being reduced by the recognition of non-cash income during the period 1991 through 1995. The Mirror CWIP asset is being amortized to expense over the life of the plant.
The STP Unit 1 and 2 Orders resolved all issues pertaining to the reasonable original costs of STP and the appropriate amount to be included in rate base. Pursuant to the Texas Commission orders,
2-99 the original costs of CPL's total investment in STP is included in rate base. As indicated under the heading Texas Commission Proceedings above, however, CPL is currently involved in base rate and fuel proceedings which challenge CPL's right to recover certain costs associated with the STP outage.
As part of the stipulated agreement, CPL agreed to freeze base rates from January 1, 1991 through 1994, subject to certain force majeure events including double-digit inflation, major tax increases, extraordinary increases in operating expenses or serious declines in operating revenues. CPL may file for increases in base rates, which would be effective after 1994 and subject to certain limitations. The fuel portion of customers' bills is subject to adjustment following the normal review and approval by the Texas Commission.
The stipulated agreements, as discussed above, were entered into by CPL, the Staff and a majority of intervenors including major cities in CPL's service territory and major industrial customers. These intervenors represent a significant majority of CPL's customers. CPL and the TSA reached agreements, which were subsequently approved by the Staff and other signatories, whereby TSA agreed not to oppose the stipulated agreements in any respect, except with regard to deferred accounting and rate design issues in the STP Unit 1 Order. OPUC and a coalition of low-income customers declined to enter into the stipulated agreements.
In January 1991, the TSA, OPUC and the coalition of low-income customers filed appeals of the STP Unit 1 Order in District Court requesting reversal of the deferred accounting for STP Unit 2 and other aspects of that order. In March 1991, the TSA, OPUC and the coalition of low-income customers filed appeals of the STP Unit 2 Order in the District Court requesting reversal of that order. These appeals are pending before the District Court. If these orders are ultimately reversed on appeal, the stipulated agreements would be nullified and CPL could experience a significant adverse effect on its results of operations and financial condition. However, the parties to the stipulated agreement, should it be nullified, are bound to renegotiate and try to reach a revised agreement that would achieve the same economic results. Management believes that the STP Unit 1 and 2 Orders will be upheld.
Deferred Accounting CPL was granted deferred accounting for STP Unit 1 and 2 costs by Texas Commission orders. These orders allowed CPL to defer post- in-service operating and maintenance costs, including taxes and depreciation, and carrying costs until these costs were reflected in retail rates. Deferred accounting had an immediate positive effect on net income in the years allowed, but cash earnings were not increased until rates went into effect reflecting STP in service. See Final Orders above. The total deferrals for the periods affected were approximately $492 million with an after-tax net income effect of approximately $325 million. This total deferral included approximately $270 million of pre-tax debt carrying costs. Pursuant to the STP Unit 1 and 2 Orders, CPL's retail rates include recovery of STP Unit 1 and 2 deferrals over the remaining life of the plant.
In July 1989, OPUC and the TSA filed appeals of the Texas Commission's final order in District Court requesting reversal of deferred accounting for STP Unit 1. In September 1990, the District Court issued a judgment affirming the Texas Commission's order for STP Unit 1, which was subsequently appealed to the Court of Appeals by OPUC and the TSA. The hearing of CPL's STP Unit 1 deferred accounting order was combined by the Court of Appeals with similar appeals of HLP deferred accounting orders.
In September 1992, the Court of Appeals issued a decision that allows CPL to include STP Unit 1 deferred post-in-service operating and maintenance costs in rate base. However, the Court of Appeals held that deferred post-in-service carrying costs could not be included in rate base, thereby prohibiting CPL from earning a return on such costs.
After the Court of Appeals' denial of each party's motion for rehearing of the decision, CPL and the Texas Commission in December 1992 filed Applications for Writ of Error petitioning the
2-100 Supreme Court of Texas to review the September 1992 decision denying rate base treatment of deferred post-in-service carrying costs by the Court of Appeals. Additionally, the TSA and OPUC filed Applications for Writ of Error petitioning the Supreme Court of Texas to reverse the Court of Appeals' decision, challenging generally the legality of deferred accounting for rate base treatment of any deferred costs. In May 1993, the Supreme Court of Texas granted CPL's Application for Writ of Error. CPL's case was consolidated with the deferred accounting cases of El Paso and HLP. In June 1994, the Supreme Court of Texas sustained deferred accounting as an appropriate mechanism for the Texas Commission to use in preserving the financial integrity of utilities. The Supreme Court of Texas held that the Texas Commission can authorize utilities to defer those costs that are incurred between the in-service date of a plant and the effectiveness of new rates, which include such costs. On October 6, 1994, the Supreme Court of Texas denied a motion for rehearing CPL's deferred accounting matter filed by the State of Texas. The language of the Supreme Court of Texas opinion suggests that the appropriateness of allowing deferred accounting may need to again be reviewed under a financial integrity standard at the time the costs begin being recovered through rates. For CPL, that would be the STP Unit 1 and Unit 2 Orders discussed above. To the extent that additional review is required, it should occur in those dockets.
If these deferred accounting matters are not favorably resolved, CPL could experience a material adverse effect on its results of operations and financial condition. While CPL's management cannot predict the ultimate outcome of these matters, management believes CPL will receive approval of its deferred accounting orders or will be successful in renegotiation of its rate orders, so that there will be no material adverse effect on CPL's results of operations or financial condition.
Westinghouse Litigation CPL and other owners of STP are plaintiffs in a lawsuit filed in October 1990 in the District Court in Matagorda County, Texas against Westinghouse, seeking damages and other relief. The suit alleges that Westinghouse supplied STP with defective steam generator tubes that are susceptible to stress corrosion cracking. Westinghouse filed an answer to the suit in March 1992, denying the plaintiff's allegations. The suit is set for trial in July 1995.
Inspections during the STP outage have detected early signs of stress corrosion cracking in tubes at STP Unit 1. Management believes additional problems would develop gradually and will be monitored by the Project Manager of STP. An accurate estimate of the costs of remedying any further problems currently is unavailable due to many uncertainties, including among other things, the timing of repairs, which may coincide with scheduled outages, and the recoverability of amounts from Westinghouse. Management believes that the ultimate resolution of this matter will not have a material adverse effect on CPL's results of operations or financial condition.
Industrial Road and Industrial Metals Site Several lawsuits relating to the industrial road and industrial metals site in Corpus Christi, Texas, naming CPL as a defendant, are currently pending in federal and state court in Texas. Plaintiffs' claims allege property damage and health impairment as a result of operations on the site and clean-up activities. Although management cannot predict the outcome of these proceedings, based on the defenses that management believes are available to CPL, management believes that the ultimate resolution of these matters will not have a material adverse effect on CPL's results of operations or financial condition.
Civil Penalties In October 1994, the NRC staff advised HLP that it proposes to fine HLP $100,000 for what the NRC believes was discrimination against a contractor employee at STP who brought complaints of possible safety problems to the NRC's attention. These actions resulted from the findings of a NRC investigation of alleged violations of STP security and work process procedures in 1992. The incident cited by the NRC is the subject of a contested hearing that is scheduled to be held in the spring of 1995 before a United States Department of Labor judge. Until the Department
2-101 of Labor issues a final decision in this matter, the NRC is not requiring HLP to respond to its notice of violation.
Other CPL is party to various other legal claims, actions and complaints arising in the normal course of business. Management does not expect disposition of these matters to have a material adverse effect on CPL's results of operations or financial condition.
10. Commitments and Contingent Liabilities It is estimated that CPL will spend approximately $108 million in construction expenditures during 1995. Substantial commitments have been made in connection with this capital expenditure program.
To supply a portion of its fuel requirements CPL has entered into various commitments for the procurement of fuel.
Nuclear Insurance In connection with the licensing and operation of STP, the owners have purchased the maximum limits of nuclear liability insurance, as required by law, and have executed indemnification agreements with the NRC in accordance with the financial protection requirements of the Price-Anderson Act.
The Price-Anderson Act, a comprehensive statutory arrangement providing limitations on nuclear liability and governmental indemnities, is in effect until August 1, 2002. The limit of liability under the Price-Anderson Act for licensees of nuclear power plants is $8.92 billion per incident, effective as of January 1995. The owners of STP are insured for their share of this liability through a combination of private insurance amounting to $200 million and a mandatory industry-wide program for self-insurance totaling $8.72 billion. The maximum amount that each licensee may be assessed under the industry-wide program of self-insurance following a nuclear incident at an insured facility is $75.5 million per reactor, which may be adjusted for inflation plus a five percent charge for legal expenses, but not more than $10 million per reactor for each nuclear incident in any one year. CPL and each of the other STP owners are subject to such assessments, which CPL and other owners have agreed will be allocated on the basis of their respective ownership interests in STP. For purposes of these assessments, STP has two licensed reactors.
The owners of STP currently maintain on-site decontamination liability and property damage insurance in the amount of $2.75 billion provided by ANI and NEIL. Policies of insurance issued by ANI and NEIL stipulate that policy proceeds must be used first to pay decontamination and clean-up costs before being used to cover direct losses to property. Under project agreements, CPL and the other owners of STP will share the total cost of decontamination liability and property insurance for STP, including premiums and assessments, on a pro rata basis, according to each owner's respective ownership interest in STP.
CPL purchases, for its own account, a NEIL I Business Interruption and/or Extra Expense policy. This insurance will reimburse CPL for extra expenses incurred, up to $1.65 million per week, for replacement generation or purchased power as the result of a covered accident that shuts down production at STP for more than 21 weeks. The maximum amount recoverable for Unit 1 is $111.3 million and for Unit 2 is $111.8 million. CPL is subject to an additional assessment up to $2.1 million for the current policy year in the event that losses as a result of a covered accident at a nuclear facility insured under the NEIL I policy exceeds the accumulated funds available under the policy.
On August 28, 1994, CPL filed a claim under the NEIL I policy related to the outage at STP Units 1 and 2. NEIL is currently reviewing the claim. CPL management is unable to predict the ultimate outcome of this matter.
2-102 11. Quarterly Information (Unaudited) The following unaudited quarterly information includes, in the opinion of management, all adjustments necessary for a fair presentation of such amounts.
Operating Operating Net Quarter Ended Revenues Income Income 1994 (thousands) March 31 $ 263,229 $ 36,943 $ 24,986 June 30 333,169 75,070 62,470 September 30 364,044 96,062 82,877 December 31 257,537 48,176 35,106 $1,217,979 $ 256,251 $ 205,439
March 31 $ 238,254 $ 39,593 $ 54,560 June 30 316,053 66,745 53,679 September 30 387,190 88,438 77,612 December 31 282,031 (4,697) (13,426) $1,223,528 $ 190,079 $ 172,425
Information for quarterly periods is affected by seasonal variations in sales, rate changes, timing of fuel expense recovery and other factors.
2-103 Report of Independent Public Accountants
To the Stockholders and Board of Directors of Central Power and Light Company:
We have audited the accompanying balance sheets and statements of capitalization of Central Power and Light Company (a Texas corporation and a wholly-owned subsidiary of Central and South West Corporation) as of December 31, 1994 and 1993, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of CPL's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Central Power and Light Company as of December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
In 1993, as discussed in NOTE 1, CPL changed its methods of accounting for unbilled revenues, postretirement benefits other than pensions, income taxes and postemployment benefits.
Our audits were made for the purpose of forming an opinion on the financial statements taken as a whole. The supplemental Schedule II and Exhibit 12 are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. This schedule and exhibit have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Arthur Andersen LLP
Dallas, Texas February 13, 1995
2-104 Report of Management
Management is responsible for the preparation, integrity and objectivity of the financial statements of Central Power and Light Company as well as other information contained in this Annual Report. The financial statements have been prepared in conformity with generally accepted accounting principles applied on a consistent basis and, in some cases, reflect amounts based on the best estimates and judgments of management, giving due consideration to materiality. Financial information contained elsewhere in this Annual Report is consistent with that in the financial statements.
The financial statements have been audited by the independent accounting firm, Arthur Andersen LLP, which was given unrestricted access to all financial records and related data, including minutes of all meetings of shareholders, the board of directors and committees of the board. CPL believes that representations made to the independent auditors during its audit were valid and appropriate. Arthur Andersen LLP's audit report is presented elsewhere in this report.
CPL maintains a system of internal controls to provide reasonable assurance that transactions are executed in accordance with management's authorization, that the financial statements are prepared in accordance with generally accepted accounting principles and that the assets of CPL are properly safeguarded against unauthorized acquisition, use or disposition. The system includes a documented organizational structure and division of responsibility, established policies and procedures including a policy on ethical standards which provides that CPL will maintain the highest legal and ethical standards, and the careful selection, training and development of our employees.
Internal auditors continuously monitor the effectiveness of the internal control system following standards established by the Institute of Internal Auditors. Actions are taken by management to respond to deficiencies as they are identified. The board, operating through its audit committee, which is comprised entirely of directors who are not officers or employees of CPL provides oversight to the financial reporting process.
Due to the inherent limitations in the effectiveness of internal controls, no internal control system can provide absolute assurance that errors will not occur. However, management strives to maintain a balance, recognizing that the cost of such a system should not exceed the benefits derived.
CPL believes that, in all material respects, its system of internal controls over financial reporting and over safeguarding of assets against unauthorized acquisition, use or disposition functioned effectively during 1994.
Robert R. Carey R. Russell Davis President and CEO - CPL Controller - CPL
2-105
PSO
PUBLIC SERVICE COMPANY OF OKLAHOMA
2-106 Selected Financial Data PSO The following selected financial data for each of the five years ended December 31 are provided to highlight significant trends in the financial condition and results of operations for PSO.
1994 1993 1992 1991 1990 (thousands, except ratios) Operating Revenues $740,496 $707,536 $622,092 $650,942 $620,132 Income Before Cumulative Effect of Changes in Accounting Principles 68,266 40,496 45,562 53,229 55,082 Cumulative Effect of Changes in Accounting Principles (1) -- 6,223 -- -- -- Net Income 68,266 46,719 45,562 53,229 55,082 Preferred Stock Dividends 816 816 816 816 816 Net Income for Common Stock 67,450 45,903 44,746 52,413 54,266
Total Assets 1,465,114 1,420,379 1,351,201 1,308,075 1,283,915
Common Stock Equity 461,499 435,049 429,146 419,400 386,987 Preferred Stock 19,826 19,826 19,826 19,826 19,826 Long-term Debt 402,752 401,255 408,731 368,219 367,727
Ratio of Earnings to Fixed Charges (SEC Method) Before Cumulative Effect of Changes in Accounting Principles 4.03 2.78 2.95 3.33 2.93
Capitalization Ratios Common Stock Equity 52.2% 50.8% 50.0% 51.9% 50.0% Preferred Stock 2.2 2.3 2.3 2.5 2.5 Long-term Debt 45.6 46.9 47.7 45.6 47.5
(1)The 1993 cumulative effect relates to the changes in accounting for unbilled revenues, adoption of SFAS Nos. 112 and 109. See NOTE 1, Summary of Significant Accounting Policies.
PSO changed its method of accounting for unbilled revenues in 1993. Pro forma amounts, assuming that the change in accounting for unbilled revenues had been adopted retroactively, are not materially different from amounts reported for prior years and therefore have not been restated.
2-107 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PUBLIC SERVICE COMPANY OF OKLAHOMA
Reference is made to PSO's Consolidated Financial Statements and related Notes and Selected Financial Data. The information contained therein should be read in conjunction with, and is essential to understanding, the following discussion and analysis.
Overview Net income for common stock for 1994 was $67 million, a 47% increase from 1993. The increase was due primarily to increased energy sales to retail customers and sales for resale to other electric utilities due to increased market place demand and the 1993 restructuring charges of $25 million.
Restructuring As previously reported, PSO has taken steps to implement a restructuring and early retirement program designed to consolidate and restructure its operations in order to meet the challenges of the changing electric utility industry and to compete effectively in the years ahead. The underlying goal of the restructuring is to enable PSO to focus on and be accountable for serving the customer. The restructuring costs were initially estimated to be $25 million and were expensed in 1993. The final costs of the restructuring were approximately $25 million. Approximately $24 million of the restructuring expenditures were incurred during 1994, with the remaining $1 million expected to be incurred during 1995. Approximately $4 million of the restructuring expenses relate to employee termination benefits, $12 million relate to enhanced benefit costs and $9 million relate to employees that will not be terminated. Approximately $17 million of the restructuring costs were paid from or will be paid from general corporate funds. The remaining $8 million represents the present value of enhanced benefit amounts to be paid from the benefit plan trusts to participants over future years in accordance with the early retirement program. The cost of these enhanced benefit amounts will be paid from general corporate funds to the benefit plan trusts over future years. The restructuring is substantially completed, with the remaining activity to take place during 1995. Certain aspects of the restructuring are pending SEC approval under the Holding Company Act.
PSO expects to realize a number of benefits from the restructuring. Beginning in 1994 and continuing into the future, increased efficiencies and synergies are expected to be realized with the elimination of previously duplicated functions. This leads to enhanced communication and efficiency, which should translate into a reduction in the rate of growth in O&M costs. The CSW System expects that all restructuring costs will be recovered by early 1996 with reductions in the rate of growth of O&M costs continuing thereafter.
Rates and Regulatory Matters See NOTE 8, Litigation and Regulatory Proceedings, for information regarding the PSO rate case.
New Accounting Standards SFAS No. 115 was effective for fiscal years beginning after December 15, 1993. PSO adopted SFAS No. 115 in 1994. The adoption of SFAS No. 115 did not have a material effect on PSO's consolidated results of operations or financial condition.
In June 1993 the FASB issued SFAS No. 116. The statement, effective for fiscal years beginning after December 15, 1994, will be adopted by PSO for 1995. The statement establishes accounting standards for contributions and applies to all entities that receive or make contributions. Management does not believe the adoption of SFAS No. 116 will have a material impact on PSO's consolidated results of operations or financial condition.
2-108 SFAS No. 119 was effective for fiscal years ending after December 15, 1994. PSO does not currently uses derivative instruments, but may use these instruments in the future to manage the increased market risks associated with greater competition in the electric utility industry. The adoption of this new statement had no material effect on PSO's consolidated results of operations or financial condition.
Liquidity and Capital Resources Overview PSO's need for capital results primarily from the construction of facilities to provide reliable electric service to its customers. Accordingly, internally generated funds should meet most of the capital requirements. However, if internally generated funds are not sufficient, PSO's financial condition should allow it access to the capital markets.
Capital Expenditures Construction expenditures, including AFUDC, were approximately $131 million in 1994, $95 million in 1993, and $100 million in 1992. It is estimated that construction expenditures, including AFUDC, during the 1995 through 1997 period will aggregate $213 million. Such expenditures primarily will be made to improve and expand distribution facilities. These improvements are expected to meet the needs of new customers and to satisfy changing requirements of existing customers. No new baseload power plants are currently planned until after the year 2000.
The construction program continues to be monitored, reviewed and adjusted to reflect changes in estimated load growth in PSO's service area, variations in prices of alternative fuel sources, the cost of labor, materials, equipment and capital, and other external factors.
The CSW System facilities plan presently includes projected lignite-fired generating plants for which PSO has invested approximately $15 million in prior years for plant sites, engineering studies and lignite reserves. Should future plans exclude these plants for environmental or other reasons, PSO would evaluate the probability of recovery of these investments and may record appropriate reserves.
Long-Term Financing As of December 31, 1994, the capitalization ratios of PSO were 52% common stock equity, 2% preferred stock and 46% long-term debt. PSO's embedded cost of long-term debt was 7.4% at the end of 1994. PSO continually monitors the capital markets for opportunities to lower its cost of capital through refinancing. PSO continues to be committed to maintaining financial flexibility by maintaining a strong capital structure and favorable securities ratings which should allow funds to be obtained from the capital markets when required.
Short-Term Financing PSO, together with other members of CSW System, has established a CSW System money pool to coordinate short-term borrowings. These loans are unsecured demand obligations at rates approximating the CSW System's commercial paper borrowing costs. PSO's short-term borrowing limit from the money pool is $100 million. During 1994, the annual weighted average interest rate was 4.5% and the average amount of short-term month-end borrowings outstanding was $42 million. The maximum amount of short-term borrowings outstanding at any month-end during 1994 was $73 million, which was the amount outstanding at May 31, 1994.
Internally Generated Funds Internally generated funds consist of cash flows from operating activities less common and preferred stock dividends. PSO utilizes short-term debt to meet fluctuations in working capital requirements due to the seasonal nature of energy sales. PSO anticipates that capital requirements for the period 1995 to 1997 will be met in large part from internal sources. PSO also anticipates that some external financing will be required during the period, but the nature, timing and extent have not yet been determined. Information concerning internally generated funds follows:
2-109 1994 1993 1992 (millions) Internally Generated Funds $110 $93 $63
Construction Expenditures Provided by Internally Generated Funds 85% 99% 63%
Sales of Accounts Receivable PSO sells its billed and unbilled accounts receivable, without recourse, to CSW Credit. The sales provided PSO with cash immediately, thereby reducing working capital needs and revenue requirements. The average and year end amounts of accounts receivable sold were $88 million and $75 million in 1994, as compared to $85 million and $80 million in 1993.
Recent Developments and Trends Competition and Industry Challenges Competitive forces at work in the electric utility industry are impacting PSO and electric utilities generally. Increased competition facing electric utilities is driven by complex economic, political and technological factors. These factors have resulted in legislative and regulatory initiatives that are likely to result in even greater competition at both the wholesale and retail level in the future. As competition in the industry increases, PSO will have the opportunity to seek new customers and at the same time be at risk of losing customers to other competitors. PSO believes that its prices for electricity and the quality and reliability of its service currently place it in a position to compete effectively in the marketplace.
The Energy Policy Act, which was enacted in 1992, significantly alters the way in which electric utilities compete. The Energy Policy Act creates exemptions from regulation under the Holding Company Act and permits utilities, including registered utility holding companies and non-utility companies, to form EWGs. EWGs are a new category of non-utility wholesale power producer that are free from most federal and state regulation, including the principal restrictions of the Holding Company Act. These provisions enable broader participation in wholesale power markets by reducing regulatory hurdles to such participation. The Energy Policy Act also allows the FERC, on a case- by-case basis and with certain restrictions, to order wholesale transmission access and to order electric utilities to enlarge their transmission systems. A FERC order requiring a transmitting utility to provide wholesale transmission service must include provisions generally that permit (i) the utility to recover from the FERC applicant all of the costs incurred in connection with the transmission services and (ii) any enlargement of the transmission system and associated services. While PSO believes that the Energy Policy Act will continue to make the wholesale markets more competitive, PSO is unable to predict the extent to which the Energy Policy Act will impact on its operations.
Increasing competition in the utility industry brings an increased need to stabilize or reduce rates. The retail regulatory environment is beginning to shift from traditional rate base regulation to incentive regulation. Incentive rate and performance- based plans encourage efficiencies and increased productivity while permitting utilities to share in the results. Retail wheeling, a major industry issue which may require utilities to "wheel" or move power from third parties to their own retail customer, is evolving gradually.
Wholesale energy markets, including the market for wholesale electric power, have been extremely competitive since the enactment of the Energy Policy Act. PSO competes in the wholesale energy markets with other public utilities, cogenerators, qualified facilities, exempt wholesale generators and others for sales of electric power.
Under the Energy Policy Act, the FERC has approved several proposals by utility companies to sell wholesale power at market-based rates and provide to electric utilities "open access" to transmission systems, subject to certain requirements. The adoption of these proposals increases marketing opportunities for electric utilities,
2-110 but also exposes them to the risk of loss of load or reduced revenues due to competition with alternative suppliers.
PSO believes that, compared to other electric utilities, it is well positioned to meet future competition. PSO benefits from economies of scale and scope by virtue of its size and its relationship to the CSW System. PSO is also a relatively low-cost producer of electric power. Moreover, PSO is taking steps to enhance its marketing and customer service, reduce costs, improve and standardize business practices, and grow through strategic acquisitions, in order to position itself for increased competition in the future.
PSO is unable to predict the ultimate outcome or impact of competitive forces on the electric utility industry or on PSO. As the wholesale and retail electricity markets become more competitive, however, the principal factor determining success is likely to be price, and to a lesser extent, reliability, availability of capacity, and customer service.
Regulatory Accounting Consistent with industry practice and the provisions of SFAS No. 71, which allows for the recognition and recovery of regulatory assets, PSO has recognized significant regulatory assets and liabilities. Management believes that PSO will continue to meet the criteria for following SFAS No. 71. However, in the event PSO no longer meets the criteria for following SFAS No. 71, a write-off of regulatory assets and liabilities would be required. For additional information regarding SFAS No. 71 reference is made to NOTE 1, Summary of Significant Accounting Policies - Regulatory Assets and Liabilities.
Environmental Matters CERCLA and Related Matters The operations of PSO, like those of other utilities, generally involve the use and disposal of substances subject to environmental laws. The CERCLA, the federal "Superfund" law, addresses the cleanup of sites contaminated by hazardous substances. Superfund requires that PRPs fund remedial actions regardless of fault or the legality of past disposal activities. PRPs include owners and operators of contaminated sites and transporters and/or generators of hazardous substances. Many states have similar laws. Theoretically, any one PRP can be held responsible for the entire cost of a cleanup. Typically, however, cleanup costs are allocated among PRPs.
PSO is subject to various pending claims alleging it is a PRP under federal or state remedial laws for investigating and cleaning up contaminated property. PSO anticipates that resolution of these claims, individually or in the aggregate, will not have a material adverse effect on PSO's consolidated results of operations or financial condition. Although the reasons for this expectation differ from site to site, factors that are the basis for the expectation for specific sites include the volume and/or type of waste allegedly contributed by PSO, the estimated amount of costs allocated to PSO and the participation of other parties.
Clean Air Act Amendments In November 1990, the United States Congress passed the Clean Air Act which places restrictions on the emission of sulfur dioxide from gas-, coal- and lignite-fired generating plants. Beginning in the year 2000, PSO will be required to hold allowances in order to emit sulfur dioxide. The EPA issues allowances to owners of existing generating units based on historical operating conditions. Based on the CSW System facilities plan, PSO believes that its allowances will be adequate to meet its needs at least through 2008. Public and private markets are developing for trading of excess allowances. PSO presently has no intention of engaging in trading of allowances, but may seek to do so in the future if market conditions warrant and appropriate regulatory approvals are obtained.
The Clean Air Act also establishes a federal operating source permit program to be administered by the states.
2-111 The Clean Air Act also directs the EPA to issue regulations governing nitrogen oxide emissions and requires government studies to determine what controls, if any, should be imposed on utilities to control air toxics emissions. The impact that the nitrogen oxide emission regulations and the air toxics study will have on PSO cannot be determined at this time.
As a result of requirements imposed by the Clean Air Act, PSO expects to spend an additional $1.3 million for annual testing of, software modifications to, and maintenance of continuous emission monitoring equipment from 1995 through 1997.
EMFs Research is ongoing whether exposure to EMFs may result in adverse health effects. Although a few of the studies to date have suggested certain associations between EMFs and some types of effects, the research to date has not established a cause-and-effect relationship between EMFs and adverse health effects. PSO cannot predict the impact on it or the electric utility industry if further investigations or proceedings were to establish that the present electricity delivery system is contributing to increased risk or incidence of health problems.
See ITEM 1. BUSINESS - Environmental Matters and NOTE 8, Litigation and Regulatory Proceedings, for additional discussion of environmental issues.
Results of Operations Electric Operating Revenues Revenues for 1994 increased approximately $33 million or 5% when compared to 1993. Revenues for 1993 increased approximately $85.4 million or 14% when compared to 1992. The increase in 1994 reflected an increase of approximately 8% in KWH sales resulting from increased sales for resale to other electric utilities due to increased marketplace demand, partially offset by lower unit fuel costs as described below. Approximately $7.9 million of the 1993 increase was due to an increase in retail prices. Retail kilowatt-hour sales increased 7% as a result of warmer weather in 1993 compared to the substantially milder than normal weather in 1992. Additionally, 1994 and 1993 were affected by increased fuel recovery as discussed below. The Company recovers its monthly fuel and purchased power expenses currently in its revenues and therefore the increase in these costs resulted in higher revenues.
