-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, sZEuKf9rVzAJQ4hbmkzZjKJfA9tlEirotSsqaW0Tyk63Oe5lwlI/rYPgOs8IcKfA CdoLG3v8Em0e0ipc2HmwoA== 0000741612-94-000009.txt : 19940325 0000741612-94-000009.hdr.sgml : 19940325 ACCESSION NUMBER: 0000741612-94-000009 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940324 FILER: COMPANY DATA: COMPANY CONFORMED NAME: TNP ENTERPRISES INC CENTRAL INDEX KEY: 0000741612 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 751907501 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-08847 FILM NUMBER: 94517601 BUSINESS ADDRESS: STREET 1: 4100 INTERNATIONAL PLZ STREET 2: PO BOX 2943 CITY: FORT WORTH STATE: TX ZIP: 76113 BUSINESS PHONE: 8177310099 10-K 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-K (X)ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1993 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission File No. 1-8847 TNP ENTERPRISES, INC. (Exact name of registrant as specified in its charter) TEXAS 75-1907501 (State of incorporation) (I.R.S. Employer Identification Number) 4100 International P. O. Box 2943 Fort Worth, Texas 76113 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code 817-731-0099 Securities registered pursuant to Section 12(b) of the Act: Shares Name of Outstanding Each Exchange on Title of Each Class of Securities on January 31, 1994 Which Registered Common Stock, No Par Value 10,697,996 New York Stock Exchange Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments to this Form 10-K. [X] As of January 31, 1994 non-affiliates of the Registrant held 10,623,257 shares of the Common Stock having an aggregate market value of $189,890,718.88 based on the closing price on the New York Stock Exchange of $17.875 per share. Documents Incorporated By Reference Part Where Document Incorporated (1) Annual Report to Shareholders for the year ended December 31, 1993 I, II (2) Proxy Statement (distributed to holders of common stock on or about March 28, 1994 III TNP ENTERPRISES, INC. FORM 10-K PART I Item 1. Business. General Development of Business The Company And Its Subsidiaries TNP Enterprises, Inc. (Company) is a Texas corporation organized in February 1983. The Company owns all of the outstanding common stock of its three subsidiaries: Texas-New Mexico Power Company (Utility), its principal operating subsidiary; Bayport Cogeneration, Inc. (Bayport); and TNP Operating Company. The Company and the Utility are holding companies as defined in the Public Utility Holding Company Act but each is exempt from regulation as a "registered holding company" as defined in said act. All financial information presented herein or incorporated by reference is on a consolidated basis and all intercompany transactions and balances have been eliminated. Texas-New Mexico Power Company Texas-New Mexico Power Company is a public utility engaged in the generation, purchase, transmission, distribution and sale of electricity to customers within the States of Texas and New Mexico. The Utility is qualified to do business as a foreign corporation in the State of Arizona. Business conducted in Arizona is limited to ownership as tenant-in-common with two other electric utility corporations in a 345-KV electric transmission line which transmits electrical energy into New Mexico for sale to customers in New Mexico. The Utility is subject to regulation by the Public Utility Commission of Texas (PUCT) and the New Mexico Public Utility Commission (NMPUC). The Utility is subject in some of its activities, including the issuance of securities, to the jurisdiction of the Federal Energy Regulatory Commission (FERC), and its accounting records are maintained in accordance with the FERC Uniform System of Accounts. The Utility has two wholly owned subsidiaries, Texas Generating Company (TGC), organized in 1988, and Texas Generating Company II (TGC II), organized in 1991. TNP One Prior to 1990, the Utility purchased virtually all of its electric requirements, primarily from other utilities. In an effort to diversify its energy and fuel sources, the Utility contracted with a consortium consisting of Westinghouse Electric Corporation, Combustion Engineering, Inc. and H. B. Zachry Company to construct TNP One. TNP One is a two-unit lignite-fueled, circulating fluidized bed generating plant in Robertson County, Texas. Unit 1 and Unit 2 of TNP One together provide, on an annualized basis, approximately 30% of the Utility's electric capacity requirements in Texas. The Utility acquired Unit 1 on July 20, 1990, and Unit 2 on July 26, 1991, through TGC and TGC II, respectively. The Utility operates the two units and sells the output of TNP One to its Texas customers. Unit 1 began commercial operation on September 12, 1990, and Unit 2 on October 16, 1991. As of December 31, 1993, the costs of Unit 1 and Unit 2 were approximately $357 million and approximately $282.9 million, respectively. Portions of the costs were funded by the Utility, with