Fuel and Purchased Power Expenses Fuel expense for 1994 increased approximately $17.6 million or 6% when compared to 1993. During 1993, fuel expense increased approximately $64 million or 27% when compared to 1992. Fuel expense for 1994 and 1993 increased primarily as a result of fewer customers participating in the FUSER Program, which terminated effective October 1993. See ITEM 1. BUSINESS -- REGULATION AND RATES for additional information relating to FUSER. In 1994, fuel expense was also affected by a 17% increase in KWH generation and an over- recovery of fuel costs from customers, which was previously recorded as deferred fuel, offset in part by a reduction in average unit fuel costs. The average unit fuel cost for 1994 was $1.96 per million BTU, a decrease of approximately 18% from the same period last year. The decrease in per unit fuel cost reflects the reversal of prior years accruals for potential liabilities related to coal transportation, as well as lower costs for natural gas and coal. The increase in fuel expense during 1993 was due primarily to an increase in KWH generation and an increase in unit fuel costs. KWH generation increased 10% due primarily to increased weather-related customer usage and unscheduled 1992 power station maintenance which did not recur in 1993. The average unit fuel cost for 1993 was $2.38 per million Btu, an increase of approximately 2% from 1992 of $2.34 per million Btu. The increase in unit fuel costs was primarily due to an accrual for potential liabilities related to coal transportation, partially offset by lower costs of natural gas and coal.
Purchased power expenses for 1994 increased approximately $2.2 million or 7% as a result of additional economy energy purchases. Purchased power expenses for 1993 decreased approximately $10.4 million or 24% as a result of additional purchases of firm energy in
2-112 1992 due to unscheduled power station maintenance which did not recur in 1993.
Operating Expenses and Taxes Changes in operating expenses in 1994 and 1993 were affected by 1993 restructuring charges of approximately $25 million, which includes approximately $18 million for an early retirement and voluntary severance program. Changes in operating expenses for both years were also affected by the 1993 write-off of certain lignite properties of approximately $5 million and accrued mine reclamation expenses of approximately $3 million. Maintenance in 1993 decreased as a result of unscheduled power station maintenance in 1992.
Depreciation and amortization expense increased approximately $4 million or 7% in 1994 and $3 million or 5% in 1993 due to increases in depreciable property.
Taxes, other than federal income increased approximately $3.6 million or 13% in 1994 and decreased approximately $.5 million or 2% in 1993 primarily as a result of changes in state income taxes.
Federal income tax expense increased approximately $11.3 million or 56% in 1994 and $5.2 million or 35% in 1993 primarily as a result of increased pre-tax income. Additionally, 1993 tax expense increased as a result of an increase in the federal statutory rate from 34% in 1992 to 35% in 1993.
Inflation Annual inflation rates, as measured by the national Consumer Price Index, have averaged 2.7% during the three years ended December 31, 1994. PSO believes that inflation, at this level, does not materially affect its consolidated results of operations or financial condition. However, under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, cash flows designed to provide recovery of historical plant costs may not be adequate to replace plant in future years.
Interest Charges Interest charges for 1994 decreased approximately $1.3 million or 4% as a result of the refinancing in 1993 of higher cost debt. This decrease is offset in part by increases in short-term borrowings. In 1993, charges increased approximately $1.3 million or 4% as a result of higher principal amounts of long-term debt outstanding, offset in part by the reacquisition of higher cost debt. In 1993, interest on short-term debt and other was affected by interest accruals associated with the settlement of federal income tax audit issues partially offset by decreased short-term borrowings at lower rates.
Cumulative Effect of Changes in Accounting Principles PSO implemented a number of accounting changes in 1993. These included the adoption of SFAS No. 112 and SFAS No. 109. PSO also changed its method of accounting for unbilled revenues. These accounting changes had a cumulative effect of increasing net income approximately $6 million.
2-113 Consolidated Statements of Income Public Service Company of Oklahoma For the Years Ended December 31, 1994 1993 1992 (thousands) Electric Operating Revenues Residential $296,159 $296,027 $258,259 Commercial 227,488 222,598 203,176 Industrial 165,200 149,762 122,180 Sales for resale 35,458 18,248 17,782 Other 16,191 20,901 20,695 740,496 707,536 622,092 Operating Expenses and Taxes Fuel 316,470 298,905 234,884 Purchased power 34,906 32,711 43,134 Other operating 120,233 125,830 117,450 Restructuring charges (197) 24,995 -- Maintenance 44,847 45,777 49,027 Depreciation and amortization 63,096 59,133 56,103 Taxes, other than federal income 31,637 28,060 28,639 Federal income taxes 31,246 19,969 14,759 642,238 635,380 543,996
Operating Income 98,258 72,156 78,096
Other Income and Deductions Allowance for equity funds used during construction 1,094 1,096 349 Other 933 531 (940) 2,027 1,627 (591)
Income Before Interest Charges 100,285 73,783 77,505
Interest Charges Interest on long-term debt 29,594 31,410 30,688 Interest on short-term debt and other 3,844 2,729 1,646 Allowance for borrowed funds used during construction (1,419) (852) (391) 32,019 33,287 31,943
Income Before Cumulative Effect of Changes in Accounting Principles 68,266 40,496 45,562
Cumulative Effect of Changes in Accounting Principles -- 6,223 --
Net Income 68,266 46,719 45,562 Preferred stock dividends 816 816 816 Net Income for Common Stock $ 67,450 $ 45,903 $ 44,746
The accompanying notes to consolidated financial statements are an integral part of these statements.
2-114 Consolidated Statements of Retained Earnings Public Service Company of Oklahoma For the Years Ended December 31, 1994 1993 1992 (thousands)
Retained Earnings at Beginning of Year $97,819 $91,916 $82,170 Net income for common stock 67,450 45,903 44,746 Deduct: Common stock dividends 41,000 40,000 35,000 Retained Earnings at End of Year $124,269 $97,819 $91,916
The accompanying notes to consolidated financial statements are an integral part of these statements.
2-115 Consolidated Balance Sheets Public Service Company of Oklahoma As of December 31, 1994 1993 (thousands) ASSETS Electric Utility Plant Production $ 902,602 $ 895,315 Transmission 346,433 335,405 Distribution 668,346 626,519 General 150,898 143,834 Construction work in progress 96,133 51,931 2,164,412 2,053,004 Less - Accumulated depreciation 859,894 806,066 1,304,518 1,246,938 Current Assets Cash and temporary cash investments 5,453 2,429 Accounts receivable 21,531 36,612 Materials and supplies, at average cost 39,888 38,212 Fuel inventory, at LIFO cost 17,820 21,273 Accumulated deferred income taxes 6,670 -- Prepayments 7,889 2,755 99,251 101,281
Deferred Charges and Other Assets 61,345 72,160
$1,465,114 $1,420,379
The accompanying notes to consolidated financial statements are an integral part of these statements.
2-116 Consolidated Balance Sheets Public Service Company of Oklahoma As of December 31, 1994 1993 (thousands) CAPITALIZATION AND LIABILITIES Capitalization Common stock: $15 par value Authorized: 11,000,000 shares Issued 10,482,000 shares and outstanding 9,013,000 shares $ 157,230 $ 157,230 Paid-in capital 180,000 180,000 Retained earnings 124,269 97,819 Total Common Stock Equity 461,499 435,049 Preferred stock 19,826 19,826 Long-term debt 402,752 401,255 Total Capitalization 884,077 856,130
Current Liabilities
Advances from affiliates 55,160 31,744 Payables to affiliates 27,876 18,218 Accounts payable 59,899 55,606 Payables to customers 22,655 13,932 Accrued taxes 17,356 15,191 Accrued interest 8,867 5,382 Accumulated deferred income taxes -- 3,633 Accrued restructuring charges 1,046 24,995 Other 14,111 20,140 206,970 188,841 Deferred Credits Accumulated deferred income taxes 281,139 260,490 Investment tax credits 49,011 51,800 Income tax related regulatory liabilities, net 18,611 21,178 Other 25,306 41,940 374,067 375,408
$1,465,114 $1,420,379
The accompanying notes to consolidated financial statements are an integral part of these statements.
2-117 Consolidated Statements of Cash Flows Public Service Company of Oklahoma For the Years Ended December 31, 1994 1993 1992 (thousands) OPERATING ACTIVITIES Net Income $ 68,266 $ 46,719 $ 45,562 Non-cash Items Included in Net Income Depreciation and amortization 67,452 65,242 61,821 Restructuring charges (197) 24,995 -- Deferred income taxes and investment tax credits 4,990 6,700 18,446 Cumulative effect of changes in accounting principles -- (6,223) -- Allowance for equity funds used during construction (1,094) (1,096) (349) Changes in Assets and Liabilities Accounts receivable 15,081 (17,299) (8,793) Materials and supplies 1,777 2,872 (5,743) Accounts payable 26,375 10,332 9,540 Accrued taxes 2,165 4,240 (17,195) Accrued restructuring charges (15,626) -- -- Other deferred credits (16,634) (3,712) (13,762) Other (754) 1,322 8,955 151,801 134,092 98,482 INVESTING ACTIVITIES Construction expenditures (128,625) (92,648) (99,079) Allowance for borrowed funds used during construction (1,419) (852) (391) Other (335) (6,125) (2,419) (130,379) (99,625) (101,889) FINANCING ACTIVITIES Proceeds from issuance of long-term debt -- 181,194 113,886 Retirement of long-term debt -- (10,000) -- Reacquisition of long-term debt -- (189,685) (63,933) Change in advances from affiliates 23,416 26,454 (11,575) Payment of dividends (41,814) (40,816) (35,817) (18,398) (32,853) 2,561
Net Change in Cash and Cash Equivalents 3,024 1,614 (846) Cash and Cash Equivalents at Beginning of Year 2,429 815 1,661 Cash and Cash Equivalents at End of Year $ 5,453 $ 2,429 $ 815
SUPPLEMENTARY INFORMATION Interest paid less amounts capitalized $ 31,459 $ 34,844 $ 27,708 Income taxes paid $ 28,910 $ 9,232 $ 8,718
The accompanying notes to consolidated financial statements are an integral part of these statements
2-118 Consolidated Statements of Capitalization Public Service Company of Oklahoma As of December 31, 1994 1993 (thousands)
COMMON STOCK EQUITY $461,499 $435,049
PREFERRED STOCK (Cumulative $100 par value, authorized 700,000 shares, redeemable at the option of PSO upon 30 days notice) Number Current of Shares Redemption Series Outstanding Price
4.00% 97,900 $105.75 9,790 9,790 4.24% 100,000 103.19 10,000 10,000 Premium 36 36 19,826 19,826
LONG-TERM DEBT First Mortgage Bonds Series J, 5 1/4%, due March 1, 1996 25,000 25,000 Series K, 7 1/4%, due January 1, 1999 25,000 25,000 Series L, 7 3/8%, due March 1, 2002 30,000 30,000 Series S, 7 1/4%, due July 1, 2003 65,000 65,000 Series T, 7 3/8%, due December 1, 2004 50,000 50,000 Series U, 6 1/4%, due April 1, 2003 35,000 35,000 Series V, 7 3/8%, due April 1, 2023 100,000 100,000 Series W, 6 1/2%, due June 1, 2005 50,000 50,000 Installment sales agreement - Pollution Control Bonds Series A, 5.9%, due December 1, 2007 34,700 34,700 Series 1984, 7 7/8%, due September 15, 2014 12,660 12,660 Unamortized discount (4,756) (5,097) Unamortized costs of reacquired debt (19,852) (21,008) 402,752 401,255 TOTAL CAPITALIZATION $884,077 $856,130
The accompanying notes to consolidated financial statements are an integral part of these statements.
2-119 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.Summary of Significant Accounting Policies Public Utility Regulation PSO is subject to regulation by the SEC under the Holding Company Act and the FERC under the Federal Power Act, and follows the Uniform System of Accounts prescribed by the FERC. PSO is subject to further regulation with regard to rates and other matters by the Oklahoma Commission. PSO, as a member of the CSW System, engages in transactions and coordinates its activities and operations with other members of the CSW System.
The more significant accounting policies of PSO and its subsidiary are summarized below:
Principles of Consolidation The consolidated financial statements include the accounts of PSO and its wholly-owned subsidiary, Ash Creek Mining Company. All significant intercompany items and transactions have been eliminated.
Electric Utility Plant Electric utility plant is stated at the original cost of construction, which includes the cost of contracted services, direct labor, materials, overhead items and allowances for borrowed and equity funds used during construction.
Depreciation Provisions for depreciation of electric utility plant are computed using the straight-line method, generally at individual rates applied to the various classes of depreciable property. The annual average consolidated composite rates were 3.5% in 1994, 1993 and 1992.
Electric Revenues and Fuel Prior to January 1, 1993, electric revenues were recorded at the time billings were made to customers on a cycle-billing basis. Electric service provided subsequent to billing dates through the end of each calendar month became part of operating revenues of the next month. To conform to general industry standards, PSO changed its method of accounting to accrue for estimated unbilled revenues. The effect of this change on 1993 net income was an increase of $8.4 million included in cumulative effect of changes in accounting principles.
PSO recovers fuel costs in Oklahoma through automatic fuel recovery mechanisms. PSO recovers fuel costs applicable to wholesale customers, which are regulated by the FERC, through an automatic fuel adjustment clause. Under rules established by the Oklahoma Commission, PSO uses a method of deferred fuel accounting. The difference between fuel revenues billed and fuel expense incurred is recorded as a reduction of or an addition to fuel expense, with a corresponding entry to accounts receivable or payables to customers as appropriate. Deferred fuel costs are applied to the customers' billings as a portion of the fuel adjustment clause the second month subsequent to the month in which the under-recoveries or over-recoveries occurred.
Accounts Receivable PSO sells its billed and unbilled accounts receivable, without recourse, to CSW Credit.
Regulatory Assets and Liabilities For its regulated activities, PSO follows SFAS No. 71, which defines the criteria for establishing regulatory assets and regulatory liabilities. Regulatory assets represent probable future revenue to PSO associated with certain costs which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future refunds to customers At December 31, 1994 and 1993, PSO had recorded the following significant regulatory assets and liabilities:
2-120 1994 1993 (thousands) Regulatory Assets (Included in Deferred Charges and Other Assets on the Balance Sheets) Deferred Storm Costs $ 4,798 $ 5,876 Demand Side Management Costs 5,411 4,198 OPEBs 4,504 5,895 Other 4,945 5,621
Regulatory Liabilities Income tax related regulatory liabilities, net $18,611 $21,178
Statements of Cash Flows Cash equivalents are considered to be highly liquid debt instruments purchased with a maturity of three months or less. Accordingly, temporary cash investments are considered cash equivalents.
Reclassification Certain financial statement items for prior years have been reclassified to conform to the 1994 presentation.
Accounting Changes Effective January 1, 1993, PSO adopted SFAS Nos. 106, 112 and 109. See NOTE 2, Federal Income Taxes, for further information regarding SFAS No. 109. In addition, PSO also changed their method of accounting for unbilled revenues. See Electric Revenues and Fuel above for further information.
The adoption of SFAS No. 106 resulted in an increase in the establishment of a regulatory asset of approximately $5 million. See Note 8, Litigation and Regulatory Proceedings-Rate Review for further information. The adoption of SFAS No. 109, SFAS No. 112 and the change in accounting for unbilled revenues are presented as a cumulative effect of changes in accounting principles as shown below:
Pre-Tax Tax Net Income Effect Effect Effect SFAS No. 109 $ -- $ (268) $ (268) SFAS No. 112 (3,173) 1,227 (1,946) Unbilled revenues 13,758 (5,321) 8,437 Total $10,585 $(4,362) $6,223
Pro forma amounts, assuming that the change in accounting for unbilled revenues had been adopted retroactively, are not materially different from amounts previously reported for prior years.
2.Federal Income Taxes PSO adopted the provisions of SFAS No. 109 effective January 1, 1993. The implementation of SFAS No. 109 had no material effect on PSO's earnings. As a result of this change, PSO recognized additional accumulated deferred income taxes and corresponding regulatory assets and liabilities to ratepayers in amounts equal to future revenues or the reduction in future revenues required when the income tax temporary differences reverse and are recovered or settled in rates. As a result of a favorable earnings history, PSO did not record any valuation allowance against deferred tax assets at December 31, 1994 and 1993.
2-121 PSO, together with other members of the CSW System, files a consolidated Federal income tax return and participates in a tax sharing agreement.
Components of income taxes follow: 1994 1993 1992 Included in Operating Expenses and Taxes (thousands) Current $27,529 $13,165 $ (790) Deferred 6,506 9,595 18,260 Deferred ITC (2,789) (2,791) (2,711) 31,246 19,969 14,759 Included in Other Income and Deductions Current (4,080) (1,977) (314) Deferred 89 (1,082) (149) (3,991) (3,059) (463) Tax Effects of Cumulative Effect of Changes in Accounting Principles -- 3,954 -- $27,255 $20,864 $14,296
Investment tax credits deferred in prior years are included in income over the lives of the related properties.
Total income taxes differ from the amounts computed by applying the statutory income tax rates to income before taxes. The reasons for the differences follow: 1994 % 1993 % 1992 % (dollars in thousands) Tax at statutory rates $ 33,432 35.0 $ 23,654 35.0 $ 20,351 34.0 Differences Amortization of ITC (2,789) (2.9) (2,791) (4.1) (2,799) (4.7) Flowback of tax rate differential (1,541) (1.6) (1,629) (2.4) (1,627) (2.7) Tax effect from prior period flow through and permanent differences -- -- 1,167 1.7 1,018 1.7 Prior period adjustments (1,348) (1.4) 486 .7 (3,712) (6.2) Other (499) (0.6) (23) -- 1,065 1.8 $27,255 28.5 $20,864 30.9 $14,296 23.9
2-122 The significant components of the net deferred income tax liability follow:
1994 1993 (thousands) Deferred Income Tax Liabilities Depreciable utility plant $292,127 $287,217 Income tax related regulatory assets 15,061 15,885 Other 25,309 19,156 Total Deferred Income Tax Liabilities 332,497 322,258
Deferred Income Tax Assets Income tax related regulatory liability (22,260) (24,076) Unamortized ITC (18,957) (20,036) Other (16,811) (14,023) Total Deferred Income Tax Assets (58,028) (58,135) Net Accumulated Deferred Income Taxes - Total $274,469 $264,123
Net Accumulated Deferred Income Taxes - Noncurrent $281,139 $260,490 Net Accumulated Deferred Income Taxes - Current (6,670) 3,633 Net Accumulated Deferred Income Taxes - Total $274,469 $264,123
3.Long-Term Debt The mortgage indenture, as amended and supplemented, securing first mortgage bonds issued by PSO constitutes a direct first mortgage lien on substantially all electric utility plant. PSO may offer additional first mortgage bonds subject to market conditions and other factors.
Annual Requirements Certain series of outstanding first mortgage bonds have annual sinking fund requirements, which are generally 1% of the amount of each such series issued. These requirements may be, and generally have been, satisfied by the application of net expenditures for bondable property in an amount equal to 166-2/3% of the annual requirements. At December 31, 1994, the annual sinking fund requirements and annual maturities for the next five years follow:
Sinking Fund Requirements Maturities (thousands) 1995 $800 $ 800 1996 550 25,550 1997 550 550 1998 550 550 1999 300 25,300
Dividends PSO's mortgage indenture, as amended and supplemented, contains certain restrictions on the payment of common stock dividends. At December 31, 1994, $124 million of retained earnings were available for payment of cash dividends to its parent, CSW.
4.Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value.
2-123 Cash and temporary cash investments The carrying amount approximates fair value because of the short maturity of those instruments.
Long-term debt The fair value of PSO's long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PSO for debt of the same or similar remaining maturities.
Advances from affiliates The carrying amount approximates fair value because of the short maturity of those instruments.
The estimated fair values of PSO's financial instruments follow:
1994 1993 Carrying Fair Carrying Fair Amount Value Amount Value (thousands) Cash and temporary cash investments $ 5,453 $ 5,453 $ 2,429 $ 2,429 Long-term debt 402,752 364,585 401,255 413,218 Advances from affiliates 55,160 55,160 31,744 31,744
The fair value does not affect PSO's liabilities unless the issues are redeemed prior to their maturity dates.
5.Short Term Financing PSO, together with other members of the CSW System, has established a money pool to coordinate short-term borrowings and to make borrowings outside the money pool through CSW's issuance of commercial paper. Money pool balances are shown as advances to or from affiliates on the Consolidated Balance Sheets. At December 31, 1994, the CSW System had bank lines of credit aggregating $930 million to back up its commercial paper program. Short-term cash surpluses transferred to the money pool receive interest income in accordance with the money pool arrangement.
6.Benefit Plans Defined Benefit Pension Plan PSO, together with other members of the CSW System, maintains a tax qualified, non-contributory defined benefit pension plan covering substantially all employees. Benefits are based on employees' years of credited service, age at retirement, and final average annual earnings with an offset for the participant's primary Social Security benefit. The CSW System's funding policy is based on actuarially determined contributions, taking into account amounts which are deductible for income tax purposes and minimum contributions required by the ERISA. Pension plan assets consist primarily of common stocks and short-term and intermediate- term fixed income investments.
Contributions to the plan for the years ended December 31, 1994, 1993 and 1992 were $6.3 million, $6.7 million and $5.9 million, respectively.
The approximate maximum number of participants in the plan during 1994, were 2,000 active employees, 1,100 retirees and beneficiaries and 300 terminated employees.
2-124 The components of net periodic pension cost and the assumptions used in accounting for pensions follows: 1994 1993 1992 (thousands) Net Periodic Pension Cost Service cost $ 5,181 $ 4,642 $ 4,307 Interest cost on projected benefit obligation 14,292 13,209 12,193 Actual return on plan assets (1,011) (16,051) (10,469) Net amortization and deferral (16,064) 60 (4,748) $ 2,398 $ 1,860 $ 1,283
Discount rate 8.25% 7.75% 8.50% Long-term compensation increase 5.46% 5.46% 5.96% Return on plan assets 9.50% 9.50% 9.50%
At December 31, 1994, the plan's net assets were approximately equal to the total actuarial present value of the accumulated benefit obligation. At December 31, 1993 the plan's net assets exceeded the total actuarial present value of the accumulated benefit obligation. No reconciliation of the funding status of the plan is presented because such information is unavailable.
Health and Welfare Plans PSO had medical, dental, group life insurance, dependent life insurance, and accidental death and dismemberment plans for substantially all active PSO employees during 1994. The contributions recorded on a pay-as-you-go basis, for the years ended December 31, 1994 and 1993 were approximately $3.6 million and $5.0 million, respectively. Effective January 1993, the PSO's method of providing health benefits was modified to include such benefits as a health maintenance organization, preferred provider options, managed prescription drug and mail-order program and a mental health and substance abuse program in addition to the self- insured indemnity plans.
Postretirement Benefits Other Than Pensions PSO adopted SFAS No. 106 January 1, 1993. PSO is amortizing their transition obligation over twenty years, with eighteen years remaining. In prior years, these benefits were accounted for on a pay-as-you-go basis.
The components of net periodic postretirement benefit cost follow:
1994 1993 (thousands) Net Periodic Postretirement Benefit Cost Service cost $ 2,350 $ 2,175 Interest cost on APBO 5,317 4,811 Actual return on plan assets (495) (264) Amortization of transition obligation 2,528 2,528 Net amortization and deferral (917) (564) $ 8,783 $ 8,686
2-125 A reconciliation of the funded status of the plan to the amounts recognized on the consolidated balance sheets follow:
December 31, 1994 1993 APBO (thousands) Retirees $ 42,233 $ 41,854 Other fully eligible participants 8,077 7,904 Other active participants 14,372 17,186 Total APBO 64,682 66,944 Plan assets at fair value (21,649) (15,066) APBO in excess of plan 43,033 51,878 Unrecognized transition obligation (45,512) (48,040) Unrecognized gain or (loss) 1,903 (4,414) Accrued/(Prepaid) Cost $ (576) $ (576)
The following assumptions were used in accounting for SFAS No. 106:
1994 1993 Discount rate 8.25% 7.75% Return on plan assets 9.50% 9.00% Tax rate for taxable trusts 39.60% 39.60%
Health Care Cost Trend Rate Assumptions Pre-65 Participants: 1994 Rate of 11.75% grading down .75% per year to an ultimate rate of 6.5% in 2001.
Post-65 Participants: 1994 Rate of 11.25% grading down .75% per year to an ultimate rate of 6.0% in 2001.
Increasing the assumed health care cost trend rates by one percentage point in each year would increase the APBO as of December 31, 1994 by $7 million and increase the aggregate of the service and interest costs components on net postretirement benefits by $1 million.
7.Jointly Owned Electric Plant PSO has a joint ownership agreement with other members of the CSW System and non-affiliated entities. Such agreements provide for the joint ownership and operation of the 676 MW, coal-fired Oklaunion Power Station and its related facilities. Each participant provided financing for its share of the project, which was placed in service in December 1986. The consolidated statements of income reflect PSO's portion of operating costs associated with plant in service. PSO's share is 106 MW or a 15.6% interest in the generating station. PSO's total investment, including allowance for funds used during construction, is $80 million and accumulated depreciation at December 31, 1994 was $24 million.
8.Litigation and Regulatory Proceedings Rate Review In December 1993, the Oklahoma Commission issued an order unanimously approving a joint stipulation between PSO, the Oklahoma Commission Staff, and the Office of the Attorney General of the State of Oklahoma, as recommended by the ALJ. The order allowed PSO an increase in retail prices of $14.4 million on an annual basis which represents a $4.3 million increase above those authorized by the March 1993 interim order. In January 1994, the Oklahoma Commission issued an order unanimously approving PSO's price schedules reflecting the $14.4 million price increase. The new prices became effective beginning with the billing month of February 1994.
2-126 The December 1993 order addresses, among other things, the following issues. PSO will recover $4.5 million annually in expenses associated with OPEBs, which, for PSO, are primarily health care related benefits. Such expenses will be recovered along with amortization of the deferred 1993 OPEBs at a rate of $0.5 million per year for 10 years. PSO will amortize deferred storm expenses associated with both a 1987 ice storm and a 1992 wind storm, amounting to $1.2 million per year for five years. In addition, the order recognizes the increase in federal income tax expenses resulting from the recent increase in the federal corporate income tax rate from 34 percent to 35 percent. PSO will continue to use the depreciation rates previously approved by the Oklahoma Commission. PSO agreed that it will not file another retail price increase application until after June 30, 1995.
Gas Transportation and Fuel Management Fees An order issued by the Oklahoma Commission in 1991 required that the level of gas transportation and fuel management fees, paid to Transok by PSO, permitted for recovery through the fuel adjustment clause be reviewed in the aforementioned price proceeding. This portion of the price review was bifurcated. In March 1995, an order was issued by the Oklahoma Commission approving an agreement which allows PSO to recover approximately $28.4 million of transportation and fuel management fees in base rates using 1991 determinants and approximately $1 million through the fuel adjustment clause. The agreement also requires the phase-in of competitive bidding of natural gas transportation requirements in excess of 165 MMcf/d.
Gas Purchase Contracts PSO has been named defendant in complaints filed in federal and state courts of Oklahoma and Texas in 1984 through February 1995 by gas suppliers alleging claims arising out of certain gas purchase contracts. Cases currently pending seek approximately $29 million in actual damages, together with claims for punitive damages which, in compliance with pleading code requirements, are alleged to be in excess of $10,000. The plaintiffs seek relief through the filing dates as well as attorney fees. As a result of settlements among the parties, certain plaintiffs dismissed their claims with prejudice to further action. The settlements did not have a significant effect on PSO's consolidated results of operations. The remaining suits are in the preliminary stages. Management cannot predict the outcome of these proceedings. However, management believes that PSO has defenses to these complaints and intends to pursue them vigorously. Management also believes that the ultimate resolution of the remaining complaints will not have a material adverse effect on PSO's consolidated results of operations or financial condition.
PCB Cases PSO has been named defendant in complaints filed in federal and state court in Oklahoma in 1984, 1985, 1986 and 1993. The complaints allege, among other things, that some of the plaintiffs and the property of other plaintiffs were contaminated with PCBs and other toxic by-products following certain incidents, including transformer malfunctions in April 1982, December 1983 and May 1984. To date, complaints represent approximately $736 million, including compensatory and punitive damages of claims have been dismissed, certain of which resulted from settlements among the parties. The settlements did not have a significant effect on PSO's consolidated results of operations. Remaining complaints currently total approximately $395 million, of which approximately one-third is for punitive damages. Discovery with regard to the remaining complaints continues. Management cannot predict the outcome of these proceedings. However, management believes that PSO has defenses to these complaints and intends to pursue them vigorously. Moreover, management has reason to believe that PSO's insurance may cover some of the claims. Management also believes that the ultimate resolution of the remaining complaints will not have a material adverse effect on PSO's consolidated results of operations or financial condition.
Burlington Northern Transportation Contract In June 1992, PSO filed suit in Federal District Court in Tulsa, Oklahoma, against Burlington Northern seeking declaratory relief under a long-term contract for the transportation of coal. In July 1992, Burlington Northern asserted counterclaims against PSO alleging that PSO breached the contract. The counterclaims sought
2-127 damages in an unspecified amount. In December 1993, PSO amended its suit against Burlington Northern seeking damages and declaratory relief under federal and state anti-trust laws. PSO and Burlington Northern filed motions for summary judgment on certain dispositive issues in the litigation. In March 1994, the court issued an order granting PSO's motions for summary judgment and denying Burlington Northern's motion. It was not necessary for the court to decide the federal and state anti-trust claims raised by PSO. Judgment was rendered in favor of PSO by the United States District Court in May 1994. In June 1994, Burlington Northern appealed this judgment to the United States Court of Appeals for the Tenth Circuit. This appeal is now pending.
Burlington Northern Arbitration In May 1994, in a related arbitration, an arbitration panel made an award favorable to PSO concerning basic transportation rates under the coal transportation contract described above, and concerning the contract mechanism for adjustment of future transportation rates. These arbitrated issues were not involved in the related lawsuit described above. Burlington Northern filed an action to vacate the arbitrated award in the District Court for Dallas County, Texas. PSO removed this action to the United States District Court for the Northern District of Texas, and filed a motion to either dismiss this action or have it transferred to the United States District Court for the Northern District of Oklahoma. Burlington Northern moved to remand the action to state court. In September 1994, the United States District Court for the Northern District of Texas denied Burlington Northern's motion to remand, and granted PSO's motion to transfer the action to the United States District Court for the Northern District of Oklahoma. Separately, PSO filed an action to confirm the arbitration award in the United States District Court for the Northern District of Oklahoma, and Burlington Northern filed a motion to dismiss this confirmation action. On December 6, 1994, the District Court entered an order denying Burlington Northern's motion to vacate the arbitration award, and granting PSO's motion to confirm the arbitration award. On December 29, 1994, the District Court entered judgment confirming the arbitration award, including a money judgment in PSO's favor for $16.4 million, with interest at 7.2% per annum compounded annually from December 21, 1994 until paid. On January 6, 1995, Burlington Northern appealed the District Court's judgment to the United States Court of Appeals for the Tenth Circuit. This appeal is now pending.
Coal Mine Reclamation In August 1994, PSO received approval from the Wyoming Department of Environmental Quality to begin reclamation of a coal mine in Sheridan, Wyoming owned by Ash Creek Mining Company, a wholly- owned subsidiary of PSO. Ash Creek Mining Company recorded a $3 million liability in 1993 for the estimated reclamation costs. Actual reclamation work is expected to commence in mid-1995, with completion estimated in late 1996. Surveillance monitoring will continue for ten years after final reclamation. Management believes the ultimate resolution of this matter will not have a material adverse effect on PSO's consolidated results of operations or financial condition.
Other PSO is party to various other legal claims, actions and complaints arising in the normal course of business. Management does not expect disposition of these matters to have a material adverse effect on PSO's consolidated results of operations or financial condition.
9. Commitments and Contingent Liabilities It is estimated that PSO will spend approximately $71 million in capital expenditures during 1995. Substantial commitments have been made in connection with the 1995 construction program
To supply the fuel requirements of its generating plants, PSO has entered into various commitments for the procurement of fuel.
2-128 10. Quarterly Information (Unaudited) The following unaudited quarterly information includes, in the opinion of management, all adjustments necessary for a fair presentation of such amounts.
Operating Operating Net Quarter Ended Revenues Income Income 1994 (thousands) March 31 $ 157,509 $ 12,427 $ 4,307 June 30 174,631 23,808 15,927 September 30 246,378 47,196 40,003 December 31 161,978 14,827 8,029 $ 740,496 $ 98,258 $ 68,266
March 31 $ 145,110 $ 12,312 $ 10,113 June 30 161,237 23,935 15,605 September 30 242,871 46,221 38,641 December 31 158,318 (10,312) (17,640) $ 707,536 $ 72,156 $ 46,719
Information for quarterly periods is affected by seasonal variations in sales, rate changes, timing of fuel expense recovery and other factors.
2-129 Report of Independent Public Accountants
To the Stockholders and Board of Directors of Public Service Company of Oklahoma:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Oklahoma (an Oklahoma corporation and a wholly-owned subsidiary of Central and South West Corporation) and subsidiary company, as of December 31, 1994 and 1993, and the related consolidated statements of income, retained earnings and cash flows, for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of PSO's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Public Service Company of Oklahoma and subsidiary company as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
In 1993, as discussed in NOTE 1, PSO changed its methods of accounting for unbilled revenues, postretirement benefits other than pensions, income taxes and postemployment benefits.
Our audits were made for the purpose of forming an opinion on the financial statements taken as a whole. The supplemental Schedule II and Exhibit 12 are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. This schedule and exhibit have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Arthur Andersen LLP
Tulsa, Oklahoma February 13, 1995
2-130 Report of Management
Management is responsible for the preparation, integrity and objectivity of the consolidated financial statements of Public Service Company of Oklahoma and its subsidiary company as well as other information contained in this Annual Report. The consolidated financial statements have been prepared in conformity with generally accepted accounting principles applied on a consistent basis and, in some cases, reflect amounts based on the best estimates and judgments of management, giving due consideration to materiality. Financial information contained elsewhere in this Annual Report is consistent with that in the consolidated financial statements.
The consolidated financial statements have been audited by the independent accounting firm, Arthur Andersen LLP, which was given unrestricted access to all financial records and related data, including minutes of all meetings of shareholders, the board of directors and committees of the board. PSO and its subsidiary believe that representations made to the independent auditors during their audit were valid and appropriate. Arthur Andersen LLP's audit report is presented elsewhere in this report.
PSO, together with its subsidiary company, maintains a system of internal controls to provide reasonable assurance that transactions are executed in accordance with management's authorization, that the consolidated financial statements are prepared in accordance with generally accepted accounting principles and that the assets of the companies are properly safeguarded against unauthorized acquisition, use or disposition. The system includes a documented organizational structure and division of responsibility, established policies and procedures including a policy on ethical standards which provides that PSO will maintain the highest legal and ethical standards, and the careful selection, training and development of our employees.
Internal auditors continuously monitor the effectiveness of the internal control system following standards established by the Institute of Internal Auditors. Actions are taken by management to respond to deficiencies as they are identified. The board, operating through its audit committee, which is comprised entirely of directors who are not officers or employees of PSO or its subsidiary, provides oversight to the financial reporting process.
Due to the inherent limitations in the effectiveness of internal controls, no internal control system can provide absolute assurance that errors will not occur. However, management strives to maintain a balance, recognizing that the cost of such a system should not exceed the benefits derived.
PSO and its subsidiary believe that, in all material respects, its system of internal controls over financial reporting and over safeguarding of assets against unauthorized acquisition, use or disposition functioned effectively during 1994.
Robert L. Zemanek R. Russell Davis President and CEO - PSO Controller - PSO
2-131
SWEPCO
SOUTHWESTERN ELECTRIC POWER COMPANY Selected Financial Data SWEPCO The following selected financial data for each of the five years ended December 31 are provided to highlight significant trends in the financial condition and results of operations for SWEPCO.
1994 1993 1992 1991 1990 (thousands, except ratios) Operating Revenues $825,296 $837,192 $778,303 $760,694 $735,217 Income Before Cumulative Effect of Changes in Accounting Principles 105,712 78,471 94,883 96,624 89,713 Cumulative Effect of Changes in Accounting Principles (1) -- 3,405 -- -- -- Net Income 105,712 81,876 94,883 96,624 89,713 Preferred Stock Dividends 3,361 3,362 3,445 3,465 3,528 Net Income for Common Stock 102,351 78,514 91,438 93,159 86,185
Total Assets 2,079,207 1,968,285 1,927,320 1,851,108 1,869,340
Common Stock Equity 678,122 645,731 647,217 645,780 641,554 Preferred Stock Not Subject to Mandatory Redemption 16,032 16,032 16,032 16,033 14,358 Subject to Mandatory Redemption 34,828 36,028 37,228 38,416 36,422 Long-term Debt 595,833 602,065 532,860 573,626 576,095
Ratio of Earnings to Fixed Charges (SEC Method) Before Cumulative Effect of Changes in Accounting Principles 3.70 3.27 3.39 3.51 3.03
Capitalization Ratios Common Stock Equity 51.2% 49.7% 52.5% 50.7% 50.6% Preferred Stock 3.8 4.0 4.3 4.3 4.0 Long-term Debt 45.0 46.3 43.2 45.0 45.4
(1) The 1993 cumulative effect relates to the changes in accounting for unbilled revenues and adoption of SFAS No. 112. See NOTE 1, Summary of Significant Accounting Policies.
SWEPCO changed its method of accounting for unbilled revenues in 1993. Pro forma amounts, assuming that the change in accounting for unbilled revenues had been adopted retroactively, are not materially different from amounts reported for prior years and therefore have not been restated.
2-133 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SOUTHWESTERN ELECTRIC POWER COMPANY
Reference is made to SWEPCO's Financial Statements and related Notes and Selected Financial Data. The information contained therein should be read in conjunction with, and is essential in understanding, the following discussion and analysis.
Overview Net income for common stock increased 30% during 1994 to approximately $102.4 million from approximately $78.5 million in 1993, due primarily to the effects of restructuring costs recorded during 1993.
Restructuring As previously reported, SWEPCO has taken steps to implement a restructuring and early retirement program designed to consolidate and restructure its operations in order to meet the challenges of the changing electric utility industry and to compete effectively in the years ahead. The underlying goal of the restructuring is to enable SWEPCO to focus on and be accountable for serving the customer. The restructuring costs were initially estimated to be $25 million and were expensed in 1993. The final costs of the restructuring were approximately $20 million. Approximately $19 million of the restructuring expenditures were incurred during 1994, with the remaining $1 million expected to be incurred during 1995. Approximately $1 million of the restructuring expenses relate to employee termination benefits, $12 million relate to enhanced benefit costs and $7 million relate to employees that will not be terminated. Approximately $13 million of the restructuring costs were paid from or will be paid from general corporate funds. The remaining $7 million represents the present value of enhanced benefit amounts to be paid from the benefit plan trusts to participants over future years in accordance with the early retirement program. The cost of these enhanced benefit amounts will be paid from general corporate funds to the benefit plan trusts over future years. The restructuring is substantially completed, with the remaining activity to take place during 1995. Certain aspects of the restructuring are pending SEC approval under the Holding Company Act.
SWEPCO expects to realize a number of benefits from the restructuring. Beginning in 1994 and continuing into the future, increased efficiencies and synergies are expected to be realized with the elimination of previously duplicated functions. This leads to enhanced communication and efficiency, which should translate into a reduction in the rate of growth in O&M costs. The CSW System expects that all restructuring costs will be recovered by early 1996 with reductions in the rate of growth of O&M costs continuing thereafter.
Rates and Regulatory Matters See NOTE 9, Litigation and Regulatory Proceedings, for information regarding the SWEPCO fuel reconciliation proceeding.
New Accounting Standards SFAS No. 115 was effective for fiscal years beginning after December 15, 1993. SWEPCO adopted SFAS No. 115 in 1994. The adoption of SFAS No. 115 did not have a material effect on SWEPCO's results of operations or financial condition.
In June 1993 the FASB issued SFAS No. 116. The statement, effective for fiscal years beginning after December 15, 1994, will be adopted by SWEPCO for 1995. The statement establishes accounting standards for contributions and applies to all entities that receive or make contributions. Management does not believe the adoption of SFAS No. 116 will have a material impact on SWEPCO's results of operations or financial condition.
2-134 SFAS No. 119 was effective for fiscal years ending after December 15, 1994. SWEPCO does not currently use derivative financial instruments, but may use these instruments in the future to manage the increased market risks associated with greater competition in the electric utility industry. The adoption of this new statement had no material effect on SWEPCO's results of operations or financial condition.
Liquidity and Capital Resources Overview SWEPCO's need for capital results primarily from its construction of facilities to provide reliable electric service to its customers. Accordingly, internally generated funds should meet most of the capital requirements. However, if internally generated funds are not sufficient, SWEPCO's financial condition should allow it access to the capital markets.
Capital Expenditures Construction expenditures, including AFUDC, were approximately $153 million in 1994, $176 million in 1993 and $97 million in 1992. Included in the expenditures for 1993 was approximately $35 million for the acquisition of BREMCO, a rural electric cooperative with service territory adjacent to SWEPCO's service territory in Louisiana. Construction expenditures during the period 1995-1997 are estimated at $286 million. These expenditures will consist primarily of expansion and improvements to distribution facilities. No new baseload power plants are currently planned until after the year 2000.
The construction program continues to be monitored, reviewed and adjusted to reflect changes in estimated load growth in SWEPCO's service area, variations in prices of alternative fuel sources, the cost of labor, materials, equipment and capital, and other external factors.
The CSW System facilities plan presently includes projected coal- and lignite-fired generating plants for which SWEPCO has invested approximately $34 million in prior years for plant sites, engineering studies and lignite reserves. Should future plans exclude these plants for environmental or other reasons, SWEPCO would evaluate the probability of recovery of these investments and may record appropriate reserves.
Long-Term Financing As of December 31, 1994, the capitalization ratios of SWEPCO were 51% common stock equity, 4% preferred stock and 45% long-term debt. SWEPCO's embedded cost of long-term debt was 7.6% at the end of 1994. SWEPCO continually monitors the capital markets for opportunities to lower its cost of capital through refinancing. SWEPCO continues to be committed to maintaining financial flexibility by maintaining a strong capital structure and favorable securities rating which should allow funds to be obtained from the capital markets when required.
SWEPCO's long-term financing activity for 1994 is summarized below:
In June 1994, SWEPCO renegotiated a $50 million term loan due June 1997, changing certain terms, including an extension of the maturity to June 2000.
In several transactions during 1994, SWEPCO redeemed $5.8 million, which represented all remaining bonds outstanding of its 9- 1/8% First Mortgage Bonds, Series U, due November 1, 2019. The funds required for these transactions were provided from short-term borrowings and internal sources. Redemption premiums are included in long-term debt on the balance sheets and are being amortized over 5 to 30 years, in accordance with anticipated regulatory treatment.
Short-Term Financing SWEPCO, together with other members of CSW System, has established a CSW System money pool to coordinate short-term borrowings. These loans are unsecured demand obligations at rates approximating the CSW System's commercial paper borrowing costs.
2-135 SWEPCO's short-term borrowing limit from the money pool is $150 million. During 1994, the annual weighted average interest rate was 4.5% and the average amount of short-term borrowings outstanding at month-end was $25 million. The maximum amount of short-term borrowings outstanding at any month-end during 1994 was $82 million, which was the amount outstanding at December 31, 1994.
Internally Generated Funds Internally generated funds consist of cash flows from operating activities less common and preferred stock dividends. SWEPCO utilizes short-term debt to meet fluctuations in working capital requirements due to the seasonal nature of energy sales. SWEPCO anticipates that capital requirements for the period 1995 to 1997 will be met, in large part, from internal sources. SWEPCO also anticipates that some external financing will be required during the period, however the nature, timing and extent have not yet been determined. Information concerning internally generated funds follows:
1994 1993 1992 (millions) Internally Generated Funds $105 $149 $75
Construction Expenditures Provided by Internally Generated Funds 71% 85% 78%
Sales of Accounts Receivable SWEPCO sells its billed and unbilled accounts receivable, without recourse, to CSW Credit. The sales provide SWEPCO with cash immediately, thereby reducing working capital needs and revenue requirements. The average and year end amounts of accounts receivable sold were $69 million and $62 million in 1994, as compared to $64 million and $57 million in 1993.
Recent Developments and Trends Competition and Industry Challenges Competitive forces at work in the electric utility industry are impacting SWEPCO and electric utilities generally. Increased competition facing electric utilities is driven by complex economic, political and technological factors. These factors have resulted in legislative and regulatory initiatives that are likely to result in even greater competition at both the wholesale and retail level in the future. As competition in the industry increases, SWEPCO will have the opportunity to seek new customers and at the same time be at risk of losing customers to other competitors. SWEPCO believes that its prices for electricity and the quality and reliability of its service currently place it in a position to compete effectively in the marketplace.
The Energy Policy Act, which was enacted in 1992, significantly alters the way in which electric utilities compete. The Energy Policy Act creates exemptions from regulation under the Holding Company Act and permits utilities, including registered utility holding companies and non-utility companies, to form EWGs. EWGs are a new category of non-utility wholesale power producer that are free from most federal and state regulation, including the principal restrictions of the Holding Company Act. These provisions enable broader participation in wholesale power markets by reducing regulatory hurdles to such participation. The Energy Policy Act also allows the FERC, on a case- by-case basis and with certain restrictions, to order wholesale transmission access and to order electric utilities to enlarge their transmission systems. A FERC order requiring a transmitting utility to provide wholesale transmission service must include provisions generally that permit (i) the utility to recover from the FERC applicant all of the costs incurred in connection with the transmission services and (ii) any enlargement of the transmission system and associated services. While SWEPCO believes that the Energy Policy Act will continue to make the wholesale markets more competitive, SWEPCO is unable to predict the extent to which the Energy Policy Act will impact its operations.
2-136 Increasing competition in the utility industry brings an increased need to stabilize or reduce rates. The retail regulatory environment is beginning to shift from traditional rate base regulation to incentive regulation. Incentive rate and performance- based plans encourage efficiencies and increased productivity while permitting utilities to share in the results. Retail wheeling, a major industry issue which may require utilities to "wheel" or move power from third parties to their own retail customer, is evolving gradually.
Wholesale energy markets, including the market for wholesale electric power, have been extremely competitive since the enactment of the Energy Policy Act. SWEPCO competes in the wholesale energy markets with other public utilities, cogenerators, qualified facilities, exempt wholesale generators and others for sales of electric power.
Under the Energy Policy Act, the FERC has approved several proposals by utility companies to sell wholesale power at market-based rates and provide to electric utilities "open access" to transmission systems, subject to certain requirements. The adoption of these proposals increases marketing opportunities for electric utilities, but also exposes them to the risk of loss of load or reduced revenues due to competition with alternative suppliers.
SWEPCO believes that, compared to other electric utilities, it is well positioned to meet future competition. SWEPCO benefits from economies of scale and scope by virtue of its size and its relationship to the CSW System. SWEPCO is also a relatively low-cost producer of electric power. Moreover, SWEPCO is taking steps to enhance its marketing and customer service, reduce costs, improve and standardize business practices, and grow through strategic acquisitions, in order to position itself for increased competition in the future.
SWEPCO is unable to predict the ultimate outcome or impact of competitive forces on the electric utility industry or on SWEPCO. As the wholesale and retail electricity markets become more competitive, however, the principal factor determining success is likely to be price, and to a lesser extent, reliability, availability of capacity, and customer service.
Public Utility Regulatory Act PURA is the legal foundation for electric utility regulation in Texas. PURA will expire on September 1, 1995, in accordance with the sunset policy of the Texas Legislature, which applies to all state agencies, unless the Texas Legislature reenacts PURA in its current form or in modified form. Several proposals have been made to amend PURA which, among other things, provide for a market-driven integrated resource planning process, pricing flexibility for utilities faced with competitive challenges, incentive regulation and deregulation of the wholesale bulk power market in ERCOT. SWEPCO is unable to predict the ultimate outcome of the 1995 session of the Texas Legislature and in particular whether amendments to PURA will be adopted.
Regulatory Accounting Consistent with industry practice and the provisions of SFAS No. 71, which allows for the recognition and recovery of regulatory assets, SWEPCO has recognized regulatory assets and liabilities. Management believes that SWEPCO will continue to meet the criteria for following SFAS No. 71. However, in the event the SWEPCO no longer meets the criteria for following SFAS No. 71, a write-off of regulatory assets and liabilities would be required. For additional information regarding SFAS No. 71 reference is made to NOTE 1, Summary of Significant Accounting Policies - Regulatory Assets and Liabilities.
Consolidated Taxes The Texas Commission before 1992 allowed income taxes to be recovered in rates based on the federal income tax incurred by a utility as if it were a stand-alone company. This stand-alone approach treated the regulated activities of a utility as a separate entity and considered only those revenues and expenses that are included in the utility's cost of service to calculate the federal income tax liability for ratemaking purposes.
2-137 Beginning in 1992, the Texas Commission changed its method of calculating the federal income tax component of rates to the "actual tax approach." The actual tax approach is an evolving concept but generally seeks to reflect in rates the actual tax liability of the utility irrespective of its relationship to the utility's cost of service. The approach reduces rates by the tax benefits of deductions which are not considered for or included in setting rates for the utility.
SWEPCO believes that the recovery of federal income taxes in rates should be determined on the stand-alone approach for ratemaking purposes, but there is no assurance this approach will be adopted.
Environmental Matters CERCLA and Related Matters The operations of SWEPCO, like those of other utilities, generally involve the use and disposal of substances subject to environmental laws. The CERCLA, the federal "Superfund" law, addresses the cleanup of sites contaminated by hazardous substances. Superfund requires that PRPs fund remedial actions regardless of fault or the legality of past disposal activities. PRPs include owners and operators of contaminated sites and transporters and/or generators of hazardous substances. Many states have similar laws. Theoretically, any one PRP can be held responsible for the entire cost of a cleanup. Typically, however, cleanup costs are allocated among PRPs.
SWEPCO is subject to various pending claims alleging that it is a PRP under federal or state remedial laws for investigating and cleaning up contaminated property. SWEPCO anticipates that resolution of these claims, individually or in the aggregate, will not have a material adverse effect on SWEPCO's results of operations or financial condition. Although the reasons for this expectation differ from site to site, factors that are the basis for the expectation for specific sites include the volume and/or type of waste allegedly contributed by SWEPCO, the estimated amount of costs allocated to SWEPCO and the participation of other parties.
MGPs Contaminated former MGPs are a type of site which utilities, and others, may have to remediate in the future under Superfund or other federal or state remedial programs. Gas was manufactured at MGPs from the mid-1800s to the mid-1900s. In some cases, utilities and others have faced potential liability for MGPs because they, or their alleged predecessors, owned or operated the plants. In other cases, utilities or others may have been subjected to such liability for MGPs because they acquired MGP sites after gas production ceased.
Suspected MGP Site in Marshall, Texas SWEPCO owns a suspected former MGP site in Marshall, Texas. SWEPCO has notified the TNRCC that evidence of contamination has been found at the site. As a result of sampling conducted at the end of 1993 and early 1994, SWEPCO is evaluating the extent, if any, to which contamination has impacted soil, groundwater and other conditions in the area. A final range of clean-up costs has not yet been determined, but, based on a preliminary estimate, SWEPCO has accrued approximately $2 million as a liability for this site on SWEPCO's books as of December 31, 1993. As more information is obtained about the site, and SWEPCO discusses the site with the TNRCC, the preliminary estimate may change.
Suspected MGP Site in Texarkana, Texas and Arkansas and Shreveport, Louisiana SWEPCO also owns a suspected former MGP site in Texarkana, Texas and Arkansas. The EPA ordered an initial investigation of this site, as well as one in Shreveport, Louisiana, which is no longer owned by SWEPCO. The contractor who performed the investigations of these two sites recommended to the EPA that no further action be taken at this time.
Suspected Biloxi, Mississippi MGP Site SWEPCO has been notified by Mississippi Power Company that it may be a PRP at the former Biloxi MGP site formerly owned and operated by a predecessor of SWEPCO. SWEPCO is working with Mississippi Power
2-138 Company to investigate the extent of contamination at this site. The MDEQ approved a site investigation work plan and, in January 1995, SWEPCO and Mississippi Power Company initiated sampling pursuant to that work plan. On an interim basis, SWEPCO and Mississippi Power Company are each paying fifty percent of the cost of implementing the site investigation work plan. That interim allocation is subject to a final allocation in the future. SWEPCO and Mississippi Power Company are investigating whether there are other PRPs at the Biloxi site. Until the extent of the contamination at the Biloxi site is identified, it is unknown what, if any, additional investigation or cleanup may be required.
Management does not expect these matters to have a material effect on SWEPCO's results of operations or financial position.
Clean Air Act Amendments In November 1990, the United States Congress passed the Clean Air Act which places restrictions on the emission of sulfur dioxide from gas-, coal- and lignite-fired generating plants. Beginning in the year 2000, SWEPCO will be required to hold allowances in order to emit sulfur dioxide. EPA issues allowances to owners of existing generating units based on historical operating conditions. Based on the CSW System facilities plan, SWEPCO believes that its allowances will be adequate to meet its needs at least through 2008. Public and private markets are developing for trading of excess allowances. SWEPCO presently has no intention of engaging in trading of allowances, but may seek to do so in the future if market conditions warrant and appropriate regulatory approvals are obtained.
The Clean Air Act also establishes a federal operating source permit program to be administered by the states.
The Clean Air Act also directs the EPA to issue regulations governing nitrogen oxide emissions and requires government studies to determine what controls, if any, should be imposed on utilities to control air toxics emissions. The impact that the nitrogen oxide emission regulations and the air toxics study will have on SWEPCO cannot be determined at this time.
As a result of requirements imposed by the Clean Air Act, SWEPCO expects to spend an additional $1.3 million for annual testing of, software modifications to, and maintenance of continuous emission monitoring equipment from 1995 through 1997.
EMFs Research is ongoing whether exposure to EMFs may result in adverse health effects. Although a few of the studies to date have suggested certain associations between EMFs and some types of effects, the research to date has not established a cause-and-effect relationship between EMFs and adverse health effects. SWEPCO cannot predict the impact on SWEPCO or the electric utility industry if further investigations or proceedings were to establish that the present electricity delivery system is contributing to increased risk or incidence of health problems.
See ITEM 1. BUSINESS - ENVIRONMENTAL MATTERS and NOTE 10, Commitments and Contingent Liabilities, for additional discussion of environmental issues.
Results of Operations Electric Operating Revenues Total electric operating revenues decreased $11.9 million or 1% during 1994 due primarily to decreased fuel revenues partially offset by a 3% increase in retail KWH sales due to customer growth and a 15% increase in sales for resale. Sales for resale to non-affiliated electric utilities and rural electric cooperatives increased approximately $9.4 million during the year. Total revenues increased approximately $59 million in 1993 when compared to the prior year. The increase was due primarily to a 6% increase in KWH sales
2-139 resulting from favorable weather and customer growth due to the acquisition of BREMCO in 1993 as well as increased sales for resale.
Fuel and Purchased Power Expenses Fuel expense decreased approximately $27.2 million or 7% during 1994 and increased approximately $28 million or 8% during 1993. The decrease in 1994 is due primarily to a decrease in unit fuel costs from $1.94 in 1993 to $1.75 in 1994. The decrease in unit fuel costs is primarily due to coal contract settlements and a decrease in the cost of spot market gas. This decrease was partially offset by a 4% increase in generation. The increase in 1993 is attributable to an 8% increase in generation and an increase in unit fuel costs from $1.93 in 1992 to $1.94 in 1993.
Purchased power costs increased approximately $7.1 million in 1994 and $6.5 million in 1993. The 1994 increase was due primarily to a purchased power contract negotiated as a part of the 1993 purchase of BREMCO. The increase in 1993 was largely due to scheduled and unscheduled maintenance at the Company's generating facilities and the above-mentioned purchased power contract.
Operating Expenses and Taxes Other operating expenses increased approximately $18.1 million in 1993 due primarily to expensing of reserves for certain lignite properties, outside and legal services, and an increase in employee benefit expenses in 1993 resulting form the adoption of SFAS No. 106.
Restructuring charges reflect the initial estimated cost of the restructuring of $25.2 million. As the restructuring progressed, this amount was adjusted during 1994 to approximately $20 million.
Maintenance expense decreased approximately $7.4 million in 1994 and increased approximately $8 million in 1993 when compared to 1992. The changes during both periods are due to increased maintenance of distribution facilities and general plant in 1993.
Taxes, other than federal income, increased approximately $4.4 million or 10% in 1993 due primarily to a Texas franchise tax refund recognized in 1992.
Federal income tax expense increased approximately $13.1 million or 48% in 1994 primarily as a result of increased pre-tax income. In 1993, federal income taxes decreased approximately $5.8 million or 18% as a result of lower pre-tax income partially offset by an increase in the federal income tax rate from 34% to 35%.
Inflation Annual inflation rates, as measured by the national Consumer Price Index, have averaged approximately 2.7% for the three-year period ending December 31, 1994. Inflation at these levels does not materially affect SWEPCO's results of operations or financial condition. Under existing regulatory practice, however, only the historical cost of plant is recoverable from customers. As a result, cash flows designed to provide recovery of historical plant costs may not be adequate to replace plant in future years.
Allowance for Equity and Debt Funds Used During Construction AFUDC is a function of the amounts of construction on which AFUDC is calculated and the rate used. The increases in 1994 and 1993 were due primarily to increased construction work in process.
Interest on Long-Term Debt Interest expense on long-term debt increased in 1994 approximately $2.4 million or 6% due primarily to an increase in average balances outstanding. The 1993 decrease of approximately $6.5 million is attributable to the refinancing of higher cost debt with lower cost debt.