the majority of the costs borrowed by TGC and TGC II under separate financing facilities for the two units, which are guaranteed by the Utility. TNP ENTERPRISES, INC. FORM 10-K Regulatory Proceedings The Utility has received rate orders from the PUCT placing the majority of the costs of each of the two units of TNP One in rate base. The Utility and other parties to the proceedings have appealed both orders. For a review of the history of the two rate proceedings and the pending judicial proceedings, see Item 3, "Legal Proceedings" and note 5 to the consolidated financial statements contained in the Annual Report to Shareholders for the year ended December 31, 1993. See note 2 to the consolidated financial statements contained in the Annual Report to Shareholders for the year ended December 31, 1993 for a discussion of the financings of the two units including, during 1993, substantial reduction of the TNP One construction indebtedness and extension of the payment schedule for the remaining balance of the construction debt. For a discussion of the effects of the construction and financing of TNP One on the Utility's financial condition, including the detrimental regulatory treatment received to date, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in the Annual Report to Shareholders for the year ended December 31, 1993. Business of Other Subsidiaries TNP Operating Company and Bayport are general purpose corporations organized under the Texas Business Corporation Act. Neither company was materially involved in any business activities during 1993. Financial Information About Industry Segments This information is incorporated by reference to page 37 of the Annual Report to Shareholders for the year ended December 31, 1993. It is not possible to attribute operating profit or loss and identifiable assets to each of the classes of customers listed on the page referred to in said Annual Report. Kilowatt-hour (KWH) sales in 1993 were assisted by more typical weather experienced in 1993 as compared to 1992. KWH sales declined in 1992 from 1991 due in part to milder than normal temperatures in the Utility's service area in Texas; however, revenues were approximately the same for the two years due primarily to an increase in the Utility's Texas customers' rates in 1992. Also contributing to the sales decline was the failure of new customers and revenues to materialize as expected within the industrial class to ameliorate the loss of KWH sales to certain industrial customers. During 1993, the number of industrial customers decreased by 14, but that decrease included the consolidation of 10 customers into 2 customers for billing purposes and the reclassification of 3 customers to the commercial class of customers. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in the Annual Report to Shareholders for the year ended December 31, 1993 for a discussion of the changes in operating revenues, including rate increases. Narrative Description of Business The Company is a holding company as defined in the Public Utility Holding Company Act of 1935, but is exempt from regulation as a "registered holding company" under the act except with respect to the acquisition of securities of other public utility companies. The Company's exemption is based upon the substantially intrastate character of the operations of the Utility, and the filing with the Securities and Exchange Commission (SEC) of an annual exemption statement pursuant to its Rule U-2. The Public Utility Holding Company Act authorizes the SEC to terminate an exemption which it determines to be detrimental to the public interest or to the interest of investors or consumers. Therefore, the extent to which the Company and its nonutility subsidiaries may expand or diversify and maintain the Company's exempt status is always subject to review by the SEC. The Company does not intend to take any action which will jeopardize its exempt status. TNP ENTERPRISES, INC. FORM 10-K The Company is not subject to regulation by the PUCT. The Company is not generally subject to regulation by the NMPSC; the NMPSC statutes do not regulate holding companies except under certain circumstances of consolidation, merger, or acquisition. Both of these agencies have regulatory authority under state laws over the activities of the Utility. The Utility, and not the Company, is also subject to the jurisdiction of the FERC, in certain respects, under the terms of the Federal Power Act. Narrative Description of Utility Business General The Utility purchases and generates electricity for sales to its customers wholly within the States of Texas and New Mexico. The Utility's purchases of electricity are primarily from other utilities and cogenerators (see "Sources of Energy" in this section). The Utility's current generation of electricity is from TNP One. The Utility owns and operates electric transmission and distribution facilities in 90 municipalities