2-140 Interest on Short-Term Debt and Other Interest expense on short-term debt and other increased approximately $2.7 million in 1994 when compared to 1993 due primarily to an interest accrual pursuant to the terms of a settlement agreement approved by the Texas Commission in connection with SWEPCO's fuel reconciliation and increased interest expense associated with short-term debt.
Cumulative Effect of Changes in Accounting Principles Accounting changes in 1993 include the adoption of SFAS 112. SWEPCO also changed its method of accounting for unbilled revenues. These accounting changes had a cumulative effect of increasing net income by $3.4 million.
2-141 Statements of Income Southwestern Electric Power Company For the Years Ended December 31, 1994 1993 1992 (thousands) Electric Operating Revenues Residential $266,620 $273,707 $249,182 Commercial 173,718 175,059 165,836 Industrial 243,518 250,912 243,508 Sales for resale 102,723 93,337 78,814 Other 38,717 44,177 40,963 825,296 837,192 778,303 Operating Expenses and Taxes Fuel 336,389 363,627 335,594 Purchased power 20,244 13,145 6,620 Other operating 119,277 118,665 100,598 Restructuring charges (4,978) 25,203 -- Maintenance 42,782 50,164 42,191 Depreciation and amortization 79,845 74,385 72,300 Taxes, other than federal income 45,735 46,942 42,502 Federal income taxes 40,080 27,004 32,771 679,374 719,135 632,576
Operating Income 145,922 118,057 145,727
Other Income and Deductions Allowance for equity funds used during construction 3,579 1,560 132 Other 4,656 3,658 537 8,235 5,218 669
Income Before Interest Charges 154,157 123,275 146,396
Interest Charges Interest on long-term debt 43,395 40,958 47,490 Interest on short-term debt and other 7,568 4,866 4,073 Allowance for borrowed funds used during construction (2,518) (1,020) (50) 48,445 44,804 51,513 Income Before Cumulative Effect of Changes in Accounting Principles 105,712 78,471 94,883
Cumulative Effect of Changes in Accounting Principles -- 3,405 --
Net Income 105,712 81,876 94,883 Preferred stock dividends 3,361 3,362 3,445 Net Income for Common Stock $ 102,351 $ 78,514 $ 91,438
The accompanying notes to financial statements are an integral part of these statements.
2-142 Statements of Retained Earnings Southwestern Electric Power Company For the Years Ended December 31, 1994 1993 1992 (thousands) Retained Earnings at Beginning of Year $265,071 $266,557 $265,120 Net income for common stock 102,351 78,514 91,438 Gain on reacquisition of preferred stock 40 -- -- Deduct: Common stock dividends 70,000 80,000 90,000 Preferred stock redemption cost -- -- 1 Retained Earnings at End of Year $297,462 $265,071 $266,557
The accompanying notes to financial statements are an integral part of these statements.
2-143 Balance Sheets Southwestern Electric Power Company As of December 31, 1994 1993 (thousands) ASSETS Electric Utility Plant Production $1,401,418 $1,392,058 Transmission 385,113 350,625 Distribution 733,707 678,788 General 213,563 188,193 Construction work in progress 149,508 126,258 2,883,309 2,735,922 Less - Accumulated depreciation 1,026,751 947,792 1,856,558 1,788,130 Current Assets Cash and temporary cash investments 1,296 6,723 Accounts receivable 54,344 24,363 Materials and supplies, at average cost 28,109 25,218 Fuel inventory, at average cost 61,701 49,487 Accumulated deferred income taxes 6,592 3,912 Prepayments and other 13,071 14,965 165,113 124,668
Deferred Charges and Other Assets 57,536 55,487 $2,079,207 $1,968,285
The accompanying notes to financial statements are an integral part of these statements.
2-144 Balance Sheets Southwestern Electric Power Company As of December 31, 1994 1993 (thousands) CAPITALIZATION AND LIABILITIES Capitalization Common stock: $18 par value Authorized: 7,600,000 shares Issued and Outstanding: 7,536,640 shares $ 135,660 $ 135,660 Paid-in capital 245,000 245,000 Retained earnings 297,462 265,071 Total Common Stock Equity 678,122 645,731 Preferred stock Not subject to mandatory redemption 16,032 16,032 Subject to mandatory redemption 34,828 36,028 Long-term debt 595,833 602,065 Total Capitalization 1,324,815 1,299,856
Current Liabilities Long-term debt and preferred stock due within twelve months 5,270 5,028 Advances from affiliates 81,868 27,864 Accounts payable 50,138 41,598 Fuel refunds due customers 12,200 2,358 Customer deposits 13,075 14,244 Accrued restructuring charges 1,110 25,203 Accrued taxes 12,495 27,340 Accrued interest 17,175 17,354 Other 29,505 30,499 222,836 191,488 Deferred Credits Income taxes 365,441 332,522 Investment tax credits 81,023 85,301 Income tax related regulatory liabilities, net 44,836 52,828 Other 40,256 6,290 531,556 476,941 $2,079,207 $1,968,285
The accompanying notes to financial statements are an integral part of these statements.
2-145 Statements of Cash Flows Southwestern Electric Power Company For the Years Ended December 31, 1994 1993 1992 (thousands) OPERATING ACTIVITIES Net Income $105,712 $ 81,876 $ 94,883 Non-cash Items Included in Net Income Depreciation and amortization 89,646 93,120 79,051 Restructuring charges (4,978) 25,203 -- Deferred income taxes and investment tax credits 17,970 (4,775) 3,393 Cumulative effect of changes in accounting principles -- (3,405) -- Allowance for equity funds used during construction (3,579) (1,560) (132) Changes in Assets and Liabilities Accounts receivable (29,981) (3,632) (8,067) Fuel inventory (12,214) 21,101 12,722 Accounts payable 8,540 8,612 5,313 Accrued taxes (14,845) 11,561 (5,817) Accrued restructuring charges (11,694) -- -- Unrecovered fuel/Fuel refund due customers 9,842 1,946 1,274 Other deferred credits 33,966 (9,468) (1,875) Other (10,264) 11,519 (11,892) 178,121 232,098 168,853 INVESTING ACTIVITIES Construction expenditures (146,865) (138,510) (96,676) Acquisition expenditures -- (35,333) -- Allowance for borrowed funds used during construction (2,518) (1,020) (50) Sale of electric utility plant and other (4,980) (4,113) (2,339) (154,363) (178,976) (99,065) FINANCING ACTIVITIES Proceeds from sale of long-term debt -- 221,511 221,067 Reacquisition of long-term debt (5,475) (198,962) (176,474) Redemption of preferred stock (1,160) -- (1,190) Retirement of long-term debt (3,213) (39,835) (3,488) Change in advances from affiliates 54,004 (286) 28,149 Special deposits for reacquisition of long-term debt -- 53,500 (53,500) Payment of dividends (73,341) (83,386) (93,443) (29,185) (47,458) (78,879)
Net Change in Cash and Cash Equivalents (5,427) 5,664 (9,091) Cash and Cash Equivalents at Beginning of Year 6,723 1,059 10,150 Cash and Cash Equivalents at End of Year $ 1,296 $ 6,723 $ 1,059
SUPPLEMENTARY INFORMATION Interest paid less amounts capitalized $ 45,260 $ 42,271 $ 53,129 Income taxes paid $ 36,632 $ 21,112 $ 37,181
The accompanying notes to financial statements are an integral part of these statements.
2-146 Statements of Capitalization Southwestern Electric Power Company As of December 31, 1994 1993 (thousands)
COMMON STOCK EQUITY $ 678,122 $ 645,731
PREFERRED STOCK Cumulative $100 Par Value, Authorized 1,860,000 shares Number Current of Shares Redemption Series Outstanding Price
Not Subject to Mandatory Redemption 5.00% 75,000 $109.00 7,500 7,500 4.65% 25,000 102.75 2,500 2,500 4.28% 60,000 103.90 6,000 6,000 Premium 32 32 16,032 16,032 Subject to Mandatory Redemption 6.95% 352,000 104.64 36,400 37,600 Issuance Expense (372) (372) Amount to be redeemed within one year (1,200) (1,200) 34,828 36,028 LONG-TERM DEBT First Mortgage Bonds Series U, 9 1/8%, due November 1, 2019 -- 5,830 Series V, 7 3/4%, due June 1, 2004 40,000 40,000 Series W, 6 1/8%, due September 1, 1999 40,000 40,000 Series X, 7%, due September 1, 2007 90,000 90,000 Series Y, 6 5/8%, due February 1, 2003 55,000 55,000 Series Z, 7 1/4%, due July 1, 2023 45,000 45,000 Series AA, 5 1/4%, due April 1, 2000 45,000 45,000 Series BB, 6 7/8%, due October 1, 2025 80,000 80,000 1976 Series A, 6.20%, due November 1, 2006 * 6,665 6,810 1976 Series B, 6.20%, due November 1, 2006 * 1,000 1,000 Installment Sales Agreements - PCRBs 1978 Series A, 6%, due January 1, 2008 14,420 14,420 Series 1986, 8.2%, due July 1, 2014 81,700 81,700 1991 Series A, 8.2%, due August 1, 2011 17,125 17,125 1991 Series B, 6.9%, due November 1, 2004 12,290 12,290 Series 1992, 7.6%, due January 1, 2019 53,500 53,500 Bank Loan, Variable Rate, due June 15, 2000 50,000 50,000 Railcar lease obligations 17,922 20,635 Unamortized discount and premium (3,745) (4,034) Unamortized costs of reacquired debt (45,974) (48,383) Amount to be redeemed within one year (4,070) (3,828) 595,833 602,065 TOTAL CAPITALIZATION $1,324,815 $1,299,856
*Obligations incurred in connection with the sale by public authorities of tax-exempt PCRBs.
The accompanying notes to financial statements are an integral part of these statements.
2-147 NOTES TO FINANCIAL STATEMENTS
1.Summary of Significant Accounting Policies Public Utility Regulation SWEPCO is subject to regulation by the SEC under the Holding Company Act and the FERC under the Federal Power Act, and follows the Uniform System of Accounts prescribed by the FERC. SWEPCO is subject to further regulation with regard to rates and other matters by state regulatory commissions including the Arkansas Commission, Louisiana Commission and the Texas Commission. SWEPCO, as a member of the CSW System, engages in transactions and coordinates its activities and operations with other members of the CSW System.
The more significant accounting policies of SWEPCO are summarized below:
Electric Utility Plant Electric utility plant is stated at the original cost of construction, which includes the cost of contracted services, direct labor, materials, overhead items and allowances for borrowed and equity funds used during construction.
Depreciation Provisions for depreciation of electric utility plant are computed using the straight-line method, generally at individual rates applied to the various classes of depreciable property. The annual average consolidated composite rates were 3.2% in 1994, 1993 and 1992.
Electric Revenues and Fuel Prior to January 1, 1993, electric revenues were recorded at the time billings were made to customers on a cycle-billing basis. Electric service provided subsequent to billing dates through the end of each calendar month became part of operating revenues of the next month. To conform to general industry standards, SWEPCO changed its method of accounting to accrue for estimated unbilled revenues. The effect of this change on 1993 income was an increase of $5.4 million included in cumulative effect of changes in accounting principles.
SWEPCO recovers fuel costs in Texas as a fixed component of base rates whereby over-recoveries of fuel are payable to customers and under-recoveries may be billed to customers after Texas Commission approval. The cost of fuel is charged to expense as consumed.
SWEPCO recovers fuel costs in Arkansas and Louisiana through automatic fuel recovery mechanisms. The application of these mechanisms varies by jurisdiction.
SWEPCO recovers fuel costs applicable to wholesale customers, which are regulated by the FERC, through an automatic fuel adjustment clause.
Accounts Receivable SWEPCO sells its billed and unbilled accounts receivable, without recourse, to CSW Credit.
Regulatory Assets and Liabilities For its regulated activities, SWEPCO follows SFAS No. 71, which defines the criteria for establishing regulatory assets and regulatory liabilities. Regulatory assets represent probable future revenue to the company associated with certain costs which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future refunds to customers. At December 31, 1994 and 1993, SWEPCO had recorded the following significant regulatory assets and liabilities:
2-148 1994 1993 (thousands) Regulatory Assets (Included in Deferred Charges and Other Assets on the Balance Sheets) SFAS No. 106 Costs $ 1,949 $ 993
Regulatory Liabilities Fuel refund due customers $12,200 $ 2,358 Income tax related regulatory liabilities, net $44,836 $52,828
Statements of Cash Flows Cash equivalents are considered to be highly liquid debt instruments purchased with a maturity of three months or less. Accordingly, temporary cash investments are considered cash equivalents.
Reclassification Certain financial statement items for prior years have been reclassified to conform to the 1994 presentation.
Accounting Changes Effective January 1, 1993, SWEPCO adopted SFAS Nos. 106, 112 and 109. See NOTE 2, Federal Income Taxes, for further information regarding SFAS No. 109. In addition, SWEPCO also changed its method of accounting for unbilled revenues. See Electric Revenues and Fuel above for further information.
The adoption of SFAS No. 106 resulted in an increase in 1993 operating expenses of $3 million. The adoption of SFAS No. 112 and the change in accounting for unbilled revenues are presented as a cumulative effect of changes in accounting principles as shown below:
Pre-Tax Tax Net Income Effect Effect Effect
SFAS No. 112 $(3,047) $ 1,066 $(1,981) Unbilled revenues 8,286 (2,900) 5,386 Total $ 5,239 $(1,834) $ 3,405
Pro forma amounts, assuming that the change in accounting for unbilled revenues had been adopted retroactively, are not materially different from amounts previously reported for prior years.
2.Federal Income Taxes SWEPCO adopted the provisions of SFAS No. 109 effective January 1, 1993. The implementation of SFAS No. 109 had no material effect on SWEPCO's earnings. As a result of this change, SWEPCO recognized additional accumulated deferred income taxes and corresponding regulatory assets and liabilities to ratepayers in amounts equal to future revenues or the reduction in future revenues required when the income tax temporary differences reverse and are recovered or settled in rates. As a result of a favorable earnings history, SWEPCO did not record any valuation allowance against deferred tax assets at December 31, 1994 and 1993.
SWEPCO, together with other members of the CSW System, files a consolidated federal income tax return and participates in a tax sharing agreement.
2-149 Components of income taxes follow: 1994 1993 1992 Included in Operating Expenses and Taxes (thousands) Current $22,110 $31,779 $29,377 Deferred 22,248 418 10,258 Deferred ITC (4,278) (5,193) (6,864) 40,080 27,004 32,771 Included in Other Income and Deductions Current (3,732) (1,916) 278 Deferred -- -- -- (3,732) (1,916) 278 Tax Effects of Cumulative Effect of Changes in Accounting Principles -- 1,834 -- $36,348 $26,922 $33,049
Investment tax credits deferred in prior years are included in income over the lives of the related properties.
Total income taxes differ from the amounts computed by applying the statutory income tax rates to income before taxes. The reasons for the differences follow:
1994 % 1993 % 1992 % (dollars in thousands) Tax at statutory rates $49,721 35.0 $38,079 35.0 $43,497 34.0 Differences Amortization of ITC (4,277) (3.0) (5,193) (4.8) (5,384) (4.2) Prior period adjustments (2,718) (1.9) -- -- (3,218) (2.5) Consolidated savings (2,476) (1.7) (2,575) (2.4) -- -- Other (3,902) (2.8) (3,389) (3.1) (1,846) (1.6) $36,348 25.6 $26,922 24.7 $33,049 25.7
The significant components of the net deferred income tax liability follow:
1994 1993 (thousands) Deferred Income Tax Liabilities Depreciable utility plant $ 389,016 $ 352,629 Income tax related regulatory assets 33,847 33,028 Other 41,150 39,405 Total Deferred Income Tax Liabilities $ 464,013 $ 425,062
Deferred Income Tax Assets Income tax related regulatory liability (50,162) (52,250) Unamortized ITC (29,482) (31,039) Other (25,520) (13,163) Total Deferred Income Tax Assets (105,164) (96,452) Net Accumulated Deferred Income Taxes - Total $ 358,849 $ 328,610
Net Accumulated Deferred Income Taxes - Noncurrent $ 365,441 $ 332,522 Net Accumulated Deferred Income Taxes - Current (6,592) (3,912) Net Accumulated Deferred Income Taxes - Total $ 358,849 $ 328,610
2-150 3.Long-Term Debt The mortgage indenture, as amended and supplemented, securing first mortgage bonds issued by SWEPCO, constitutes a direct first mortgage lien on substantially all electric utility plant. SWEPCO may offer additional first mortgage bonds subject to market conditions and other factors.
Annual Requirements Certain series of outstanding first mortgage bonds have annual sinking fund requirements, which are generally 1% of the amount of each such series issued. These requirements may be, and generally have been, satisfied by the application of net expenditures for bondable property in an amount equal to 166-2/3% of the annual requirements. At December 31, 1994, the annual sinking fund requirements and annual maturities for the next five years follow:
Sinking Fund Requirements Maturities (thousands) 1995 $ 145 $ 4,100 1996 145 3,900 1997 145 2,600 1998 145 2,400 1999 595 44,000
Dividends SWEPCO's mortgage indenture, as amended and supplemented, contains certain restrictions on the payment of common dividends. At December 31, 1994, all of SWEPCO's retained earnings were available for the payment of cash dividends to its parent, CSW.
Reacquired Long-term Debt Reference is made to MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources - Long-term Financing, for further information related to long-term debt, including new issues and reacquisitions.
4.Preferred Stock SWEPCO's 6.95% Series, $100 par value preferred stock required a mandatory sinking fund sufficient to retire 12,000 shares annually.
The outstanding preferred stock not subject to mandatory redemption is redeemable at the option of SWEPCO upon 30 days notice at the current redemption price per share.
5.Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value.
Cash and temporary cash investments The carrying amount approximates fair value because of the short maturity of those instruments.
Advances from affiliates The carrying amount approximates fair value because of the short maturity of those instruments.
Long-term debt The fair value of the SWEPCO's long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to SWEPCO for debt of the same remaining maturities.
2-151 Current maturities of long-term debt and preferred stock due within 12 months The fair values of the SWEPCO's current maturities of long-term debt and preferred stock due within 12 months are estimated based on quoted market prices for the same or similar issues or on the current rates offered to SWEPCO for long-term debt or preferred stock with the same or similar remaining redemption provisions.
Preferred stock The fair value of SWEPCO's preferred stock is estimated based on quoted market prices for the same or similar issues or on the current rates offered to SWEPCO for preferred stock with the same or similar remaining redemption provisions.
The estimated fair values of SWEPCO's financial instruments follow: 1994 1993 Carrying Fair Carrying Fair Amount Value Amount Value (thousands) Cash and temporary cash investments $ 1,296 $ 1,296 $ 6,723 $ 6,723 Long-term debt and preferred stock due within 12 months 5,270 5,171 -- -- Advances from affiliates 81,868 81,868 32,892 32,892 Long-term debt 595,833 555,659 602,065 631,150 Preferred stock subject to mandatory redemption 34,828 31,968 36,028 38,038
The fair value does not affect SWEPCO's liabilities unless the issues are redeemed prior to their maturity dates.
6.Short-Term Financing SWEPCO, together with other members of the CSW System, has established a money pool to coordinate short-term borrowings and to make borrowings outside the money pool through CSW's issuance of commercial paper. Money pool balances are shown as advances to or from affiliates on the Balance Sheets. At December 31, 1994, the CSW System had bank lines of credit aggregating $930 million to back up its commercial paper program. Short-term cash surpluses transferred to the money pool receive interest income in accordance with the money pool arrangement.
7.Benefit Plans Defined Benefit Pension Plan SWEPCO, together with other members of the CSW System, maintains a tax qualified, non-contributory defined benefit pension plan covering substantially all employees. Benefits are based on employees' years of credited service, age at retirement, and final average annual earnings with an offset for the participants' primary Social Security benefit. The CSW System's funding policy is based on actuarially determined contributions, taking into account amounts which are deductible for income tax purposes and minimum contributions required by ERISA. Pension plan assets consist primarily of common stocks and short-term and intermediate- term fixed income investments.
Contributions to the plan for the years ended December 31, 1994, 1993 and 1992 were $5.9 million, $6.1 million and $5.2 million, respectively.
The approximate maximum number of participants in the plan during 1994 was 2,000 active employees, 800 retirees and beneficiaries and 100 terminated employees.
2-152 The components of net periodic pension cost and the assumptions used in accounting for pensions follow: 1994 1993 1992 (thousands) Net Periodic Pension Cost Service cost $ 4,843 $ 4,239 $ 3,857 Interest cost on projected benefit obligation 13,361 12,063 10,920 Actual return on plan assets (945) (14,658) (9,375) Net amortization and deferral (15,018) 55 (4,253) $ 2,341 $ 1,699 $ 1,149
Discount rate 8.25% 7.75% 8.50% Long-term compensation increase 5.46% 5.46% 5.96% Return on plan assets 9.50% 9.50% 9.50%
At December 31, 1994, the plan's net assets were approximately equal to the total actuarial present value of the accumulated benefit obligation. At December 31, 1993 and 1992, the plan's net assets exceeded the total actuarial present value of the accumulated benefit obligation. No reconciliation of the funding status of the plan is presented because such information is unavailable.
Health and Welfare Plans SWEPCO had medical, dental, group life insurance, dependent life insurance, and accidental death and dismemberment plans for substantially all active SWEPCO employees during 1994. The contributions, recorded on a pay-as-you-go basis, for the years ended December 31, 1994 and 1993 were approximately $4.1 million and $5.4 million, respectively. Effective January 1993, SWEPCO's method of providing health benefits was modified to include such benefits as a health maintenance organization, preferred provider options, managed prescription drug and mail-order program and a mental health and substance abuse program in addition to the self- insured indemnity plans.
Postretirement Benefits Other Than Pensions SWEPCO adopted SFAS No. 106 on January 1, 1993. The effect on operating expense in 1993 was $3 million. SWEPCO is amortizing its transition obligation over twenty years, with eighteen years remaining. In prior years, these benefits were accounted for on a pay-as-you-go basis.
The components of net periodic postretirement benefit cost follow:
1994 1993 (thousands) Net Periodic Postretirement Benefit Cost Service cost $1,965 $1,813 Interest cost on APBO 4,266 3,782 Actual return on plan assets (464) (230) Amortization of transition obligation 1,967 1,967 Net amortization and deferral (765) (474) $6,969 $6,858
2-153 A reconciliation of the funded status of the plan to the amounts recognized on the balance sheets follow:
December 31, 1994 1993 APBO (thousands) Retirees $ 32,938 $ 31,883 Other fully eligible participants 7,945 7,505 Other active participants 12,726 14,199 Total APBO 53,609 53,587 Plan assets at fair value (18,775) (13,139) APBO in excess of plan assets 34,834 40,448 Unrecognized transition obligation (35,403) (37,370) Unrecognized gain or (loss) 608 (4,410) Accrued/(Prepaid) Cost $ 39 $ (1,332)
The following assumptions were used in accounting for SFAS No. 106.
1994 1993 Discount rate 8.25% 7.75% Return on plan assets 9.50% 9.00% Tax rate for taxable trusts 39.60% 39.60%
Health Care Cost Trend Rate Assumptions Pre-65 Participants: 1994 Rate of 11.75% grading down .75% per year to an ultimate rate of 6.5% in 2001.
Post-65 Participants: 1994 Rate of 11.25% grading down .75% per year to an ultimate rate of 6.0% in 2001.
Increasing the assumed health care cost trend rates by one percentage point in each year would increase the APBO as of December 31, 1994 by $6 million and increase the aggregate of the service and interest costs components on net postretirement benefits by $0.9 million.
8.Jointly Owned Electric Utility Plant SWEPCO has joint ownership agreements with non-affiliated entities. Such agreements provide for the joint ownership and operation of the Flint Creek, Pirkey and Dolet Hills power plants and related facilities. The statements of income reflect SWEPCO's portion of operating costs associated with jointly owned plants. At December 31, 1994, SWEPCO had interests as shown below: Flint Dolet Creek Pirkey Hills Coal Lignite Lignite Plant Plant Plant (dollars in millions) Plant in service $79 $431 $226 Accumulated depreciation $39 $135 $62 Plant capacity-MW 480 650 650 Participation 50.0% 85.9% 40.2% Share of capacity-MW 240 559 262
2-154 9.Litigation and Regulatory Proceedings Fuel Reconciliation On March 17, 1994, SWEPCO filed a petition with the Texas Commission to reconcile fuel costs for the period November 1989 through December 1993. Total Texas jurisdictional fuel expenses subject to reconciliation for this 50-month period were approximately $559 million. SWEPCO's net under-recovery for the reconciliation period was approximately $0.9 million. SWEPCO and the intervening parties in this proceeding were able to negotiate a stipulated agreement providing a $3.2 million fuel cost disallowance and settling all issues except one. That issue involved the recovery of certain fuel related litigation and settlement negotiation expenses. The Texas Commission, at its Final Order hearing on January 18, 1995, approved the stipulated disallowance and granted SWEPCO recovery of the fuel related litigation expense. The $3.2 million disallowance is included in SWEPCO's 1994 results of operations. SWEPCO recognized the litigation costs as expenses in prior periods.
Burlington Northern Transportation Contract On January 20, 1995, a state district court in Bowie County, Texas, entered judgment in favor of SWEPCO against Burlington Northern in a lawsuit between the parties regarding rates charged under two rail transportation contracts for delivery of coal to SWEPCO's Welsh and Flint Creek power plants. The court awarded SWEPCO approximately $72 million covering damages for the period from April 27, 1989 through September 26, 1994 and prejudgment interest fees and granted certain declaratory relief requested by SWEPCO.
Kansas City Southern Railway Company Transportation Contracts In March 1994, SWEPCO entered into a settlement with the Kansas City Southern Railway Company of litigation between parties regarding two coal transportation contracts. Pursuant to the settlement, SWEPCO and the Kansas City Southern Railway Company executed a new coal transportation agreement. The settlement is expected to result in a reduction of SWEPCO's coal transportation costs now and in the future. Burlington Northern, another party to the prior contracts and to the litigation, did not participate in the settlement and the litigation is still pending between SWEPCO and Burlington Northern.
Other SWEPCO is party to various other legal claims, actions and complaints arising in the normal course of business. Management does not expect disposition of these matters to have a material adverse effect on SWEPCO's results of operations or financial condition.
10. Commitments and Contingent Liabilities It is estimated that SWEPCO will spend approximately $96 million in construction expenditures during 1995. Substantial commitments have been made in connection with this capital expenditure program.
To supply a portion of the fuel requirements, SWEPCO has entered into various commitments for procurement of fuel.
Henry W. Pirkey Power Plant In connection with the South Hallsville lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCO has agreed, under certain conditions, to assume the obligations of the mining contractor. As of December 31, 1994, the maximum amount SWEPCO would have to assume was $73.7 million. The maximum amount may vary as the mining contractor's need for funds fluctuates. The contractor's actual obligation outstanding at December 31, 1994 was $60.9 million.
South Hallsville Lignite Mine As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining at the South Hallsville lignite mine, SWEPCO has agreed to provide bond guarantees on mine reclamation in the amount of $70 million. Since SWEPCO uses self-
2-155 bonding, the guarantee provides for SWEPCO to commit to use its resources to complete the reclamation in the event the work is not completed by the third party miner. The current cost to reclaim the mine is estimated to be approximately $25 million.
Coal Transportation SWEPCO has entered into various financing arrangements primarily with respect to coal transportation and related equipment, which are treated as operating leases for rate-making purposes. At December 31, 1994, leased assets of $46 million, net of accumulated amortization of $30.1 million, were included in electric plant on the balance sheet and at December 31, 1993, leased assets were $46 million, net of accumulated amortization of $26.8 million. Total charges to operating expenses for leases were $6.8 million, $7.1 million, and $6.9 million for the years 1994, 1993, and 1992.
Suspected MGP Site in Marshall, Texas SWEPCO owns a suspected former MGP site in Marshall, Texas. SWEPCO has notified the TNRCC that evidence of contamination has been found at the site. As a result of sampling conducted at the end of 1993 and early 1994, SWEPCO is evaluating the extent, if any, to which contamination has impacted soil, groundwater and other conditions in the area. A final range of clean-up costs has not yet been determined, but, based on a preliminary estimate, SWEPCO has accrued approximately $2 million as a liability for this site on SWEPCO's books as of December 31, 1993. As more information is obtained about the site, and SWEPCO discusses the site with the TNRCC, the preliminary estimate may change.
Suspected MGP Site in Texarkana, Texas and Arkansas and Shreveport, Louisiana SWEPCO also owns a suspected former MGP site in Texarkana, Texas and Arkansas. The EPA ordered an initial investigation of this site, as well as one in Shreveport, Louisiana, which is no longer owned by SWEPCO. The contractor who performed the investigations of these two sites recommended to the EPA that no further action be taken at this time.
Biloxi, Mississippi MGP Site SWEPCO has been notified by Mississippi Power Company that it may be a PRP at the former Biloxi MGP site formerly owned and operated by a predecessor of SWEPCO. SWEPCO is working with Mississippi Power Company to investigate the extent of contamination at this site. The MDEQ approved a site investigation work plan and, in January 1995, SWEPCO and Mississippi Power Company initiated sampling pursuant to that work plan. On an interim basis, SWEPCO and Mississippi Power Company are each paying fifty percent of the cost of implementing the site investigation work plan. That interim allocation is subject to a final allocation in the future. SWEPCO and Mississippi Power Company are investigating whether there are other PRPs at the Biloxi site. Until the extent of the contamination at the Biloxi site is identified, it is unknown what, if any, additional investigation or cleanup may be required.
Management does not expect these matters to have a material effect on SWEPCO's results of operations or financial position.
2-156 11. Quarterly Information (Unaudited) The following unaudited quarterly information includes, in the opinion of management, all adjustments necessary for a fair presentation of such amounts. Operating Operating Net Quarter Ended Revenues Income Income 1994 (thousands) March 31 $190,066 $ 24,820 $ 14,537 June 30 211,989 36,699 25,851 September 30 245,331 53,304 41,854 December 31 177,910 31,099 23,470 $825,296 $145,922 $105,712
March 31 $175,601 $ 23,953 $ 16,269 June 30 193,225 31,954 21,363 September 30 276,594 58,639 48,353 December 31 191,772 3,511 (4,109) $837,192 $118,057 $ 81,876
Information for quarterly periods is affected by seasonal variations in sales, rate changes, timing of fuel expense recovery and other factors.
2-157 Report of Independent Public Accountants
To the Stockholders and Board of Directors of Southwestern Electric Power Company:
We have audited the accompanying balance sheets and statements of capitalization of Southwestern Electric Power Company (a Delaware corporation and a wholly-owned subsidiary of Central and South West Corporation) as of December 31, 1994 and 1993, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of SWEPCO's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwestern Electric Power Company as of December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
In 1993, as discussed in NOTE 1, SWEPCO changed its method of accounting for unbilled revenues, postretirement benefits other than pensions, income taxes and postemployment benefits.
Our audits were made for the purpose of forming an opinion on the financial statements taken as a whole. The supplemental Schedule II and Exhibit 12 are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. This schedule and exhibit have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Arthur Andersen LLP
Dallas, Texas February 13, 1995
2-158 Report of Management
Management is responsible for the preparation, integrity and objectivity of the financial statements of Southwestern Electric Power Company as well as other information contained in this Annual Report. The financial statements have been prepared in conformity with generally accepted accounting principles applied on a consistent basis and, in some cases, reflect amounts based on the best estimates and judgments of management, giving due consideration to materiality. Financial information contained elsewhere in this Annual Report is consistent with that in the financial statements.
The financial statements have been audited by the independent accounting firm, Arthur Andersen LLP, which was given unrestricted access to all financial records and related data, including minutes of all meetings of shareholders, the board of directors and committees of the board. SWEPCO believes that representations made to the independent auditors during its audit were valid and appropriate. Arthur Andersen LLP's audit report is presented elsewhere in this report.
SWEPCO maintains a system of internal controls to provide reasonable assurance that transactions are executed in accordance with management's authorization, that the financial statements are prepared in accordance with generally accepted accounting principles and that the assets of the companies are properly safeguarded against unauthorized acquisition, use or disposition. The system includes a documented organizational structure and division of responsibility, established policies and procedures including a policy on ethical standards which provides that SWEPCO will maintain the highest legal and ethical standards, and the careful selection, training and development of our employees.
Internal auditors continuously monitor the effectiveness of the internal control system following standards established by the Institute of Internal Auditors. Actions are taken by management to respond to deficiencies as they are identified. The board, operating through its audit committee, which is comprised entirely of directors who are not officers or employees of SWEPCO provides oversight to the financial reporting process.
Due to the inherent limitations in the effectiveness of internal controls, no internal control system can provide absolute assurance that errors will not occur. However, management strives to maintain a balance, recognizing that the cost of such a system should not exceed the benefits derived.
SWEPCO believes that, in all material respects, its system of internal controls over financial reporting and over safeguarding of assets against unauthorized acquisition, use or disposition functioned effectively during 1994.
Richard H. Bremer R. Russell Davis President and CEO - SWEPCO Controller - SWEPCO
2-159
WTU
WEST TEXAS UTILITIES COMPANY
2-160 Selected Financial Data WTU The following selected financial data for each of the five years ended December 31 are provided to highlight significant trends in the financial condition and results of operations for WTU.
1994 1993 1992 1991 1990 (thousands, except ratios) Operating Revenues $342,991 $345,445 $315,370 $318,966 $327,065 Income Before Cumulative Effect of Changes in Accounting Principles 37,366 26,517 35,007 36,368 34,173 Cumulative Effect of Changes in Accounting Principles (1) -- 3,779 -- -- -- Net Income 37,366 30,296 35,007 36,368 34,173 Preferred Stock Dividends 452 967 1,451 1,868 2,077 Net Income for Common Stock 36,914 29,329 33,556 34,500 32,096
Total Assets 778,895 754,443 744,829 734,053 735,969
Common Stock Equity 271,954 266,092 266,874 259,373 261,466 Preferred Stock Not Subject to Mandatory Redemption 6,291 6,291 6,291 6,291 6,291 Subject to Mandatory Redemption -- -- 9,537 14,482 22,376 Long-term Debt 210,047 176,882 211,610 217,855 216,837
Ratio of Earnings to Fixed Charges (SEC Method) Before Cumulative Effect of Changes in Accounting Principles 3.37 2.79 3.22 3.30 3.05
Capitalization Ratios Common Stock Equity 55.7% 59.2% 54.0% 52.1% 51.6% Preferred Stock 1.3 1.4 3.2 4.2 5.6 Long-term Debt 43.0 39.4 42.8 43.7 42.8
(1) The 1993 cumulative effect relates to the changes in accounting for unbilled revenues and adoption of SFAS No. 112. See NOTE 1, Summary of Significant Accounting Policies.
WTU changed its method of accounting for unbilled revenues in 1993. Pro forma amounts, assuming that the change in accounting for unbilled revenues had been adopted retroactively, are not materially different from amounts reported for prior years and therefore have not been restated.
2-161 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
WEST TEXAS UTILITIES COMPANY
Reference is made to WTU's Financial Statements and related Notes and Selected Financial Data. The information contained therein should be read in conjunction with, and is essential to understanding, the following discussion and analysis.
Overview Net income for common stock was $37 million in 1994, a 26% increase when compared to 1993. This increase was due primarily to an increase in retail base revenues and other income and a decrease in restructuring charges.
Restructuring As previously reported, WTU has taken steps to implement a restructuring and early retirement program designed to consolidate and restructure its operations in order to meet the challenges of the changing electric utility industry and to compete effectively in the years ahead. The underlying goal of the restructuring is to enable WTU to focus on and be accountable for serving the customer. The restructuring costs were initially estimated to be $15 million and were expensed in 1993. The final costs of the restructuring were approximately $13 million. Approximately $12 million of the restructuring expenditures were incurred during 1994, with the remaining $1 million expected to be incurred during 1995. Approximately $1 million of the restructuring expenses relate to employee termination benefits, $7 million relate to enhanced benefit costs and $5 million relate to employees that will not be terminated. Approximately $9 million of the restructuring costs were paid from or will be paid from general corporate funds. The remaining $4 million represent the present value of enhanced benefit amounts to be paid from the benefit plan trusts to participants over future years in accordance with the early retirement program. The cost of these enhanced benefit amounts will be paid from general corporate funds to the benefit plan trusts over future years. The restructuring is substantially completed, with the remaining activity to take place during 1995. Certain aspects of the restructuring are pending SEC approval under the Holding Company Act.
WTU expects to realize a number of benefits from the restructuring. Beginning in 1994 and continuing into the future, increased efficiencies and synergies are expected to be realized with the elimination of previously duplicated functions. This leads to enhanced communication and efficiency, which should translate into a reduction in the rate of growth in O&M costs. The CSW System expects that all restructuring costs will be recovered by early 1996 with reductions in the rate of growth of O&M costs continuing thereafter.
Rates and Regulatory Matters See NOTE 9, Litigation and Regulatory Proceedings, for information regarding the WTU fuel and rate proceedings, and deferred accounting matters.
New Accounting Standards SFAS No. 115 was effective for fiscal years beginning after December 15, 1993. WTU adopted SFAS No. 115 in 1994. The adoption of SFAS No. 115 did not have a material effect on WTU's results of operations or financial condition.
In June 1993, the FASB issued SFAS No. 116. The statement, effective for fiscal years beginning after December 15, 1994, will be adopted by WTU for 1995. The statement establishes accounting standards for contributions and applies to all entities that receive or make contributions. Management does not believe the adoption of SFAS No. 116 will have a material impact on WTU's results of operations or financial condition.
2-162 SFAS No. 119 was effective for fiscal years ending after December 15, 1994. WTU currently does not use derivative instruments, but may use these instruments in the future to manage the increased market risks associated with greater competition in the electric utility industry. The adoption of this new statement had no material effect on WTU's results of operations or financial condition.
Liquidity and Capital Resources Overview WTU's need for capital results primarily from the construction of facilities to provide reliable electric service to its customers. Accordingly, internally generated funds should meet most of the capital requirements. However, if internally generated funds are not sufficient, WTU's financial condition and credit rating should allow it access to the capital markets.
Capital Expenditures Construction expenditures including AFUDC were $42 million, $37 million and $29 million for the years 1994, 1993 and 1992. It is estimated that construction expenditures, including AFUDC, during the 1995 through 1997 period will aggregate $109 million. Such expenditures primarily will be made to improve and expand transmission and distribution facilities. These improvements are expected to meet the needs of new customers and to satisfy changing requirements of existing customers. No new baseload power plants are currently planned until after the year 2000.
The construction program continues to be monitored, reviewed and adjusted to reflect changes in estimated load growth in WTU's service area, variations in prices of alternative fuel sources, the cost of labor, materials, equipment and capital, and other external factors.
The CSW System facilities plan presently includes projected coal- and lignite-fired generating plants for which WTU has invested approximately $15 million in prior years for plant sites, engineering studies and lignite reserves. Should future plans exclude these plants for environmental or other reasons, WTU would evaluate the probability of recovery of these investments and may record appropriate reserves.
Long-Term Financing As of December 31, 1994, the capitalization ratios of WTU were 56% common stock equity, 1% preferred stock and 43% long-term debt. WTU continually monitors the capital markets for opportunities to lower its cost of capital through refinancing. WTU continues to be committed to maintaining financial flexibility by maintaining its strong capital structure and favorable securities ratings which should allow funds to be obtained from the capital markets when required.
WTU's long-term financing activity is shown below:
In February 1994, WTU issued $40 million of 6-1/8% FMBs, Series S, due February 1, 2004. Proceeds were used to reimburse WTU's treasury for (i) $12 million aggregate principal amount of 7-1/4% First Mortgage Bonds, Series G, due January 1, 1999, redeemed on January 1, 1994, and, (ii) $23 million aggregate principal amount of 7- 7/8% FMBs, Series H, due July 1, 2003, redeemed on December 30, 1993. The balance of the proceeds was used to repay outstanding short-term borrowings.
In July 1994, WTU redeemed its remaining $4.7 million outstanding of 7-1/4% Series Preferred Stock in accordance with mandatory sinking fund provisions. The funds required for this transaction were provided from internal sources and short-term borrowings.
In October and November 1994, WTU reacquired $7.8 million aggregate principal amount of its 9-1/4% FMBs, Series O, due December 1, 2019 in open market transactions. The funds required for these transactions were provided from short-term borrowings and internal sources. The premiums and reacquisition costs of reacquired long-term
2-163 debt are included in long-term debt on the balance sheets and are being amortized over 10 to 30 years in accordance with the anticipated regulatory treatment.
In December 1994, pursuant to sinking fund requirements, WTU elected to redeem at par $650,000 Series O, FMBs.
In March 1995, WTU issued $40 million of 7-1/2% FMBs, Series T, due April 1, 2000. Proceeds were used to repay a portion of WTU's short-term debt, to provide working capital and for other general corporate purposes.
WTU Shelf Registration WTU expects to obtain a majority of their 1995 capital requirements from internal sources, but may issue additional securities subject to market conditions and other factors. The proceeds of any such offerings will be used principally to redeem higher cost preferred stock and to repay short-term debt. WTU has filed shelf registration statements with the SEC for the sale of securities. As of March 1995, WTU had $20 million remaining for issuance of first mortgage bonds under a shelf registration filed with the SEC in 1993. WTU may issue additional debt securities subject to market conditions and other factors. The proceeds of any such offerings will be used principally to redeem higher cost FMBs, to lower embedded cost of debt, to repay short-term debt, to provide working capital and for other general corporate purposes.
WTU may issue additional preferred stock subject to market conditions and other factors. The proceeds of any such offerings will be used principally to redeem higher cost preferred stock and to redeem short-term debt.
Short-Term Financing WTU, together with other members of the CSW System, has established a CSW System money pool to coordinate short-term borrowings. These loans are unsecured demand obligations at rates approximating the CSW System's commercial paper borrowing costs. WTU's short-term borrowing limit from the money pool is $50 million. During 1994, the annual weighted average interest rate was 4.5% and the average amount of short-term month-end borrowings outstanding was $22 million. The maximum amount of short-term borrowings outstanding at any month-end during 1994 was $46 million, which was the amount outstanding at December 31, 1994.
Internally Generated Funds Internally generated funds consist of cash flows from operating activities less common and preferred stock dividends. WTU uses short- term debt to meet fluctuations in working capital requirements due to the seasonal nature of energy sales. During 1993 and 1994, WTU experienced several non-recurring transactions that resulted in negative internally generated funds in 1994, including the refinancing of Series G and Series H FMBs with Series S FMBs which occurred from December 1993 through February 1994. This refinancing caused an abnormally high accounts payable balance at December 31, 1993 which was subsequently reduced by the issuance of Series S in February 1994, resulting in the appearance of a large out flow of cash from operating funds. WTU anticipates that capital requirements for the period 1995 to 1997 will be met, in large part, from internal sources. WTU also expects that some external financings maybe required during the period, but the nature, timing and extent have not yet been determined. Information concerning internally generated funds follows:
1994 1993 1992 (millions) Internally Generated Funds ($4) $59 $49
Construction Expenditures Provided by Internally Generated Funds -- 163% 169%
2-164 As discussed above, WTU issued $40 million of 7-1/2% FMBs during the first quarter of 1995, which were used to reduce short-term debt.
Sales of Accounts Receivable WTU sells its billed and unbilled accounts receivable, without recourse, to CSW Credit. The sales provide WTU with cash immediately, thereby reducing working capital needs and revenue requirements. The average and year end amounts of accounts receivable sold were $35 million and $18 million in 1994, as compared to $36 million and $34 million in 1993.
Recent Developments and Trends Competition and Industry Challenges Competitive forces at work in the electric utility industry are impacting WTU and electric utilities generally. Increased competition facing electric utilities is driven by complex economic, political and technological factors. These factors have resulted in legislative and regulatory initiatives that are likely to result in even greater competition at both the wholesale and retail level in the future. As competition in the industry increases, WTU will have the opportunity to seek new customers and at the same time be at risk of losing customers to other competitors. WTU believes that its prices for electricity and the quality and reliability of its service currently place it in a position to compete effectively in the marketplace.
The Energy Policy Act, which was enacted in 1992, significantly alters the way in which electric utilities compete. The Energy Policy Act creates exemptions from regulation under the Holding Company Act and permits utilities, including registered utility holding companies and non-utility companies, to form EWGs. EWGs are a new category of non-utility wholesale power producer that are free from most federal and state regulation, including the principal restrictions of the Holding Company Act. These provisions enable broader participation in wholesale power markets by reducing regulatory hurdles to such participation. The Energy Policy Act also allows the FERC, on a case- by-case basis and with certain restrictions, to order wholesale transmission access and to order electric utilities to enlarge their transmission systems. A FERC order requiring a transmitting utility to provide wholesale transmission service must include provisions generally that permit (i) the utility to recover from the FERC applicant all of the costs incurred in connection with the transmission services and (ii) any enlargement of the transmission system and associated services. While WTU believes that the Energy Policy Act will continue to make the wholesale markets more competitive, WTU is unable to predict the extent to which the Energy Policy Act will impact its operations.
Increasing competition in the utility industry brings an increased need to stabilize or reduce rates. The retail regulatory environment is beginning to shift from traditional rate base regulation to incentive regulation. Incentive rate and performance- based plans encourage efficiencies and increased productivity while permitting utilities to share in the results. Retail wheeling, a major industry issue which may require utilities to "wheel" or move power from third parties to their own retail customer, is evolving gradually.
Wholesale energy markets, including the market for wholesale electric power, have been extremely competitive since the enactment of the Energy Policy Act. WTU competes in the wholesale energy markets with other public utilities, cogenerators, qualified facilities, exempt wholesale generators and others for sales of electric power.
Under the Energy Policy Act, the FERC has approved several proposals by utility companies to sell wholesale power at market-based rates and provide to electric utilities "open access" to transmission systems, subject to certain requirements. The adoption of these proposals increases marketing opportunities for electric utilities, but also exposes them to the risk of loss of load or reduced revenues due to competition with alternative suppliers.
2-165 WTU believes that, compared to other electric utilities, it is well positioned to meet future competition. WTU benefits from economies of scale and scope by virtue of its size and its relationship to the CSW System. WTU is also a relatively low-cost producer of electric power. Moreover, WTU is taking steps to enhance its marketing and customer service, reduce costs, improve and standardize business practices, and grow through strategic acquisitions, in order to position itself for increased competition in the future.
WTU is unable to predict the ultimate outcome or impact of competitive forces on the electric utility industry or on WTU. As the wholesale and retail electricity markets become more competitive, however, the principal factor determining success is likely to be price, and to a lesser extent, reliability, availability of capacity, and customer service.
Public Utility Regulatory Act PURA is the legal foundation for electric utility regulation in Texas. PURA will expire on September 1, 1995, in accordance with the sunset policy of the Texas Legislature, which applies to all state agencies, unless the Texas Legislature reenacts PURA in its current form or in modified form. Several proposals have been made to amend PURA which, among other things, provide for a market-driven integrated resource planning process, pricing flexibility for utilities faced with competitive challenges, incentive regulation and deregulation of the wholesale bulk power market in ERCOT. WTU is unable to predict the ultimate outcome of the 1995 session of the Texas Legislature and in particular whether amendments to PURA will be adopted.
Regulatory Accounting Consistent with industry practice and the provisions of SFAS No. 71, which allows for the recognition and recovery of regulatory assets, WTU has recognized significant regulatory assets and liabilities. Management believes that WTU will continue to meet the criteria for following SFAS No. 71. However, in the event WTU no longer meets the criteria for following SFAS No. 71, a write-off of regulatory assets and liabilities would be required. For additional information regarding SFAS No. 71 reference is made to NOTE 1, Summary of Significant Accounting Policies - Regulatory Assets and Liabilities.
Consolidated Taxes The Texas Commission before 1992 allowed income taxes to be recovered in rates based on the federal income tax incurred by a utility as if it were a stand-alone company. This stand-alone approach treated the regulated activities of a utility as a separate entity and considered only those revenues and expenses that are included in the utility's cost of service to calculate the federal income tax liability for ratemaking purposes.
Beginning in 1992, the Texas Commission changed its method of calculating the federal income tax component of rates to the "actual tax approach." The actual tax approach is an evolving concept but generally seeks to reflect in rates the actual tax liability of the utility irrespective of its relationship to the utility's cost of service. The approach reduces rates by the tax benefits of deductions which are not considered for or included in setting rates for the utility.
The Texas Commission is expected to use the actual tax approach for calculating the recovery of federal income tax in the pending rate case for WTU. The impact of the actual tax approach on the prospective rates for WTU cannot be determined since the application of the concept is unsettled.
WTU believes that the recovery of federal income taxes in rates should be determined on the stand-alone approach for ratemaking purposes, but there is no assurance this approach will be adopted in the pending WTU rate case.
2-166 Environmental Matters CERCLA and Related Matters The operations of WTU, like those of other utilities, generally involve the use and disposal of substances subject to environmental laws. The CERCLA, the federal "Superfund" law, addresses the cleanup of sites contaminated by hazardous substances. Superfund requires that PRPs fund remedial actions regardless of fault or the legality of past disposal activities. PRPs include owners and operators of contaminated sites and transporters and/or generators of hazardous substances. Many states have similar laws. Theoretically, any one PRP can be held responsible for the entire cost of a cleanup. Typically, however, cleanup costs are allocated among PRPs.
WTU is subject to various pending claims alleging it is a PRP under federal or state remedial laws for investigating and cleaning up contaminated property. WTU anticipates that resolution of these claims, individually or in the aggregate, will not have a material adverse effect on WTU's results of operations or financial condition. Although the reasons for this expectation differ from site to site, factors that are the basis for the expectation for specific sites include the volume and/or type of waste allegedly contributed by WTU, the estimated amount of costs allocated to WTU and the participation of other parties.
Clean Air Act Amendments In November 1990, the United States Congress passed the Clean Air Act which places restrictions on the emission of sulfur dioxide from gas-, coal- and lignite-fired generating plants. Beginning in the year 2000, the Electric Operating Companies will be required to hold allowances in order to emit sulfur dioxide. The EPA issues allowances to owners of existing generating units based on historical operating conditions. Based on the CSW System facilities plan, WTU believes that its allowances will be adequate to meet its needs at least through 2008. Public and private markets are developing for trading of excess allowances. WTU presently has no intention of engaging in trading of allowances, but may seek to do so in the future if market conditions warrant and appropriate regulatory approvals are obtained.
The Clean Air Act also establishes a federal operating source permit program to be administered by the states.
The Clean Air Act also directs the EPA to issue regulations governing nitrogen oxide emissions and requires government studies to determine what controls, if any, should be imposed on utilities to control air toxics emissions. The impact that the nitrogen oxide emission regulations and the air toxics study will have on WTU cannot be determined at this time.
As a result of requirements imposed by the Clean Air Act, WTU expects to spend $0.5 million for annual testing of, software modifications to, and maintenance of continuous emission monitoring equipment from 1995 through 1997.
EMFs Research is ongoing whether exposure to EMFs may result in adverse health effects. Although a few of the studies to date have suggested certain associations between EMFs and some types of effects, the research to date has not established a cause-and-effect relationship between EMFs and adverse health effects. WTU cannot predict the impact on WTU or the electric utility industry if further investigations or proceedings were to establish that the present electricity delivery system is contributing to increased risk or incidence of health problems.
Results of Operations Electric Operating Revenues Electric operating revenues in 1994 decreased approximately $2.5 million or 1% when compared to 1993. This decrease was due primarily to a reduction in lower margin off-system sales of $8 million resulting from decreased market place demand. This decrease was partially offset by higher on system revenues of $6.5 million attributable to an increase in retail KWH sales of 3% resulting from customer growth and increased usage. Also contributing to the
2-167 decrease was an interim rate reduction of approximately $5.7 million on an annual basis effective October 1, 1994. Revenues for 1993, when compared to 1992, increased approximately $30.1 million, or 10%. The increase is attributed to a 10% increase in KWH sales and a $9.1 million increase in fuel-related revenues. The increase in KWH sales is attributable to a warmer summer in 1993 and increased sales for resale to an affiliated company.
Fuel and Purchased Power Expenses Fuel expenses decreased approximately $3.8 million or 3% during 1994 when compared to 1993 and increased approximately $15.1 million or 13% when compared to 1992. The decrease in 1994 is primarily attributable to a 2% decrease in average unit fuel costs from $1.91 in 1993 to $1.88 in 1994 and a 2% decrease in generation. The increase in 1993 is due primarily to a 5% increase in average unit fuel cost to $1.91 in 1993 from $1.82 in 1992 and a 7% increase in generation. The change in unit fuel costs during both years is due primarily to changes in the price of natural gas on the spot market.
Purchased power expenses decreased approximately $2.3 million and increased $4.3 million during 1994 and 1993, respectively, when compared to the prior years. The change during both periods is primarily attributable to increased economy purchases in 1993.
Expenses and Taxes Other operating expenses increased approximately $4.9 million and $3.8 million during 1994 and 1993, respectively, when compared to prior years. The increase during 1994 reflects a reimbursement in 1993 for the settlement of a dispute relating to a coal supply contract which lowered expenses in 1993. Higher outside services for fuel related issues and other employee related expenses in 1994 also contributed to the increase. The increase during 1993 was due primarily to higher employee pensions and benefits.
Restructuring charges reflect the original accrual of $15 million in December 1993 which was subsequently adjusted by $2 million in 1994, resulting in total restructuring charges for WTU of $13 million at December 31, 1994.
Maintenance expense in 1994 increased over 1993 by approximately $1.7 million or 13% due primarily to increased production maintenance of boiler and electric plant. Maintenance increased approximately $1.3 million in 1993 compared with 1992 because of higher production and general expenses resulting from boiler plant maintenance.
Depreciation and amortization expenses increased approximately $1.2 million and $3.6 million during 1994 and 1993, respectively, when compared to prior years due primarily to increases in depreciable property.
Federal income taxes increased approximately $4.3 million or 32% in 1994 when compared with 1993 due to higher pre-tax income. The decrease in 1993 compared to 1992 was largely attributable to lower pre-tax income partially offset by an increase in the federal corporate income tax rate to 35% from 34%.
Other income increased approximately $2.3 million in 1994 resulting from tax benefits received under WTU's tax sharing agreement with CSW.
Interest on Long-Term Debt Interest on long-term debt decreased approximately $0.7 million in 1994 when compared to the prior year due to WTU's refinancing of higher cost debt with lower cost debt and decreased balances outstanding.
Inflation Annual inflation rates, as measured by the national Consumer Price Index, have averaged approximately 2.7% for the three-year period ending December 31, 1994. WTU believes that inflation, at these levels, does not materially affect its results of operations
2-168 or financial condition. However, under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, cash flows designed to provide recovery of historical plant costs may not be adequate to replace plant in future years.
Cumulative Effect of Changes in Accounting Principles In 1993, WTU changed it method of accounting for unbilled revenue and implemented SFAS No. 112. These accounting changes had a cumulative effect of increasing net income by $3.8 million.
2-169 Statements of Income West Texas Utilities Company For the Years Ended December 31, 1994 1993 1992 (thousands) Electric Operating Revenues Residential $118,525 $115,932 $106,497 Commercial 66,483 65,085 62,244 Industrial 52,626 53,709 52,651 Sales for resale 67,076 72,252 60,833 Other 38,281 38,467 33,145 342,991 345,445 315,370 Operating Expenses and Taxes Fuel 131,258 135,048 119,983 Purchased power 5,144 7,411 3,086 Other operating 66,290 61,357 57,578 Restructuring charges (2,037) 15,250 -- Maintenance 14,978 13,251 11,959 Depreciation and amortization 31,569 30,405 26,784 Taxes, other than federal income 23,072 22,496 21,970 Federal income taxes 17,954 13,651 16,708 288,228 298,869 258,068
Operating Income 54,763 46,576 57,302
Other Income and Deductions Allowance for equity funds used during construction 150 109 51 Other 4,210 1,907 1,114 4,360 2,016 1,165
Income Before Interest Charges 59,123 48,592 58,467
Interest Charges Interest on long-term debt 18,547 19,225 21,368 Interest on short-term debt and other 3,534 2,988 2,197 Allowance for borrowed funds used during construction (324) (138) (105) 21,757 22,075 23,460
Income Before Cumulative Effect of Changes in Accounting Principles 37,366 26,517 35,007
Cumulative Effect of Changes in Accounting Principles -- 3,779 --
Net Income 37,366 30,296 35,007 Preferred stock dividends 452 967 1,451 Net Income for Common Stock $ 36,914 $ 29,329 $ 33,556
The accompanying notes to financial statements are an integral part of these statements.
2-170 Statements of Retained Earnings West Texas Utilities Company For the Years Ended December 31, 1994 1993 1992 (thousands) Retained Earnings at Beginning of Year $126,642 $127,424 $119,923 Net income for common stock 36,914 29,329 33,556 Deduct: Common stock dividends 31,000 30,000 26,000 Preferred stock redemption cost 52 111 55 Retained Earnings at End of Year $132,504 $126,642 $127,424
The accompanying notes to financial statements are an integral part of these statements.
2-171 Balance Sheets West Texas Utilities Company As of December 31, 1994 1993 (thousands) ASSETS Electric Utility Plant Production $427,736 $425,340 Transmission 194,402 190,300 Distribution 308,905 291,509 General 73,938 69,780 Construction work in progress 23,257 14,385 1,028,238 991,314 Less - Accumulated depreciation 364,383 337,888 663,855 653,426 Current Assets Cash 2,501 706 Accounts receivable 23,165 24,497 Materials and supplies, at average cost 16,519 14,451 Fuel inventory, at average cost 9,229 9,150 Coal inventory, at LIFO cost 6,442 5,511 Accumulated deferred income taxes 3,068 1,222 Prepayments and other 1,091 450 62,015 55,987
Deferred Charges and Other Assets Deferred Oklaunion costs 26,914 27,735 Other 26,111 17,295 53,025 45,030 $778,895 $754,443
The accompanying notes to financial statements are an integral part of these statements.
2-172 Balance Sheets West Texas Utilities Company As of December 31, 1994 1993 (thousands) CAPITALIZATION AND LIABILITIES Capitalization Common stock: $25 par value Authorized: 7,800,000 shares Issued and outstanding: 5,488,560 shares $137,214 $137,214 Paid-in capital 2,236 2,236 Retained earnings 132,504 126,642 Total Common Stock Equity 271,954 266,092 Preferred stock Not subject to mandatory redemption 6,291 6,291 Long-term debt 210,047 176,882 Total Capitalization 488,292 449,265
Current Liabilities Long-term debt and preferred stock due within twelve months 650 17,298 Advances from affiliates 46,315 11,784 Accounts payable 35,407 51,041 Accrued restructuring charges 571 15,250 Accrued taxes 7,452 14,620 Accrued interest 4,394 4,128 Other 3,758 1,979 98,547 116,100 Deferred Credits Accumulated deferred income taxes 146,146 134,595 Investment tax credits 31,882 33,203 Income tax related regulatory liabilities, net 9,217 10,545 Other 4,811 10,735 192,056 189,078 $778,895 $754,443
The accompanying notes to financial statements are an integral part of these statements.
2-173 Statements of Cash Flows West Texas Utilities Company For the Years Ended December 31, 1994 1993 1992 (thousands) OPERATING ACTIVITIES Net Income $ 37,366 $ 30,296 $ 35,007 Non-cash Items Included in Net Income Depreciation and amortization 33,362 31,925 28,354 Restructuring charges (2,037) 15,250 -- Deferred income taxes and investment tax credits 7,056 3,159 4,911 Cumulative effect of changes in accounting principles -- (3,779) -- Allowance for equity funds used during construction (150) (109) (51) Changes in Assets and Liabilities Accounts receivable 1,332 (3,159) (6,804) Fuel inventory (1,010) (6) 141 Accounts payable (15,103) 21,552 13,417 Accrued taxes (7,168) 4,085 1,343 Accrued restructuring charges (8,918) -- -- Other deferred credits (5,924) (6,502) (777) Other (10,802) (2,694) 1,152 28,004 90,018 76,693 INVESTING ACTIVITIES Construction expenditures (41,504) (36,318) (28,902) Allowance for borrowed funds used during construction (324) (138) (105) Disposition of plant (1,315) 3,302 (854) (43,143) (33,154) (29,861) FINANCING ACTIVITIES Proceeds from issuance of long-term debt 39,354 (77) 98,506 Reacquisition of long-term debt (20,731) (24,250) (106,757) Redemption of preferred stock (4,700) (10,000) (5,000) Payment of dividends (31,520) (30,816) (27,874) Change in advances from affiliates 34,531 7,241 (5,714) 16,934 (57,902) (46,839)
Net Change in Cash and Cash Equivalents 1,795 (1,038) (7) Cash and Cash Equivalents at Beginning of Year 706 1,744 1,751 Cash and Cash Equivalents at End of Year $ 2,501 $ 706 $ 1,744
SUPPLEMENTARY INFORMATION Interest paid less amounts capitalized $ 18,128 $ 18,430 $ 21,257 Income taxes paid $ 12,720 $ 325 $ 6,174
The accompanying notes to financial statements are an integral part of these statements.
2-174 Statements of Capitalization West Texas Utilities Company As of December 31, 1994 1993 (thousands)
COMMON STOCK EQUITY $271,954 $266,092
PREFERRED STOCK Cumulative $100 Par Value, Authorized 810,000 shares Number Current of Shares Redemption Series Outstanding Price
Not Subject to Mandatory Redemption 4.40% 60,000 $107.00 6,000 6,000 Premium 291 291 6,291 6,291 Subject to Mandatory Redemption 7.25% 47,000 $100.91 -- 4,700 Issuance Expense -- (52) Amount to be Redeemed Within One Year -- (4,648) -- -- LONG-TERM DEBT First Mortgage Bonds Series G, 7 1/4%, due January 1, 1999 -- 12,000 Series O, 9 1/4%, due December 1, 2019 55,203 63,700 Series P, 7 3/4%, due June 1, 2007 25,000 25,000 Series Q, 6 7/8%, due October 1, 2002 35,000 35,000 Series R, 7%, due October 1, 2004 40,000 40,000 Series S, 6 1/8%, due February 1, 2004 40,000 -- Installment Sales Agreements - PCRBs Series 1984, 7 7/8%, due September 15, 2014 44,310 44,310 Unamortized discount and premium (1,323) (1,162) Unamortized costs of reacquired debt (27,493) (29,316) Amount to be redeemed within one year (650) (12,650) 210,047 176,882 TOTAL CAPITALIZATION $488,292 $449,265
The accompanying notes to financial statements are an integral part of these statements.
2-175 NOTES TO FINANCIAL STATEMENTS
1.Summary of Significant Accounting Policies Public Utility Regulation WTU is subject to regulation by the SEC under the Holding Company Act, and the FERC under the Federal Power Act, and follows the Uniform System of Accounts prescribed by the FERC. WTU is subject to further regulation with regard to rates and other matters by the Texas Commission. WTU, as a member of the CSW System, engages in transactions and coordinates its activities and operations with other members of the CSW System.
The more significant accounting policies of WTU are summarized below:
Electric Utility Plant Electric utility plant is stated at the original cost of construction, which includes the cost of contracted services, direct labor, materials, overhead items and allowances for borrowed and equity funds used during construction.
Depreciation Provisions for depreciation of electric utility plant are computed using the straight-line method, generally at individual rates applied to the various classes of depreciable property. The annual average consolidated composite rates were 3.2% in both 1994 and 1993 and 3.1% in 1992.
Electric Revenues and Fuel Prior to January 1, 1993, electric revenues were recorded at the time billings were made to customers on a cycle-billing basis. Electric service provided subsequent to billing dates through the end of each calendar month became part of operating revenues of the next month. To conform to general industry standards, WTU changed its method of accounting to accrue for estimated unbilled revenues. The effect of this change on 1993 net income was an increase of $5.4 million included in cumulative effect of changes in accounting principles.
WTU recovers fuel costs in Texas as a fixed component of base rates whereby over-recoveries of fuel are payable to customers and under-recoveries of fuel may be billed to customers after Texas Commission approval. The cost of fuel is charged to expense as consumed. WTU recovers fuel costs applicable to wholesale customers, which are regulated by the FERC, through an automatic fuel adjustment clause.
Accounts Receivable. WTU sells its billed and unbilled accounts receivable, without recourse, to CSW Credit.
Regulatory Assets and Liabilities. For its regulated activities, WTU follows SFAS No. 71, which defines the criteria for establishing regulatory assets and regulatory liabilities. Regulatory assets represent probable future revenue to the company associated with certain costs which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future refunds to customers. At December 31, 1994 and 1993, WTU had recorded the following significant regulatory assets and liabilities:
2-176 1994 1993 (thousands) Regulatory Assets Deferred plant costs $26,914 $27,735
Regulatory Liabilities Income tax related regulatory liabilities, net $ 9,217 $10,545
Deferred Plant Costs In accordance with orders of the Texas Commission, WTU deferred operating, depreciation and tax costs incurred for Oklaunion Power Station Unit 1. This deferral was for the period beginning on the date when the plant began commercial operation until the date the plant was included in rate base. The deferred costs are being amortized and recovered through rates over the remaining life of the plant. See NOTE 9, Litigation and Regulatory Proceedings, for further discussion of WTU's deferred accounting.
Statements of Cash Flows Cash equivalents are considered to be highly liquid debt instruments purchased with a maturity of three months or less. Accordingly, temporary cash investments are considered cash equivalents.
Reclassification Certain financial statement items for prior years have been reclassified to conform to the 1994 presentation.
Accounting Changes Effective January 1, 1993, WTU adopted SFAS Nos. 106, 112 and 109. See NOTE 2, Federal Income Taxes, for further information regarding SFAS No. 109. In addition, WTU also changed its method of accounting for unbilled revenues. See Electric Revenues and Fuel above for further information.
The adoption of SFAS No. 106 resulted in an increase in 1993 operating expenses of $1.9 million. The adoption of SFAS No. 112 and the change in accounting for unbilled revenues are presented as a cumulative effect of changes in accounting principles as shown below:
Pre-Tax Tax Net Income Effect Effect Effect (thousands)
SFAS No. 112 $(2,534) $ 887 $(1,647) Unbilled revenues 8,347 (2,921) 5,426 Total $ 5,813 $(2,034) $ 3,779
Pro forma amounts assuming that the change in accounting for unbilled revenues had been adopted retroactively are not materially different from amounts previously reported for prior years.
2.Federal Income Taxes WTU adopted the provisions of SFAS No. 109 effective January 1, 1993. The implementation of SFAS No. 109 had no material effect on WTU's earnings. As a result of this change, WTU recognized additional accumulated deferred income taxes and corresponding regulatory assets and liabilities to ratepayers in amounts equal to future revenues or the reduction in future revenues required when the income tax temporary differences reverse and are recovered or settled in rates. As a result of a favorable earnings history, WTU did not record any valuation allowance against deferred tax assets at December 31, 1994 and 1993.
2-177 WTU, together with other members of the CSW System, files a consolidated federal income tax return and participates in a tax sharing agreement.
Components of income taxes follow:
1994 1993 1992 Included in Operating Expenses and Taxes (thousands) Current $10,898 $11,379 $11,797 Deferred 8,377 3,593 6,426 Deferred ITC (1,321) (1,321) (1,515) 17,954 13,651 16,708 Included in Other Income and Deductions Current (2,998) (510) 590 Deferred -- -- -- (2,998) (510) 590 Tax Effects of Cumulative Effect of Changes in Accounting Principles -- 2,034 -- $14,956 $15,175 $17,298
Investment tax credits deferred in prior years are included in income over the lives of the related properties.
Total income taxes differ from the amounts computed by applying the statutory income tax rates to income before taxes. The reasons for the differences follow:
1994 % 1993 % 1992 % (dollars in thousands) Tax at statutory rates $18,313 35.0 $15,915 35.0 $17,784 34.0 Differences Amortization of ITC (1,321) (2.5) (1,321) (2.9) (1,321) (2.5) Other (2,036) (3.9) 581 1.3 835 1.7 $14,956 28.6 $15,175 33.4 $17,298 33.2
2-178 The significant components of the net deferred income tax liability follow:
1994 1993 (thousands) Deferred Income Tax Liabilities Depreciable utility plant $144,501 $120,015 Deferred plant costs 9,420 9,707 Income tax related regulatory liability 10,908 11,074 Other 10,120 18,963 Total Deferred Income Tax Liabilities 174,949 159,759
Deferred Income Tax Assets Income tax related regulatory liability (14,134) (14,765) Unamortized ITC (11,159) (11,621) Other (6,578) -- Total Deferred Income Tax Assets (31,871) (26,386) Net Accumulated Deferred Income Taxes - Total $143,078 $133,373
Net Accumulated Deferred Income Taxes - Noncurrent $146,146 $134,595 Net Accumulated Deferred Income Taxes - Current (3,068) (1,222) Net Accumulated Deferred Income Taxes - Total $143,078 $133,373
3.Long-Term Debt The mortgage indenture, as amended and supplemented, securing first mortgage bonds issued by WTU, constitutes a direct first mortgage lien on substantially all electric utility plant. WTU may offer additional FMBs subject to market conditions and other factors.
Annual Requirements Series O FMBs have annual sinking fund requirements, which may be satisfied by the application of net expenditures for bondable property in an amount equal to 166-2/3% of the annual requirements or at WTU's option, the redemption of 1% of the amount originally issued. At December 31, 1994, the annual sinking fund requirements for the next five years, exclusive of maturities, of WTU's first mortgage bonds are $650,000. Pursuant to these sinking fund requirements, WTU elected to redeem at par $650,000 Series O, FMBs in December 1994.
Dividends WTU's mortgage indenture, as amended and supplemented, contains certain restrictions on the payment of common stock dividends. At December 31, 1994, $133 million of retained earnings were available for the payment of cash dividends to its parent, CSW.
Reacquired long-term debt Reference is made to MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources, for further information related to long-term debt, including new issues and reacquisition.
4.Preferred Stock In July 1993, WTU redeemed 100,000 shares of its 7.25% Series, $100 par value, Preferred Stock, for $10 million, in accordance with mandatory and optional sinking fund provisions. The capital required for this transaction was provided by short-term borrowings from the CSW System money pool and internal sources.
2-179 In July 1994, WTU redeemed the remaining 47,000 shares of its 7.25% Series, $100 par value, Preferred Stock.
5.Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value.
Cash and temporary cash investments The carrying amount approximates fair value because of the short maturity of those instruments.
Advances from affiliates The carrying amount approximates fair value because of the short maturity of those instruments.
Long-term debt The fair value of the WTU's long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to WTU for debt of the same remaining maturities.
Preferred stock subject to mandatory redemption The fair value of the WTU's preferred stock subject to mandatory redemption is estimated based on quoted market prices for the same or similar issues or on the current rates offered to WTU for preferred stock with the same or similar remaining redemption provisions.
Current maturities of long-term debt The fair value of current maturities is estimated based on quoted market prices for the same or similar issues or the current rates offered for long-term debt.
The estimated fair values of WTU's financial instruments follow:
1994 1993 Carrying Fair Carrying Fair Amount Value Amount Value (thousands) Cash and temporary cash investments $ 2,501 $ 2,501 $ 706 $ 706 Current maturities of long-term debt 650 666 12,650 12,800 Advances from affiliates 46,315 46,315 36,285 36,285 Long-term debt 210,047 228,802 176,882 225,082 Preferred stock -- -- 4,648 4,671
The fair value does not affect WTU's liabilities unless the issues are redeemed prior to their maturity dates.
6.Short-Term Financing WTU, together with other members of the CSW System, has established a money pool to coordinate short-term borrowings and to make borrowings outside the money pool through CSW's issuance of commercial paper. Money pool balances are shown as advances to or from affiliates on the Balance Sheets. At December 31, 1994, the CSW System had bank lines of credit aggregating $930 million to back up its commercial paper program. Short-term cash surpluses transferred to the money pool receive interest income in accordance with the money pool arrangement.
2-180 7.Benefit Plans Defined Benefit Pension Plan WTU, together with other members of the CSW System, maintains a tax qualified, non-contributory defined benefit pension plan covering substantially all employees. Benefits are based on employees' years of credited service, age at retirement, and final average annual earnings with an offset for the participant's primary Social Security benefit. The CSW System's funding policy is based on actuarially determined contributions, taking into account amounts which are deductible for income tax purposes and minimum contributions required by the ERISA. Pension plan assets consist primarily of common stocks and short-term and intermediate- term fixed income investments.
Contributions to the plan for the years ended December 31, 1994, 1993 and 1992 were $3.8 million, $3.9 million and $3.4 million, respectively.
The approximate maximum number of participants in the plan during 1994 were 1,300 active employees, 500 retirees and beneficiaries and 100 terminated employees.
The components of net periodic pension cost and the assumptions used in accounting for pensions follow:
1994 1993 1992 (thousands) Net Periodic Pension Cost Service cost $ 3,082 $ 2,732 $ 2,569 Interest cost on projected benefit obligation 8,501 7,776 7,274 Actual return on plan assets (601) (9,448) (6,242) Net amortization and deferral (9,556) 35 (2,836) $ 1,426 $ 1,095 $ 765
Discount rate 8.25% 7.75% 8.50% Long-term compensation increase 5.46% 5.46% 5.96% Return on plan assets 9.50% 9.50% 9.50%
At December 31, 1994, the plan's net assets were approximately equal to the total actuarial present value of the accumulated benefit obligation. At December 31, 1993 the plan's net assets exceeded the total actuarial present value of the accumulated benefit obligation. No reconciliation of the funding status of the plan is presented because such information is unavailable.
Health and Welfare Plans WTU had medical, dental, group life insurance, dependent life insurance, and accidental death and dismemberment plans for substantially all active WTU employees during 1994. The contributions, recorded on a pay-as-you-go basis for the years ended December 31, 1994 and 1993 were approximately $2.7 million and $3.5 million, respectively. Effective January 1993, WTU's method of providing health benefits was modified to include such benefits as preferred provider options, managed prescription drug and mail-order program and a mental health and substance abuse program in addition to the self-insured indemnity plans.
Postretirement Benefits Other Than Pensions WTU adopted SFAS No. 106 January 1, 1993. The effect on operating expense in 1993 was $1.9 million. WTU is amortizing its transition obligation over twenty years, with eighteen years remaining. In prior years, these benefits were accounted for on a pay-as-you-go basis.
2-181 The components of net periodic postretirement benefit cost follow:
1994 1993 (thousands) Net Periodic Postretirement Benefit Cost Service cost $1,233 $1,157 Interest cost on APBO 2,559 2,316 Actual return on plan assets (113) (104) Amortization of transition obligation 1,225 1,225 Net amortization and deferral (418) (296) $4,486 $4,298
A reconciliation of the funded status of the plan to the amounts recognized on the consolidated balance sheets follow:
December 31, 1994 1993 APBO (thousands) Retirees $ 19,703 $ 18,722 Other fully eligible participants 4,764 4,624 Other active participants 7,519 8,758 Total APBO 31,986 32,104 Plan assets at fair value (9,636) (6,064) APBO in excess of plan assets 22,350 26,040 Unrecognized transition obligation (22,047) (23,272) Unrecognized gain or (loss) 91 (2,374) Accrued/(Prepaid) Cost $ 394 $ 394
The following assumptions were used in accounting for SFAS No. 106:
1994 1993 Discount rate 8.25% 7.75% Return on plan assets 9.50% 9.00% Tax rate for taxable trusts 39.60% 39.60%
Health Care Cost Trend Rate Assumptions Pre-65 Participants: 1994 Rate of 11.75% grading down .75% per year to an ultimate rate of 6.5% in 2001.
Post-65 Participants: 1994 Rate of 11.25% grading down .75% per year to an ultimate rate of 6.0% in 2001.
Increasing the assumed health care cost trend rates by one percentage point in each year would increase the APBO as of December 31, 1994 by $3.5 million and increase the aggregate of the service and interest costs components on net postretirement benefits by $.5 million.
8.Jointly Owned Electric Utility Plant WTU has a joint ownership agreement with other members of the CSW System and other non-affiliated entities. Such agreements provide for the joint ownership and operation of Oklaunion Power Station. Each participant provided financing for its share of the project, which was placed in service in December 1986. The statements of income reflect WTU's portion of operating costs associated with jointly owned plant in service. WTU's share is 370 MW or a 54.7% interest in the generating station. WTU's total investment, including AFUDC is $280 million and accumulated depreciation at December 31, 1994 is $59 million.
2-182 9.Litigation and Regulatory Proceedings Rate Proceeding - Docket No. 13369 On August 25, 1994, WTU filed a petition with the Texas Commission and with cities with original jurisdiction to review WTU's rates, proposed an interim across-the-board base rate reduction of 3.25% or, approximately $5.7 million, effective October 1, 1994, and sought until February 28, 1995, the time to develop and file a RFP. WTU also requested the ability to "true-up", back to October 1, 1994, any difference in revenue requirements upon final order of the Texas Commission, and proposed that any increases over the pre-October 1, 1994, base rates be implemented prospectively on the effective date of the final order.
As discussed below, WTU's fuel reconciliation was consolidated with this proceeding in September 1994. Reconcilable fuel costs during the reconciliation period were approximately $300 million. At June 30, 1994, the fuel cost under-recovery totaled approximately $5.1 million, including interest. At December 31, 1994, this amount had become an over-recovery of approximately $0.2 million. WTU is not seeking a change in fuel factors.
On February 28, 1995, WTU filed with the Texas Commission and cities with original jurisdiction the RFP which indicates a revenue deficiency of approximately $14.5 million. However, WTU simultaneously filed with the parties a settlement proposal to reduce overall base rate revenue by 3.25%, effective October 1, 1994, an annual impact in the rate year beginning January 1, 1996 of approximately $5.9 million. The settlement proposal reflects WTU's desire to maintain competitive rates, recognizes the importance of competitive rates in the changing electric service marketplace, and demonstrates WTU's strong commitment to the long- term success of WTU and its customers.
Unless a settlement accelerates the schedule, WTU anticipates hearings in mid-1995 with a final order in the fourth quarter of 1995. Management cannot predict the outcome of the rate proceeding, the fuel reconciliation, or the settlement proposal, but believes that the ultimate resolution of these matters will not have a material adverse effect on WTU's results of operations or financial condition.
Fuel Reconciliation - Docket No. 13172 On June 30, 1994, WTU filed a petition with the Texas Commission to reconcile fuel costs for the period January 1991 through February 1994. Subsequently, in September 1994, this fuel reconciliation proceeding was consolidated into Docket No. 13369 described above, and the reconciliation period was extended through June 1994.
Rate Case Proceeding - Docket No. 7510 In November 1987, the Texas Commission issued a final order in WTU's retail rate case providing for WTU to receive an annual increase in base retail revenues of $34.9 million. Rates reflecting the final order were implemented in December 1987. WTU, along with certain intervenors in the retail rate proceeding, appealed the Texas Commission's final order to the District Court seeking reversal of various provisions of the final order, including the inclusion of deferred accounting in rate base.
The appeals were consolidated and in September 1988, the District Court affirmed the final order of the Texas Commission. In November 1988, certain intervenors filed appeals of the District Court's judgment with the Court of Appeals. In February 1990, the Court of Appeals ruled that an intervenor had improperly been excluded from presenting its appeal to the District Court, reversed the District Court's judgment and remanded the case to the District Court for further proceedings.
In October 1992, the District Court heard the remanded appeals of the final order of the Texas Commission and in March 1993 issued an order affirming the Texas Commission's order in all material respects with the single exception of the inclusion of deferred Oklaunion carrying costs in rate base. In its treatment of
2-183 deferred costs, the District Court followed a then-current opinion of the Court of Appeals which precluded recovery of deferred post- in-service carrying costs. In April 1993, WTU and other parties filed appeals, and oral argument was held on the appeals in December 1993 on the non-deferred accounting issues. With respect to the deferred accounting issues, the parties recognized certain Supreme Court of Texas decisions regarding other deferred accounting cases would be influential in WTU's case.
In June 1994, the Supreme Court of Texas issued its opinion in the three other cases involving deferred accounting holding that the Texas Commission has the authority to allow deferred accounting treatment during the deferral period, including deferred post-in- service carrying costs. The Supreme Court of Texas upheld the Court of Appeals in all respects except it reversed the Court of Appeals to the extent it disallowed carrying costs deferrals and remanded to the Court of Appeals for consideration of the unresolved arguments of the improperly excluded intervenor. Motions for rehearing were filed by certain parties which were denied by the Supreme Court of Texas. These rulings influenced the Court of Appeals' decision in WTU's rate case appeals, as described below.
On February 15, 1995, the Court of Appeals affirmed all aspects of the District Court judgment relating to the Texas Commission's allowance of non-Oklaunion depreciation rates and the surcharge of rate case expenses, reversed the District Court's judgment relating to the exclusion of deferred Oklaunion carrying costs in rate base, and remanded the cause to the Texas Commission to reexamine the issue of deferred costs in light of the remand of Docket No. 7289, as described below. However, on March 3, 1995, WTU filed a motion for rehearing at the Court of Appeals seeking clarification of certain aspects of its order and arguing that the Court of Appeals erred in remanding the case to the Texas Commission for it to determine to what extent deferred costs are necessary to preserve WTU's financial integrity because the issue has been waived since it was not briefed or argued to the Court of Appeals. WTU expects other parties may also file motions for rehearing.
WTU's motion for rehearing may, if granted, prevent further review of financial integrity issues with respect to deferred accounting in any remand of Docket No. 7510. If a broader remand is permitted and if the Texas Commission concludes in Docket No. 7289 that deferred accounting was necessary to preserve WTU's financial integrity during the deferral period, the Texas Commission must decide to what extent the deferred Oklaunion costs, including carrying costs, were necessary to preserve WTU's financial integrity. If WTU's deferred accounting treatment is ultimately reversed or is substantially reduced, WTU could experience a material adverse impact on its results of operations. While management can give no assurances as to the outcome of the remanded proceeding or the motion for rehearing, management believes that 100 percent of the Oklaunion deferred costs will be determined by the Texas Commission to have been necessary to preserve WTU's financial integrity during the deferral period so that there will be no material adverse effect on WTU's results of operations or financial condition.
Deferred Accounting - Docket No. 7289 WTU received approval from the Texas Commission in September 1987 to defer operating expenses and carrying costs associated with Oklaunion incurred subsequent to its December 1986 commercial operation date until December 1987 (the deferral period) when retail rates including Oklaunion in WTU's rate base became effective. WTU has recorded approximately $32 million of Oklaunion deferred costs, of which $25 million are carrying costs. The deferred costs are being recovered and amortized over the remaining life of the plant. In November 1987, OPUC filed an appeal in the District Court challenging the Texas Commission's final order authorizing WTU to defer the costs associated with Oklaunion. In October 1988, the District Court affirmed the final order of the Texas Commission. In December 1988, OPUC filed an appeal of the District Court judgment in the Court of Appeals. In September 1990, the Court of Appeals upheld the District Court's affirmance of the Texas Commission's final order and in October 1990, OPUC filed a motion for rehearing of the Court of Appeals' decision, which was denied in November 1990. On further appeal, the Supreme Court heard oral argument in September 1993, in WTU's case as well as three other cases involving deferred accounting
2-184 and in June 1994 issued its opinions in these cases affirming the Texas Commission's authority to allow deferred accounting treatment, but establishing a financial integrity standard rather than the measurable harm standard used by the Texas Commission.
In October 1994, the Supreme Court of Texas issued a mandate remanding WTU's deferred accounting case to the Texas Commission. While no schedule has yet been established for the proceedings on remand at the Texas Commission, this remand may be considered in tandem with WTU's pending rate case, Docket No. 13369. In the remanded proceeding, the Texas Commission must make a formal finding that the deferral of Oklaunion costs was necessary to prevent WTU's financial integrity during the deferral period from being jeopardized.
If WTU's deferred accounting treatment is ultimately reversed and not favorably resolved, WTU could experience a material adverse impact on its results of operations. While management cannot predict the ultimate outcome of these proceedings, management believes that WTU's deferred accounting will be ultimately sustained by the Texas Commission on the basis of the financial integrity standard set forth by the Supreme Court of Texas, so that there will be no material adverse effect on WTU's results of operations or financial condition.
FERC Order On April 4, 1994, the FERC issued an order pursuant to section 211 of the Federal Power Act forcing a regional utility to transmit power to Tex-La on behalf of WTU. The order was one of the first issued by FERC under that provision, which was added by the Energy Policy Act to increase competition in wholesale power markets. On December 1, 1994, the FERC issued an order requiring a regional utility to provide this transmission service at a cost which was acceptable to Tex-La. The FERC also ordered the same regional utility to enter into an interconnection and remote control area load agreement with WTU within 30 days. This agreement was executed on January 3, 1995. On January 5, 1995, WTU began selling 92 MW of power and energy to Tex-La. Tex-La has a peak requirement of approximately 120 MWs. WTU will serve Tex-La until facilities are completed to connect Tex-La to SWEPCO, at which time SWEPCO will provide 85 MW and WTU will retain 35 MW of the Tex-La electric load.
Other WTU is party to various other legal claims, actions and complaints arising in the normal course of business. Management does not expect disposition of these matters to have a material adverse effect on WTU's results of operations or financial condition.
10. Commitments and Contingent Liabilities Construction It is estimated that WTU will spend approximately $37 million in construction expenditures during 1995. Substantial commitments have been made in connection with this capital expenditure program.
Fuel To supply a portion of its fuel requirements WTU has entered into various commitments for the procurement of fuel. WTU has a sale/leaseback agreement with Transok, an affiliated company, for full capacity use of a natural gas pipeline to WTU's Ft. Phantom generating plant. The lease agreement also provides for full capacity use of Transok's natural gas pipelines serving WTU's San Angelo and Oak Creek generating plants. The initial terms of the agreement are for twelve years with renewable options thereafter.
2-185 11. Quarterly Information (Unaudited) The following unaudited quarterly information includes, in the opinion of management, all adjustments necessary for a fair presentation of such amounts.
Quarter Ended Operating Operating Net Revenues Income Income 1994 (thousands) March 31 $ 83,319 $ 8,487 $ 3,546 June 30 83,016 12,958 8,192 September 30 109,348 27,987 23,271 December 31 67,308 5,331 2,357 $342,991 $54,763 $37,366
March 31 $ 73,109 $ 9,540 $ 7,898 June 30 86,973 14,060 9,086 September 30 109,897 24,172 19,490 December 31 75,466 (1,196) (6,178) $345,445 $45,576 $30,296
Information for quarterly periods is affected by seasonal variations in sales, rate changes, timing of fuel expense recovery and other factors.
2-186 Report of Independent Public Accountants
To the Stockholders and Board of Directors of West Texas Utilities Company:
We have audited the accompanying balance sheets and statements of capitalization of West Texas Utilities Company (a Texas corporation and a wholly-owned subsidiary of Central and South West Corporation) as of December 31, 1994 and 1993, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of WTU's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of West Texas Utilities Company as of December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
In 1993, as discussed in NOTE 1, WTU changed its methods of accounting for unbilled revenues, postretirement benefits other than pensions, income taxes and postemployment benefits.
Our audits were made for the purpose of forming an opinion on the financial statements taken as a whole. The supplemental Schedule II and Exhibit 12 are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. This schedule and exhibit have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Arthur Andersen LLP
Dallas, Texas February 13, 1995
2-187 Report of Management
Management is responsible for the preparation, integrity and objectivity of the financial statements of West Texas Utilities Company as well as other information contained in this Annual Report. The financial statements have been prepared in conformity with generally accepted accounting principles applied on a consistent basis and, in some cases, reflect amounts based on the best estimates and judgments of management, giving due consideration to materiality. Financial information contained elsewhere in this Annual Report is consistent with that in the financial statements.
The financial statements have been audited by the independent accounting firm, Arthur Andersen LLP, which was given unrestricted access to all financial records and related data, including minutes of all meetings of shareholders, the board of directors and committees of the board. WTU believes that representations made to the independent auditors during their audit were valid and appropriate. Arthur Andersen LLP's audit report is presented elsewhere in this report.
WTU maintains a system of internal controls to provide reasonable assurance that transactions are executed in accordance with management's authorization, that the financial statements are prepared in accordance with generally accepted accounting principles and that the assets of the companies are properly safeguarded against unauthorized acquisition, use or disposition. The system includes a documented organizational structure and division of responsibility, established policies and procedures including a policy on ethical standards which provides that WTU will maintain the highest legal and ethical standards, and the careful selection, training and development of our employees.
Internal auditors continuously monitor the effectiveness of the internal control system following standards established by the Institute of Internal Auditors. Actions are taken by management to respond to deficiencies as they are identified. The board, operating through its audit committee, which is comprised entirely of directors who are not officers or employees of WTU provides oversight to the financial reporting process.
Due to the inherent limitations in the effectiveness of internal controls, no internal control system can provide absolute assurance that errors will not occur. However, management strives to maintain a balance, recognizing that the cost of such a system should not exceed the benefits derived.
WTU believes that, in all material respects, its system of internal controls over financial reporting and over safeguarding of assets against unauthorized acquisition, use or disposition functioned effectively during 1994.
Glenn Files R. Russell Davis President and CEO - WTU Controller - WTU
2-188 ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
3-1 PART III
CPL, PSO, SWEPCO and WTU CSW common stock amounts in ITEM 11 and ITEM 12 reflect the two- for-one common stock split, effected by a 100% common stock dividend paid March 6, 1992 to shareholders of record on February 10, 1992.
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS. CSW CSW has filed with the SEC its Notice of Annual Meeting of Stockholders and Proxy Statement relating to its 1995 Annual Meeting of Stockholders. The information required by ITEM 10, other than with respect to certain information regarding the executive officers of CSW which is included in ITEM 1. BUSINESS - Executive Officers of the Registrant, is hereby incorporated by reference to pages 3-5 and 8 of such Proxy Statement.
CPL, PSO, SWEPCO AND WTU (a) The following is a list of directors of each of the Electric Operating Companies, together with certain information with respect to each of them:
Name, Age, Principal Year Occupation, Business Experience First Became and Other Directorships Director
CPL
E. R. BROOKS. . . . . . . . . . . . . . . . . . AGE - 57 1991 Chairman, President and CEO of CSW since 1991. President of CSW from 1990 to 1991. President and COO of CSW from January 1990 to September 1990. Director of CSW and each of its subsidiaries. Director of Hubbell, Inc., Orange, Connecticut. Trustee of Baylor University Medical Center, Dallas, Texas and Hardin Simmons University, Abilene, Texas.
ROBERT R. CAREY. . . . . . . . . . . . . . AGE - 57 1989 President and CEO of CPL since 1990. Executive Vice President and COO of CPL from 1989 to 1990. Director of NationsBank, Corpus Christi, Texas.
RUBEN M. GARCIA. . . . . . . . . . . . . . AGE - 63 1981 President or principal of several firms engaged primarily in construction and land development in the Laredo, Texas area.
DAVID L. HOOPER. . . . . . . . . . . . . . .AGE - 39 1994 Vice President, Marketing and Business Development of CPL since 1994. Director of Marketing and Business Development of CSWS from 1993 to 1994. Director of Marketing and Business Development of CPL from 1991 to 1993. Area manager of CPL from 1990 to 1991. Director of Corporate Communications of CPL from 1988 to 1990.
HARRY D. MATTISON. . . . . . . . . . . . AGE - 58 1994 Executive Vice President of CSW since 1990 and CEO of CSWS since 1993. COO of CSW from 1990 to 1993. President and CEO of SWEPCO from 1988 to 1990. Director of CSW and each of CSW's wholly-owned subsidiaries.
3-2 Name, Age, Principal Year Occupation, Business Experience First Became and Other Directorships Director
ROBERT A. McALLEN. . . . . . . . . . . . AGE - 60 1983 Robert A. McAllen, Insurance Agency, Weslaco, Texas.
PETE MORALES, JR. . . . . . . . . . . . . .AGE - 54 1990 President and General Manager of Morales Feed Lots, Inc., Devine, Texas. Director of The Bank of Texas, Devine, Texas.
S. LOYD NEAL, JR. . . . . . . . . . . . . . AGE - 57 1990 President of Hilb, Rogal and Hamilton Company of Corpus Christi, an insurance agency, Corpus Christi, Texas. Director of Bay Area Medical Center, Corpus Christi, Texas.
JIM L. PETERSON. . . . . . . . . . . . . . .AGE - 59 1989 President and CEO of Whataburger, Inc., Corpus Christi, Texas. President of Peterson Ranch and Cattle Company, Goliad, Texas. President and CEO of Bojangles Restaurants Inc., Charlotte, North Carolina. Director of Mercantile Bank of Corpus Christi and Brownsville, Texas.
H. LEE RICHARDS. . . . . . . . . . . . . . .AGE - 61 1987 Chairman of the Board of Hygeia Dairy Company, Harlingen, Texas.
MELANIE J. RICHARDSON. . . . . . . . . AGE - 38 1993 Vice President, Administration of CPL since 1993. Treasurer of CPL from 1992 to 1994. Vice President, Corporate Services of CPL from 1992 to 1993. Director of Internal Audits of CPL from 1991 to 1992. Manager of Personnel Services of CPL from 1986 to 1991.
J. GONZALO SANDOVAL. . . . . . . . . . AGE - 46 1992 Vice President, Operations/Engineering of CPL since 1993. Vice President, Regional Operations of CPL from 1992 to 1993. Vice President, Corporate Services of CPL from 1991 to 1992. General Manager of the Southern Region from 1988 to 1991.
GERALD E. VAUGHN. . . . . . . . . . . . . AGE - 52 1993 Vice President, Nuclear of CSWS since 1994. Vice President, Nuclear Affairs of CPL since 1993. Vice President for Nuclear Services of Carolina Power and Light Company, Raleigh, North Carolina, from 1990 to 1993. Vice President of Nuclear Operations at HLP from 1987 to 1990.
Each of the directors and executive officers of CPL is elected to hold office until the first meeting of CPL's Board of Directors after the 1995 Annual Meeting of Stockholders. CPL's 1995 Annual Meeting of Stockholders is presently scheduled to be held on April 13, 1995. All outside directors have engaged in their principal occupations listed above for a period of more than five years, unless otherwise indicated.
3-3 Name, Age, Principal Year Occupation, Business Experience First Became and Other Directorships Director
PSO
E. R. BROOKS. . . . . . . . . . . . . . . . . . AGE - 57 1991 Chairman, President and CEO of CSW since 1991. President of CSW from 1990 to 1991. President and COO of CSW from January 1990 to September 1990. Director of CSW and each of its subsidiaries. Director of Hubbell, Inc., Orange, Connecticut. Trustee of Baylor University Medical Center, Dallas, Texas and Hardin Simmons University, Abilene, Texas.
HARRY A. CLARKE. . . . . . . . . . . . . . . . . . . . . AGE - 66 1972 HAC Investments, Afton, Oklahoma.
PAUL K. LACKEY, JR. . . . . . . . . . . . . . . . . . . . AGE - 51 1992 Consultant, Flint Industries, Inc., a construction, electronics manufacturing, and environmental services company, Tulsa, Oklahoma. Advisory Director of Bank IV-Tulsa, Tulsa, Oklahoma.
PAULA MARSHALL-CHAPMAN . . . . . . . . . . . . . . . . . .AGE - 41 1991 General Partner/CEO of Bama Pie Ltd., a baked goods produce company, Tulsa, Oklahoma.
HARRY D. MATTISON. . . . . . . . . . . . .AGE - 58 1994 Executive Vice President of CSW since 1990 and CEO of CSWS since 1993. COO of CSW from 1990 to 1993. President and CEO of SWEPCO from 1988 to 1990. Director of CSW and each of CSW's wholly-owned subsidiaries.
WILLIAM R. McKAMEY . . . . . . . . . . . . . . . . . . . .AGE - 48 1993 Vice President, Marketing and Business Development of PSO since 1993. Director of Marketing and Business Development of CSW from 1992 to 1993. Director of Marketing of SWEPCO from 1990 to 1992.
MARY M. POLFER . . . . . . . . . . . . . . . . . . . . . .AGE - 50 1991 Vice President, Administration of PSO since 1993. Vice President, Finance of PSO from 1990 to 1993. Director Corporate Projects from 1987 to 1990, Farmland Industries, Inc., a federated cooperative, Kansas City, Missouri.
DR. ROBERT B. TAYLOR, JR. . . . . . . . . . . . . . . . . AGE - 66 1975 Dentist, Okmulgee, Oklahoma.
ROBERT L. ZEMANEK . . . . . . . . . . . . . . . . . . . . AGE - 45 1990 President and CEO of PSO since 1992. Executive Vice President of PSO from 1990 to 1992. Vice President, Corporate Services of PSO from 1989 to 1990.
3-4 Name, Age, Principal Year Occupation, Business Experience First Became and Other Directorships Director
WALDO J. ZERGER, JR. . . . . . . . . . . . . . . . . . . .AGE - 48 1991 Vice President, Operations and Engineering of PSO since 1994. Vice President of Division Operations of PSO from 1990 to 1994.
Each of the directors and executive officers of PSO is elected to hold office until the first meeting of PSO's Board of Directors after the 1995 Annual Meeting of Stockholders. PSO's 1995 Annual Meeting of Stockholders is presently scheduled to be held on April 18, 1995. All outside directors have engaged in their principal occupations listed above for a period of more than five years, unless otherwise indicated.
SWEPCO
RICHARD H. BREMER . . . . . . . . . . . . . . . . . . . . AGE - 46 1989 President and CEO of SWEPCO since 1990. Vice President, Operations of SWEPCO from 1989 to 1990. Director of Commercial National Bank, Shreveport, Louisiana. Director of Deposit Guaranty Corporation, Jackson, Mississippi.
E. R. BROOKS. . . . . . . . . . . . . . . . . . AGE - 57 1991 Chairman, President and CEO of CSW since 1991. President of CSW from 1990 to 1991. President and COO of CSW from January 1990 to September 1990. Director of CSW and each of its subsidiaries. Director of Hubbell, Inc., Orange, Connecticut. Trustee of Baylor University Medical Center, Dallas, Texas and Hardin Simmons University, Abilene, Texas.
JAMES E. DAVISON . . . . . . . . . . . . . AGE - 57 1993 Sole Proprietor of Paul M. Davison Petroleum Products. President and Chief Executive Officer of Davison Transport, Inc. and Davison Terminal Services, Inc. Advisory Board member of Heritage Financial Group. All of the above entities are located in Ruston, Louisiana.
AL P. EASON, JR. . . . . . . . . . . . . . . . . . . . . .AGE - 69 1975 Retired as Chairman and CEO of the First Federal Savings and Loan Association of Fayetteville, Arkansas in 1990. President, Eason and Company, a general insurance company, Fayetteville, Arkansas.
W. J. GOOGE, JR. . . . . . . . . . . . . . . . . . . . . .AGE - 52 1990 Vice President, Administration of SWEPCO since 1993. Vice President, Corporate Services of SWEPCO from 1990 to 1993. Vice President, Personnel, Safety and Insurance of SWEPCO from 1984 to 1990.
DR. FREDERICK E. JOYCE . . . . . . . . . . . . . . . . . .AGE - 60 1990 Physician. President of Chappell-Joyce Pathology Association, P.A., Texarkana, Texas. President of Doctors Diagnostic Laboratory, Inc., Texarkana, Texas. Director of State First National Bank and State First Financial Corporation, Texarkana, Arkansas. Director of First Commercial Corporation, Little Rock, Arkansas.
3-5 Name, Age, Principal Year Occupation, Business Experience First Became and Other Directorships Director
MICHAEL H. MADISON . . . . . . . . . . . . . . . . . . . .AGE - 46 1992 Vice President, Operations and Engineering of SWEPCO since 1993. Vice President, Engineering and Production of SWEPCO from 1992 to 1993. Vice President, Corporate Services of WTU from 1990 to 1992. Eastern Division Manager of PSO in 1990.
HARRY D. MATTISON. . . . . . . . . . . . .AGE - 58 1994 Executive Vice President of CSW since 1990 and CEO of CSWS since 1993. COO of CSW from 1990 to 1993. President and CEO of SWEPCO from 1988 to 1990. Director of CSW and each of CSW's wholly-owned subsidiaries.
MARVIN R. McGREGOR. . . . . . . . . . . . . . . . . . . . AGE - 48 1990 Vice President, Marketing and Business Development of SWEPCO since 1990.
WILLIAM C. PEATROSS . . . . . . . . . . . . . . . . . . . AGE - 51 1990 President of Caddo Abstract and Title Co., Inc., Partner-Baucum, Hamilton and Peatross, a law firm; Partner-Kernmass-X Oil Company, Partner-Coastal Land Association, Director of Commercial National Bank. All of the above entities are located in Shreveport, Louisiana.
JACK L. PHILLIPS . . . . . . . . . . . . . . . . . . . . .AGE - 70 1986 Owner of Jack L. Phillips Oil & Gas Exploration and Production, Gladewater, Texas. Director of Longview National Bank, Longview, Texas.
Each of the directors and executive officers of SWEPCO is elected to hold office until the first meeting of SWEPCO's Board of Directors after the 1995 Annual Meeting of Stockholders. SWEPCO's 1995 Annual Meeting of Stockholders is presently scheduled to be held on April 12, 1995. All outside directors have engaged in their principal occupations listed above for a period of more than five years, unless otherwise indicated.
WTU
RICHARD F. BACON . . . . . . . . . . . . . . . . . . . . .AGE - 68 1980 Retired President and CEO of Merchants, Inc. Companies, a freight common carrier, Abilene, Texas.
C. HARWELL BARBER . . . . . . . . . . . . . . . . . . . . AGE - 68 1990 Chairman of Rita Barber, Inc., a burial clothing company, Abilene, Texas.
E. R. BROOKS. . . . . . . . . . . . . . . . . . AGE - 57 1980 Chairman, President and CEO of CSW since 1991. President of CSW from 1990 to 1991. President and COO of CSW from January 1990 to September 1990. Director of CSW and each of its subsidiaries. Director of Hubbell, Inc., Orange, Connecticut. Trustee of Baylor University Medical Center, Dallas, Texas and Hardin Simmons University, Abilene, Texas.
3-6 Name, Age, Principal Year Occupation, Business Experience First Became and Other Directorships Director
PAUL J. BROWER . . . . . . . . . . . . . . . . . . . . . AGE - 46 1991 Vice President, Marketing and Business Development of WTU since 1991. Division Manager of PSO from 1990 to 1991 and Corporate Sales Manager of PSO from 1986 to 1990.
T. D. CHURCHWELL. . . . . . . . . . . . . . . . . . . . .AGE - 50 1994 Executive Vice President of WTU since 1994. Vice President, Corporate Services of CSWS from 1991 to 1993. Central Region Manager of CPL from 1989 to 1991.
GLENN FILES . . . . . . . . . . . . . . . . . . . . . . .AGE - 47 1991 President and CEO of WTU since 1992. Executive Vice President of WTU from 1991 to 1992. Vice President, Marketing and Business Development of CPL from 1990 to 1991. Director of Corporate Planning of PSO from 1988 to 1990. Director of First National Bank of Abilene, Texas.
HARRY D. MATTISON. . . . . . . . . . . . AGE - 58 1994 Executive Vice President of CSW since 1990 and CEO of CSWS since 1993. COO of CSW from 1990 to 1993. President and CEO of SWEPCO from 1988 to 1990. Director of CSW and each of CSW's wholly-owned subsidiaries.
TOMMY MORRIS . . . . . . . . . . . . . . . . . . . . . . AGE - 60 1976 Independent insurance agent, Abilene, Texas.
DIAN G. OWEN . . . . . . . . . . . . . . . . . . . . . . AGE - 55 1994 Chairman of Owen Healthcare, Inc., hospital services, Abilene, Texas. Director of First National Bank of Abilene, Abilene, Texas. Director of First Financial Bankshares, Inc., Abilene, Texas.
JAMES M. PARKER . . . . . . . . . . . . . . . . . . . . .AGE - 64 1987 President and CEO of J. M. Parker and Associates, Inc., an investment company, Abilene, Texas. Director of First Financial Bankshares, Inc. and First National Bank of Abilene, Abilene, Texas.
DENNIS M. SHARKEY . . . . . . . . . . . . . . . . . . . .AGE - 50 1994 Vice President, Administration of WTU since 1994. Vice President, Finance and Director of SWEPCO from 1990 to 1993. Vice President and Corporate Secretary of WTU from 1989 to 1990.
F. L. STEPHENS . . . . . . . . . . . . . . . . . . . . . AGE - 57 1980 Chairman and CEO of Town & Country Food Stores, Inc., San Angelo, Texas. Director of First National Bank at Lubbock, Lubbock, Texas. Director of Norwest Texas, Lubbock, Texas.
DONALD A. WELCH . . . . . . . . . . . . . . . . . . . . .AGE - 55 1982 Vice President, Operations and Engineering of WTU since 1993. Vice President, Division Operations of WTU from 1991 to 1992. Vice President, District Operations of WTU from 1990 to 1991.
3-7 Each of the directors and executive officers of WTU is elected to hold office until the first meeting of WTU's Board of Directors after the 1995 Annual Meeting of Stockholders. WTU's 1995 Annual Meeting of Stockholders is presently scheduled to be held on March 28, 1995. All outside directors have engaged in their principal occupations listed above for a period of more than five years, unless otherwise indicated.
(b) The following is a list of the executive officers who are not directors of the registrants, together with certain information with respect to each of them:
Year First Name, Age, Principal Elected to Occupation, Business Experience Present Position
CPL, PSO, SWEPCO and WTU SHIRLEY S. BRIONES . . . . . . . . . . . . . . . . . . . AGE - 43 1994 Treasurer of CPL, PSO, SWEPCO, WTU and CSWS since 1994. Manager, Budgets and Accounting Systems of CPL from 1992 to 1994. Supervisor of Accounting of CPL from 1990 to 1992. Supervisor, Financial Planning of CPL from 1988 to 1990.
R. RUSSELL DAVIS . . . . . . . . . . . . . . . . . . . . AGE - 38 1994 Controller of CPL, WTU, SWEPCO and CSWS since 1994. Controller of PSO since 1993. Assistant Controller of CSW from 1992 to 1993. Assistant Controller of CSWS from 1991 to 1992. Business Improvement Project Manager of WTU in 1991. Manager of Financial Reporting of WTU from 1988 to 1991.
CPL DAVID P. SARTIN. . . . . . . . . . . . . . . . . . . . . AGE - 38 1991 Director of Planning and Analysis of CPL since 1994. Secretary of CPL since 1991. Controller and Secretary of CPL from 1991 to 1994. Controller of WTU from 1989 to 1991.
PSO BETSY J. POWERS . . . . . . . . . . . . . . . . . . . . .AGE - 59 1989 Secretary of PSO since 1989.
SWEPCO ELIZABETH D. STEPHENS . . . . . . . . . . . . . . . . . .AGE - 39 1988 Secretary of SWEPCO since 1988.
WTU MARTHA MURRAY . . . . . . . . . . . . . . . . . . . . . .AGE - 49 1992 Secretary of WTU since 1992. Previously a senior secretary at WTU.
3-8 ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION. Cash and Other Forms of Compensation
CSW Information required by ITEM 11 is hereby incorporated by reference to pages 15-19 of CSW's Proxy Statement.
CPL, PSO, SWEPCO and WTU The following table sets forth the aggregate cash and other compensation for services rendered for the fiscal years of 1994, 1993, and 1992 paid or awarded by each registrant to the CEO and each of the four most highly compensated Executive Officers, other than the CEO, whose salary and bonus exceeds $100,000, and up to two additional individuals, if any, not holding an executive officer position as of year-end but who held such a position at any time during the year, and whose compensation for the year would have placed them among the four most highly compensated executive officers.
3-12 Option/SAR Grants
Shown below is information on grants of stock options made in 1994 pursuant to the 1992 LTIP to the Named Executives Officers of each of the Electric Operating Companies. No stock appreciation rights were granted in 1994.
Option/SAR Exercises and Year-End Value Table
Shown below is information regarding option/SAR exercises during 1994 and unexercised options/SARs at December 31, 1994 for the Named Executives Officers.
Long-term Incentive Plan Awards Table
The following table shows information concerning awards made to the Named Executive Officers during 1994 under cycle III of the LTIP:
3-15 CPL, PSO, SWEPCO and WTU Payouts of the awards are contingent upon CSW achieving a specified level of total stockholder return, relative to a peer group of utility companies, for the three-year period, or cycle, and exceeding a certain defined minimum threshold. Total stockholder return is calculated by dividing (i) the sum of (a) the cumulative amount of dividends per share for the three-year period, assuming full dividend reinvestment, and (b) the change in share price over the three-year period, by (ii) the share price at the beginning of the three-year period. If the Named Executive Officer's employment is terminated during the performance period for any reason other than death, total and permanent disability or retirement, then the award is canceled. The first awards under LTIP were established in 1992 for a three-year cycle through 1994. The Executive Compensation Committee is scheduled to evaluate cycle I performance under the LTIP in March, 1995.
The LTIP contains a provision accelerating awards upon a change in control of CSW. If a change in control of CSW occurs, (i) all options and SARs become fully exercisable, (ii) all restrictions, terms and conditions applicable to all restricted stock are deemed lapsed and satisfied and all performance units are deemed to have been fully earned, as of the date of the change in control. Awards which have been granted and outstanding for less than six months as of the date of change in control are not then exercisable, vested or earned on an accelerated basis. The LTIP also contains provisions designed to prevent circumvention of the above acceleration provisions generally through coerced termination of an employee prior to the change in control of CSW.
Retirement Plan
CPL, PSO, SWEPCO and WTU PENSION PLAN TABLE Annual Benefits After Specified Years of Credited Service
Average Compensation 15 20 25 30 or more
$100,000 . . . . . .$ 25,050 $ 33,333 $ 41,667 $ 50,000 150,000 . . . . . . 37,575 50,000 62,500 75,000 200,000 . . . . . . 50,100 66,667 83,333 100,000 250,000 . . . . . . 62,625 83,333 104,167 125,000 300,000 . . . . . . 75,150 100,000 125,000 150,000 350,000 . . . . . . 87,675 116,667 145,833 175,000 450,000 . . . . . . 112,725 150,000 187,500 225,000 550,000 . . . . . . 137,775 183,333 229,167 275,000 650,000 . . . . . . 162,825 216,667 270,833 325,000 750,000 . . . . . . 187,875 250,000 312,500 375,000
Executive officers are eligible to participate in the tax- qualified CSW Pension Plan like other employees of the registrants. Certain executive officers, including the Named Executive Officers, are also eligible to participate in the SERP, a non-qualified ERISA excess benefit plan. Such pension benefits depend upon years of credited service, age at retirement and amount of covered compensation earned by a participant. The annual normal retirement benefits payable under the pension and the SERP are based on 1.67% of "Average Compensation" times the number of years of credited service, reduced by (i) no more than 50% of a participant's age 62 or later Social Security benefit and (ii) certain other offset benefits.
"Average Compensation" is the covered compensation for the plans and equals the average annual compensation, reported as salary
3-16 in the Summary Compensation Table, during the 36 consecutive months of highest pay during the 120 months prior to retirement. The combined benefit levels in the table above, which include both the pension and SERP benefits, are based on retirement at age 65, the years of credited service shown, continued existence of the plans without substantial change and payment in the form of a single life annuity.
Respective years of credited service and ages, as of December 31, 1994, for the Named Executive Officers are as follows:
Named Executive Officer Years of Credited Service Age
CPL Robert R. Carey 27 57 Melanie J. Richardson 13 38 J. Gonzalo Sandoval 21 45 C. Wayne Stice 30 57 B. W. Teague 30 56
PSO Robert L. Zemanek 22 45 William R. McKamey 24 48 Mary M. Polfer 4 50 E. Michael Williams 22 46 Waldo J. Zerger, Jr. 24 48
SWEPCO Richard H. Bremer 17 46 W. Jerry Googe, Jr. 30 52 Michael H. Madison 23 46 Marvin R. McGregor 25 48
WTU Glenn Files 23 47 Paul J. Brower 18 45 T. D. Churchwell 16 50 Dennis M. Sharkey 16 50 Donald A. Welch 30 55
Meetings and Compensation
CPL and PSO The Board of Directors held four regular meetings during 1994. Directors who are not also executive officers and employees of the CPL and PSO or their affiliates receive annual directors' fees of $6,000 for serving on the board and a fee of $300 plus expenses for each meeting of the board or committee attended.
3-17 SWEPCO The Board of Directors held four meetings during 1994. Directors who are not also executive officers and employees of SWEPCO or its affiliates receive annual directors' fees of $6,600 for serving on the board, and a fee of $300 plus expenses for each meeting of the board or committee attended.
WTU The Board of Directors held five meetings during 1994. Directors who are not also executive officers and employees of WTU or its affiliates receive annual directors' fees of $6,000 for serving on the board and a fee of $300 plus expenses for each meeting of the board or committee attended.
CPL, SWEPCO and WTU Those directors who are not also officers of CPL, SWEPCO and WTU are eligible to participate in a deferred compensation plan. Under this plan such directors may elect to defer payment of annual directors' and meeting fees until they retire from the board or as they otherwise direct.
Compensation Committee Interlocks and Insider Participation
CPL, PSO, SWEPCO and WTU No person serving during 1994 as a member of the Executive Compensation Committee of the Board of Directors of CSW served as an officer or employee of each registrant during or prior to 1994. No person serving during 1994 as an executive officer of the Electric Operating Companies serves or has served on the compensation committee or as a director of another company whose executive officers serve or has served as a member of the Executive Compensation Committee of CSW or as a director of one of the Electric Operating Companies.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
CSW The information required by ITEM 12 is hereby incorporated by reference to page 5-6 of CSW's Proxy Statement.
CPL, PSO, SWEPCO and WTU All outstanding Common Stock shares are owned beneficially and of record by CSW, 1616 Woodall Rodgers Freeway, Dallas, Texas 75202.
Company Shares Par Value
CPL 6,755,535 $25 par value PSO 9,013,000 $15 par value SWEPCO 7,536,640 $18 par value WTU 5,488,560 $25 par value
3-18 Security Ownership of Management The following table shows securities beneficially owned as of December 31, 1994, by each director, the CEO and the four other most highly compensated executive officers and, as a group, all directors and executive officers of each registrant. Share amounts shown in this table include options exercisable within 60 days after year- end, restricted stock, shares of CSW Common credited to CSW Thrift Plus accounts and all other shares of CSW Common beneficially owned by the listed persons. Each person has sole voting and investment power with respect to all shares listed in the table below, excluding the shares underlying the unexercised options.
CPL Beneficial Ownership as of December 31, 1994 Name CSW Common Stock Preferred Stock (1)(2) (2)
E. R. Brooks 81,940 Robert R. Carey 24,260 Ruben M. Garcia -- David L. Hooper 1,775 Harry D. Mattison 33,111 Robert A. McAllen 3,500 Pete Morales, Jr. -- S. Loyd Neal, Jr. 2,950 Jim L. Peterson -- H. Lee Richards 1,700 Melanie J. Richardson 1,356 J. Gonzalo Sandoval 11,328 C. Wayne Stice 5,568 B. W. Teague 3,371 Gerald E. Vaughn 151 All of the above and other executive officers as a group 175,673
(1)Shares for Messrs., Brooks, Carey, Mattison, Sandoval and CPL directors and executives as a group, include 4,760, 2,851, 3,236, 211 and 11,058 shares of restricted stock, respectively. These individuals currently have voting power, but not investment power, with respect to these shares. The above shares also include 870, 19,062, 9,786, 12,352, 1,942, 1,530, 1,045 and 49,535 shares underlying immediately exercisable options held by Ms. Richardson and Messrs. Brooks, Carey, Mattison, Sandoval, Stice, Teague and CPL directors and executives as a group, respectively.
(2)Percentages are all less than one percent and therefore are omitted.
3-19 PSO Beneficial Ownership as of December 31, 1994 Name CSW Common Stock Preferred Stock (1)(2) (2)
E. R. Brooks 81,940 Harry A. Clarke -- Paul K. Lackey, Jr. -- Paula Marshall-Chapman -- Harry D. Mattison 33,111 William R. McKamey 8,176 Mary M. Polfer 3,378 Jack E. Raulston -- Dr. Robert B. Taylor, Jr. -- Robert L. Zemanek 10,920 Waldo J. Zerger, Jr. 9,635 E. Michael Williams 254 All of the above and other executive officers as a group 154,146
(1)Shares for Ms. Polfer and Messrs. Brooks, Mattison, Williams, Zemanek, Zerger and PSO directors and executives as a group, include 439, 4,760, 3,236, 254, 1,094, 478 and 10,261 shares of restricted stock, respectively. These individuals currently have voting power, but not investment power, with respect to these shares. The above shares also include 1,942, 19,062, 12,352, 1,322, 7,092, 2,090 and 45,732 shares underlying immediately exercisable options held by Ms. Polfer and Messrs. Brooks, Mattison, McKamey, Zemanek, Zerger, and PSO directors and executives as a group, respectively.
(2)Percentages are all less than one percent and therefore are omitted.
3-20 SWEPCO Beneficial Ownership as of December 31, 1994 Name CSW Common Stock Preferred Stock (1)(2) (2)
Richard H. Bremer 28,578 E. R. Brooks 81,940 James E. Davison -- Al P. Eason, Jr. 2,000 W. J. Googe, Jr. 6,558 Dr. Frederick E. Joyce 2,000 Michael H. Madison 4,241 Harry D. Mattison 33,111 Marvin R. McGregor 3,892 William C. Peatross -- Jack L. Phillips -- All of the above and other executive officers as a group 166,116
(1)Shares for Messrs. Bremer, Brooks, Googe, Madison, Mattison, McGregor and SWEPCO directors and executives as a group, include 2,609, 4,760, 539, 484, 3,236, 518 and 12,146 shares of restricted stock, respectively. These individuals currently have voting power, but not investment power, with respect to these shares. The above shares also include 8,286, 19,062, 1,942, 2,090, 12,352, 2,090 and 47,011 shares underlying immediately exercisable options held by Messrs. Bremer, Brooks, Googe, Madison, Mattison, McGregor, and SWEPCO directors and executives as a group, respectively.
(2)Percentages are all less than one percent and therefore are omitted.
WTU Beneficial Ownership as of December 31, 1994 Name CSW Common Stock Preferred Stock (1)(2) (2)
Richard F. Bacon 2,643 C. Harwell Barber 12,292 E. R. Brooks 81,940 Paul J. Brower 3,698 T. D. Churchwell 3,131 Glenn Files 9,164 Harry D. Mattison 33,111 Tommy Morris 2,000 Dian G. Owen 50 James M. Parker 6,700 Dennis M. Sharkey 16,205 F. L. Stephens 1,596 Donald A. Welch 7,920 All of the above and other executive officers as a group. 184,360
(1)Shares for Messrs. Brooks, Brower, Churchwell, Files, Mattison, Sharkey, Welch and WTU directors and executives as a group, include 4,760, 330, 424, 1,071, 3,236, 662, 515 and 10,998 shares of restricted stock, respectively. These individuals currently have voting power, but not investment power, with respect to these shares. The above shares also include 19,062, 2,090, 2,090, 6,596, 12,352, 8,342, 2,090 and 53,558 shares underlying immediately exercisable options held by Messrs. Brooks, Brower, Churchwell, Files, Mattison, Sharkey, Welch and WTU directors and executives as a group, respectively.
(2)Percentages are all less than one percent and therefore are omitted.
3-22 ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. CSW The information required by ITEM 13 is hereby incorporated by reference to pages 6-9 of CSW's Proxy Statement.
CPL, PSO, SWEPCO and WTU None.
4-1 PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report on this Form 10-K.
(1) Financial Statements: Reports of Independent Public Accountants on the financial statements for CSW and subsidiary companies, CPL, PSO, SWEPCO and WTU are listed under Item 8 herein.
The financial statements filed as a part of this report for CSW and subsidiary companies, CPL, PSO, SWEPCO and WTU are listed under Item 8 herein.
(2) Financial Statement Schedules: Report of Independent Public Accountants as to Schedules for CSW, CPL, PSO, SWEPCO and WTU are included in the Report of Independent Public Accountants for each registrant.
Financial Statement Schedules for CSW, CPL, PSO, SWEPCO and WTU are listed in the Index to the Financial Statement Schedules at page 4-15.
(3) Exhibits Exhibits for CSW, CPL, PSO, SWEPCO and WTU are listed in the Exhibit Index at page 4-21.
(b) Reports on Form 8-K: CSW and CPL CSW and CPL filed a Current Report on Form 8-K dated October 31, 1994, reporting ITEM 5. "Other Events" relating to the CPL rate case.
PSO and SWEPCO No reports were filed on Form 8-K during the quarter ended December 31, 1994.
WTU WTU filed a Current Report on Form 8-K dated February 17, 1995 providing unaudited 1994 financial data associated with a debt financing.
(c) Management Contracts, Compensatory Plans or Arrangements: The management contracts, compensatory plans or arrangements required to be filed as exhibits to this Form 10-K are listed in 10(a)1-10(a)6 in item (d) Exhibits below.
4-2 CSW SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 20, 1995. The signature of the undersigned registrant shall be deemed to relate only to matters having reference to such registrant and any subsidiaries thereof.
CENTRAL AND SOUTH WEST CORPORATION
By: Wendy G. Hargus Controller
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 20, 1995. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above named registrant and any subsidiaries thereof.
Signature Title
E. R. Brooks President and CEO and Director (Principal Executive Officer)
Glenn D. Rosilier Chief Financial Officer (Principal Financial Officer)
Wendy G. Hargus Controller (Principal Accounting Officer)
*T. J. Barlow Director *Glenn Biggs Director *Molly Shi Boren Director *Donald M. Carlton Director *Joe H. Foy Director *Robert Lawless Director *Harry D. Mattison Executive Vice President and Director *James L. Powell Director *Arthur E. Rasmussen Director *T. V. Shockley, III Executive Vice President and Director *J. C. Templeton Director *Lloyd D. Ward Director
*Wendy G. Hargus, by signing her name hereto, does sign this document on behalf of the persons indicated above pursuant to a power of attorney duly executed by each such person.
*By: Wendy G. Hargus Attorney-in-Fact 4-3 CPL SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 20, 1995. The signature of the undersigned registrant shall be deemed to relate only to matters having reference to such registrant.
CENTRAL POWER AND LIGHT COMPANY
By: R. Russell Davis Controller
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 20, 1995. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above named registrant.
Signature Title
Robert R. Carey President and CEO and Director (Principal Executive Officer)
R. Russell Davis Controller (Principal Accounting and Financial Officer)
*E. R. Brooks Director *Ruben M. Garcia Director *David L. Hooper Director *Harry D. Mattison Director *Robert A. McAllen Director *Pete Morales, Jr. Director *S. Loyd Neal, Jr. Director *Jim L. Peterson Director *H. Lee Richards Director *Melanie J. Richardson Director *J. Gonzalo Sandoval Director *Gerald E. Vaughn Director
*R. Russell Davis, by signing his name hereto, does sign this document on behalf of the persons indicated above pursuant to a power of attorney duly executed by each such person.
*By: R. Russell Davis Attorney-in-Fact 4-4 PSO SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 20, 1995. The signature of the undersigned registrant shall be deemed to relate only to matters having reference to such registrant.
PUBLIC SERVICE COMPANY OF OKLAHOMA
By: R. Russell Davis Controller
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 20, 1995. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above named registrant.
Signature Title
Robert L. Zemanek President and CEO and Director (Principal Executive Officer)
R. Russell Davis Controller (Principal Accounting and Financial Officer)
*E. R. Brooks Director *Harry A. Clark Director *Paul K. Lackey, Jr. Director *Paula Marshall-Chapman Director *Harry D. Mattison Director *William R. McKamey Director *Mary M. Polfer Director *Dr. Robert B. Taylor, Jr. Director *Waldo J. Zerger, Jr. Director
*R. Russell Davis, by signing his name hereto, does sign this document on behalf of the persons indicated above pursuant to a power of attorney duly executed by each such person.
*By: R. Russell Davis Attorney-in-Fact
4-5 SWEPCO SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 20, 1995. The signature of the undersigned registrant shall be deemed to relate only to matters having reference to such registrant.
SOUTHWESTERN ELECTRIC POWER COMPANY
By: R. Russell Davis Controller
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 20, 1995. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above named registrant.
Signature Title
Richard H. Bremer President and CEO and Director (Principal Executive Officer)
R. Russell Davis Controller (Principal Accounting and Financial Officer)
*E. R. Brooks Director *James E. Davison Director *Al P. Eason, Jr.. Director *W. J. Googe, Jr. Director *Dr. Frederick E. Joyce Director *Michael H. Madison Director *Harry D. Mattison Director *Marvin R. McGregor Director *William C. Peatross Director *Jack L. Phillips Director
*R. Russell Davis, by signing his name hereto, does sign this document on behalf of the persons indicated above pursuant to a power of attorney duly executed by each such person.
*By: R. Russell Davis Attorney-in-Fact
4-6 WTU SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 20, 1995. The signature of the undersigned registrant shall be deemed to relate only to matters having reference to such registrant.
WEST TEXAS UTILITIES COMPANY
By: R. Russell Davis Controller
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 20, 1995. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above named registrant.
Signature Title
Glenn Files President and CEO and Director (Principal Executive Officer)
R. Russell Davis Controller (Principal Accounting and Financial Officer)
*Richard Bacon Director *C. Harwell Barber Director *E. R. Brooks Director *Paul J. Brower Director *T. D. Churchwell Director *Harry D. Mattison Director *Tommy Morris Director *Dian G. Owen Director *James M. Parker Director *F. L. Stephens Director *Dennis M. Sharkey Director *Donald A. Welch Director
*R. Russell Davis, by signing his name hereto, does sign this document on behalf of the persons indicated above pursuant to a power of attorney duly executed by each such person.
*By: R. Russell Davis Attorney-in-Fact 4-7 INDEX TO FINANCIAL STATEMENT SCHEDULES Paper Copy Schedule Page
II. Valuation and Qualifying Accounts. Central and South West Corporation 4-16 Central Power and Light Company 4-17 Public Service Company of Oklahoma 4-18 Southwestern Electric Power Company 4-19 West Texas Utilities Company 4-20
CSW, CPL, PSO, SWEPCO and WTU All other exhibits and schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or related notes to financial statements.
4-8 CENTRAL AND SOUTH WEST CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COL. A COL. B COL. C COL. D COL. E Additions Balance at Charged to Charged Balance Beginning Costs and to Other at End Description of Year Expenses Accounts (b) Deductions (c) of Year (millions) Accrued Restructuring Charges $97 $ (9) (a) $(27) $57 $ 4
Accrued Restructuring Charges $-- $ 97 $ -- $-- $ 97
(a) Reflects true-up to revised estimate of restructuring charges. (b) Effects of early retirement related to SFAS No. 87 Employers' Accounting for Pensions and SFAS No. 112 Employers' Accounting for Postemployment Benefits follow:
(millions) SFAS No. 87 $(31) SFAS No. 112 4 Total $(27)
(c) Payments of accrued restructuring charges.
4-9 CENTRAL POWER AND LIGHT COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COL. A COL. B COL. C COL. D COL. E Additions Balance at Charged to Charged Balance Beginning Costs and to Other at End Description of Year Expenses Accounts(b) Deductions(c) of Year (thousands) Accrued Restructuring Charges $29,365 $ 98 (a) $(7,893) $20,245 $ 1,325
Accrued Restructuring Charges $ -- $29,365 $ -- $ -- $29,365
(a) Reflects true-up to revised estimate of restructuring charges. (b) Effects of early retirement related to SFAS No. 87 Employers' Accounting for Pensions and SFAS No. 112 Employers' Accounting for Postemployment Benefits follow:
(thousands) SFAS No. 87 $(9,099) SFAS No. 112 1,206 Total $(7,893)
(c) Payments of accrued restructuring charges.
4-10 PUBLIC SERVICE COMPANY OF OKLAHOMA
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COL. A COL. B COL. C COL. D COL. E Additions Balance at Charged to Charged Balance Beginning Costs and to Other at End Description of Year Expenses Accounts(b) Deductions(c) of Year (thousands) Accrued Restructuring Charges $24,995 $ (197) (a) $(8,126) $15,626 $ 1,046
Accrued Restructuring Charges $ -- $24,995 $ -- $ -- $24,995
(a) Reflects true-up to revised estimate of restructuring charges. (b) Effects of early retirement related to SFAS No. 87 Employers' Accounting for Pensions and SFAS No. 112 Employers' Accounting for Postemployment Benefits follow:
(thousands) SFAS No. 87 $(9,880) SFAS No. 112 1,754 Total $(8,126)
(c) Payments of accrued restructuring charges.
4-11 SOUTHWESTERN ELECTRIC POWER COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COL. A COL. B COL. C COL. D COL. E Additions Balance at Charged to Charged Balance Beginning Costs and to Other at End Description of Year Expenses Accounts(b) Deductions(c) of Year (thousands) Accrued Restructuring Charges $25,203 $ (4,978)(a) $(7,421) $11,694 $ 1,110
Accrued Restructuring Charges $ -- $ 25,203 $ -- $ -- $25,203
(a) Reflects true-up to revised estimate of restructuring charges. (b) Effects of early retirement related to SFAS No. 87 Employers' Accounting for Pensions and SFAS No. 112 Employers' Accounting for Postemployment Benefits follow:
(thousands) SFAS No. 87 $(8,016) SFAS No. 112 595 Total $(7,421)
(c) Payments of accrued restructuring charges.
4-12 WEST TEXAS UTILITIES COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COL. A COL. B COL. C COL. D COL. E Additions Balance at Charged to Charged Balance Beginning Costs and to Other at End Description of Year Expenses Accounts(b) Deductions(c) of Year (thousands) Accrued Restructuring Charges $15,250 $ (2,037)(a) $(3,724) $8,918 $ 571
Accrued Restructuring Charges $ -- $ 15,250 $ -- $ -- $15,250
(a) Reflects true-up to revised estimate of restructuring charges. (b) Effects of early retirement related to SFAS No. 87 Employers' Accounting for Pensions and SFAS No. 112 Employers' Accounting for Postemployment Benefits follow:
(thousands) SFAS No. 87 $(3,992) SFAS No. 112 268 Total $(3,724)
(c) Payments of accrued restructuring charges.
4-13 (d) Exhibit Index: The following exhibits indicated by an asterisk (*) preceding the exhibit number are filed herewith. The balance of the exhibits have heretofore been filed with the SEC, respectively, as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a plus (+) are management contracts or compensatory plans or arrangements required to be filed herewith and required to be identified as such by ITEM 14. of Form 10-K. Reference is made to a duplicate list of exhibits being filed as a part of this Form 10-K, which list, prepared in accordance with Item 102 of Regulation S-T of the SEC, immediately precedes the exhibits being physically filed with this Form 10-K.
(2) Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
CSW (a) 1 Agreement and Plan of Merger Among El Paso Electric Company, Central and South West Corporation and CSW Sub, Inc. Dated as of May 3, 1993 as Amended May 18, 1993 (incorporated herein by reference to Exhibit 2.1 to CSW's Form 8-K dated December 29, 1993, File No. 1-1443).
(a) 2 Second Amendment Dated as of August 26, 1993 to Agreement and Plan of Merger Among El Paso Electric Company, Central and South West Corporation and CSW Sub, Inc. Dated as of May 3, 1993 as amended on May 18, 1993 (incorporated herein by reference to Exhibit 2.2 to CSW's Form 8-K dated December 29, 1993, File No. 1-1443).
(a) 3 Third Amendment Dated as of December 1, 1993 to Agreement and Plan of Merger Among El Paso Electric Company, Central and South West Corporation and CSW Sub, Inc. Dated as of May 3, 1993 as amended on May 18, 1993 and August 26, 1993 (incorporated herein by reference to Exhibit 2.3 to CSW's Form 8-K dated December 29, 1993, File No. 1-1443).
(a) 4 Modified Third Amended Plan of Reorganization of El Paso Electric Company Providing for the Acquisition of El Paso Electric Company by Central and South West Corporation as corrected December 6, 1993, and confirmed by the Bankruptcy Court (incorporated herein by reference to Exhibit 2.4 to CSW's Form 8-K dated December 29, 1993, File No. 1-1443).
(a) 5 Order and Judgement Confirming El Paso Electric Company's Third Amended Plan of Reorganization, as Modified, Under Chapter 11 of the United States Bankruptcy Code and Granting Related Relief (incorporated herein by reference to Exhibit 2.5 to CSW's Form 8-K dated December 29, 1993, File No. 1-1443).
(3) Articles of Incorporation and By-laws
CSW (a) 1 Second Restated Certificate of Incorporation of CSW, as amended (incorporated herein by reference to Exhibit 3 (a) to CSW's 1990 Form 10-K, File No. 1-1443).
(a) 2 Bylaws of CSW, as amended (incorporated herein by reference to Exhibit 3 (b) to CSW's 1990 Form 10-K, File No. 1-1443).
4-14 (d) Exhibit Index: (3) Articles of Incorporation and By-laws (continued)
CPL (b) 1 Restated Articles of Incorporation, as amended, of CPL (incorporated herein by reference to Exhibit 4(a) to CPL's Registration Statement No. 33-4897, Exhibits 5 and 7 to Form U-1, File No. 70-7171, Exhibits 5, 8.1, 8.2 and 19 to Form U-1, File No. 70-7472 and CPL's Form 10-Q for the quarterly period ended September 30, 1992, ITEM 6, Exhibit 1).
* (b) 2 Bylaws of CPL, as amended.
PSO (c) 1 Restated Certificate of Incorporation of PSO (incorporated herein by reference to Exhibit 3 to PSO's 1987 Form 10-K, File No. 0-343).
* (c) 2 Bylaws of PSO, as amended.
SWEPCO (d) 1 Restated Certificate of Incorporation, as amended, of SWEPCO (incorporated herein by reference to Exhibit 3 to SWEPCO's 1980 Form 10-K, File No. 1-3146, Exhibit 2 to Form U-1 File No. 70-6819, Exhibit 3 to Form U-1, File No. 70- 6924 and Exhibit 4 to Form U-1 File No. 70-7360).
* (d) 2 Bylaws of SWEPCO, as amended.
WTU * (e) 1 Restated Articles of Incorporation, as amended, of WTU.
* (e) 2 Bylaws of WTU, as amended.
(4) Instruments Defining the Rights of Security Holder, Including Indentures
CPL (a) 1 Indenture of Mortgage or Deed of Trust dated November 1, 1943, executed by CPL to The First National Bank of Chicago and Robert L. Grinnell, as Trustee, as amended through October 1, 1977 (incorporated herein by reference to Exhibit 5.01 in File No. 2-60712), and the Supplemental Indentures of CPL dated September 1, 1978 (incorporated herein by reference to Exhibit 2.02 in File No. 2-62271) and December 15, 1984, July 1, 1985, May 1, 1986 and November 1, 1987 (incorporated herein by reference to Exhibit 17 to Form U-1, File No. 70-7003, Exhibit 4 (b) in File No. 2-98944, Exhibit 4 to Form U-1, File No. 70-7236 and Exhibit 4 to Form U-1, File No. 70-7249) and June 1, 1988, December 1, 1989, March 1, 1990, October 1, 1992, December 1, 1992, February 1, 1993, April 1, 1993 and May 1, 1994 (incorporated herein by reference to Exhibit 2 to Form U-1, File No. 70-7520, Exhibit 3 to Form U-1, File No. 70-7721, Exhibit 10 to Form U-1, File No. 70-7725 and Exhibit 10 (a), 10 (b), 10 (c), 10 (d) and 10(e), respectively, to Form U-1, File No. 70-8053).
4-15 (d) Exhibit Index: (4) Instruments Defining the Rights of Security Holder, Including Indentures (continued) PSO (b) 1 Indenture dated July 1, 1945, as amended, of PSO (incorporated herein by reference to Exhibit 5.03 in Registration No. 2-60712) and the Supplemental Indenture of PSO dated June 1, 1979 (incorporated herein by reference to Exhibit 2.02 in Registration No. 2-64432), the Supplemental Indenture of PSO dated December 1, 1979 (incorporated herein by reference to Exhibit 2.02 in Registration No. 2-65871), the Supplemental Indenture of PSO dated March 1, 1983 (incorporated herein by reference to Exhibit 2 to Form U-1, File No. 70-6822), the Supplemental Indenture of PSO dated May 1, 1986 (incorporated herein by reference to Exhibit 3 to Form U-1, File No. 70-7234), the Supplemental Indenture of PSO dated July 1, 1992 (incorporated herein by reference to Exhibit 4 (b) to Form S-3, File No. 33-48650), the Supplemental Indenture of PSO dated December 1, 1992 (incorporated herein by reference to to Exhibit 4 (c) to Form S-3, File No. 33-49143), the Supplemental Indenture of PSO dated April 1, 1993 (incorporated herein by reference to Exhibit 4 (b) to Form S-3, File No. 33-49575), and Supplemental Indenture of PSO dated June 1, 1993 (incorporated herein by reference to Exhibit 4 (b) to PSO's 1993 Form 10-K, File No. 0-343). SWEPCO (c) 1 Indenture dated February 1, 1940, as amended through November 1, 1976, of SWEPCO (incorporated herein by reference to Exhibit 5.04 in Registration No. 2-60712), the Supplemental Indenture dated August 1, 1978 incorporated herein by reference to Exhibit 2.02 in Registration No. 2-61943), the Supplemental Indenture dated January 1, 1980 (incorporated herein by reference to Exhibit 2.02 in Registration No. 2-66033), the Supplemental Indenture dated April 1, 1981 (incorporated herein by reference to Exhibit 2.02 in Registration No. 2- 71126), the Supplemental Indenture dated May 1, 1982 (incorporated herein by reference to Exhibit 2.02 in Registration No. 2-77165), the Supplemental Indenture dated August 1, 1985 (incorporated herein by reference to Exhibit 4 to Form U-1, File No. 70-7121), the Supplemental Indenture dated May 1, 1986 (incorporated herein by reference to Exhibit 3 to Form U-1 File No. 70-7233), the Supplemental Indenture dated November 1, 1989 (incorporated herein by reference to Exhibit 3 to Form U-1, File No. 70- 7676), the Supplemental Indenture dated June 1, 1992 (incorporated herein by reference to Exhibit 10 to Form U- 1, File No. 70-7934), the Supplemental Indenture dated September 1, 1992 (incorporated herein by reference to Exhibit 10 (b) to Form U-1, File No.72-8041), the Supplemental Indenture dated July 1, 1993 (incorporated herein by reference to Exhibit 10 (c) to Form U-1, File No. 70-8041) and the Supplemental Indenture dated October 1, 1993 (incorporated herein by reference to Exhibit 10 (a) to Form U-1, File No. 70-8239). WTU (d) 1 Indenture dated August 1, 1943, as amended through July 1, 1973 (incorporated herein by reference to Exhibit 5.05 in File No. 2-60712), Supplemental Indenture dated May 1, 1979 (incorporated herein by reference to Exhibit No. 2.02 in File No. 2- 63931), Supplemental Indenture dated November 15, 1981 (incorporated herein by reference to Exhibit No. 4.02 in File No. 2-74408), Supplemental Indenture dated Nobember 1, 1983 (incorporated herein by reference to Exhibit 12 to Form U-1, File No. 70-6820), Supplemental Indenture dated April 15, 1985 (incorporated herein by reference to Amended Exhibit 13 to Form U-1, File No. 70-6925), Supplemental Indenture dated August 1, 1985 (incorporated herein by reference to Exhibit 4 (b) in File No. 2-98843), Supplemental Indenture dated May 1, 1986 (incorporated herein by reference to Exhibit 4 to Form U-1, File No. 70- 7237), Supplemental Indenture dated December 1, 1989 (incorporated herein by reference to Exhibit 3 to Form U-1, in File No. 70-7719), Supplemental Indenture dated June 1, 1992 (incorporated herein by reference to Exhibit 10 to Form U-1, File No. 70-7936), Supplemental Indenture dated October 1, 1992 (incorporated herein by reference to Exhibit 10 to Form U-1, File No. 70-8057), Supplemental Indenture dated February 1, 1994 (incorporated herein by reference to Exhibit 10-Form U-1, File No. 70-8265) and Supplemental Indenture dated March 1, 1995 (incorporated herein by reference to Exhibit 10(b) to Form U-1, File No. 70-8057).
4-16 (d) Exhibit Index: (10) Material Contracts
CSW + (a) 1 Restricted Stock Plan for Central and South West Corporation (incorporated herein by reference to Exhibit 10(a) to CSW's 1990 Form 10-K, File No. 1-1443).
+ (a) 2 Central and South West System Special Executive Retirement Plan (incorporated herein by reference to Exhibit 10(b) to CSW's 1990 Form 10-K, File No. 1-1443).
+ (a) 3 Executive Incentive Compensation Plan for Central and South West System (incorporated herein by reference to Exhibit 10(c) to the Corporation's 1990 Form 10-K, File No. 1-1443).
(a) 4 Central and South West Corporation Stock Option Plan (incorporated herein by reference to Exhibit 10(d) to the Corporation's 1990 Form 10-K, File No. 1-1443).
(a) 5 Central and South West Corporation Deferred Compensation Plan for Directors (incorporated herein by reference to Exhibit 10(e) to the Corporation's 1990 Form 10-K, File No. 1-1443).
+ (a) 6 Central and South West Corporation 1992 Long-Term Incentive Plan (incorporated herein by reference to Appendix A to the Central and South West Corporation Notice of 1992 Annual Meeting of Shareholders and Proxy Statement).
(12) Statements Re Computation of Ratios
CPL * (a) 1 Statement re computation of Ratio of Earnings to Fixed Charges for the five years ended December 31, 1994.
PSO * (b) 1 Statement re computation of Ratio of Earnings to Fixed Charges for the five years ended December 31, 1994.
SWEPCO * (c) 1 Statement re computation of Ratio of Earnings to Fixed Charges for the five years ended December 31, 1994.
WTU * (d) 1 Statement re computation of Ratio of Earnings to Fixed Charges for the five years ended December 31, 1994.
(21) Subsidiaries of the registrant
CSW * (a) 1 Subsidiaries of the registrant.
(23) Consent of Experts and Counsel
CSW * (a) 1 Consent of Independent Public Accountants.
4-17 (d) Exhibit Index: (23) Consent of Experts and Counsel (continued)
CPL * (b) 1 Consent of Independent Public Accountants.
WTU * (c) 1 Consent of Independent Public Accountants.
(24) Power of Attorney
* CSW (a) 1 Power of Attorney. (a) 2 Power of Attorney. (a) 3 Power of Attorney. (a) 4 Power of Attorney.
* CPL (b) 1 Power of Attorney. (b) 2 Power of Attorney. (b) 3 Power of Attorney.
* PSO (c) 1 Power of Attorney. (c) 2 Power of Attorney. (c) 3 Power of Attorney.
* SWEPCO (d) 1 Power of Attorney. (d) 2 Power of Attorney. (d) 3 Power of Attorney.
* WTU (e) 1 Power of Attorney. (e) 2 Power of Attorney. (e) 3 Power of Attorney.