and adjacent rural areas in Texas and New Mexico. The areas served contain a population of approximately 616,000. The Utility's service is delivered to customers in four operating divisions in Texas and one operating division in New Mexico. The Utility's Southeast Division, on the Texas Gulf Coast, is adjacent to the Johnson Space Center and lies between the cities of Houston and Galveston. The economy is supported by the oil and petrochemical industries, agriculture and the general commercial activity of the Houston area. This division produced 49.5% of the total operating revenues in 1993. The Utility's Northern Division is based in Lewisville, just north of the Dallas-Fort Worth International Airport, and extends to include municipalities along the Red River and in the Texas Panhandle. This division serves a variety of commercial, agricultural and petroleum industry customers and produced 19.5% of the Utility's revenues in 1993. The economy of the Utility's New Mexico Division is primarily dependent upon mining and agriculture. Copper mines are the major industrial customers in the New Mexico Division. This division produced 16.8% of the total operating revenues in 1993. The Utility's Central Division includes municipalities and communities located to the south and west of Fort Worth. This area's economy is largely dependent on agriculture and to lesser degrees tourism and oil production. In far west Texas, between Midland and El Paso, the Utility's Western Division serves municipalities whose economies are primarily related to oil and gas production, agriculture and food processing. The Utility serves and intends to continue serving members of the public in all of its present service areas. The Utility will construct facilities as needed to meet increasing demand for its service. The Utility will also extend service beyond its present service territories to the extent permitted by law and the orders of regulatory commissions. For a description of the properties utilized to provide this service, see Item 2, "Properties." Operating Revenues Revenues contributed by the Utility's operating divisions in 1993, 1992 and 1991 and the corresponding percentages of total operating revenues are shown below: 1993 1992 1991 Operating Revenues Revenues Revenues Division (000's) %'s (000's) %'s (000's) %'s Central $39,460 8.3% $ 35,421 8.0% $ 34,625 7.8% Northern 92,265 19.5 83,626 18.9 84,227 19.1 Southeast 234,895 49.5 222,460 50.1 220,581 50.0 Western 28,084 5.9 27,193 6.1 27,487 6.2 New Mexico 79,538 16.8 75,127 16.9 74,423 16.9 Total $474,242 100.0% $443,827 100.0% $441,343 100.0% TNP ENTERPRISES, INC. FORM 10-K In 1993, 1992 and 1991, no single customer accounted for greater than 10% of operating revenues, although the Utility has two affiliated industrial customers in the New Mexico Division which, together, contributed between 8% and 10% of the Utility's revenues in each of these years. Sources of Energy Information on the "Sources of Energy" of the Utility is incorporated herein by reference to pages 4 and 5 of the Annual Report to Shareholders for the year ended December 31, 1993. Recovery of Purchased Power and Fuel Costs Purchased power cost recovery adjustment clauses in the Utility's rate schedules have been authorized by the regulatory authorities in Texas and New Mexico. A fixed fuel recovery factor in Texas has also been approved. Both are of substantial benefit to the Utility in efforts to recover timely and adequately these significant elements of operating expenses as described in note 1(g) to the consolidated financial statements contained in the Annual Report to Shareholders for the year ended December 31, 1993. Franchises The Utility holds franchises from each of the 90 municipalities in which it renders electric service. On December 31, 1993, these franchises had expiration dates varying from 1994 to 2039, 86 having stated terms of 25 years or more and two having stated terms of 20 years and two having stated terms of 15 years. The Utility also holds certificates of public convenience and necessity from the PUCT covering all of the territories it serves in Texas. The Utility has been issued certificates for other areas after hearings before the PUCT. These certificates include terms which are customary in the public utility industry. In New Mexico, the Utility operates generally under the grandfather clause of that state's Public Utility Act which authorizes the continuance of existing service following the date of the adoption of such act. Seasonality of Business The Utility's business is seasonal in character. Summer weather causes increased use of air-conditioning equipment which produces higher revenues during the months of June, July, August and September. For the year ended December 31, 1993, approximately 40% of annual revenues were recorded in June, July, August and September, and 60% in the other eight months. Working Capital The Utility's major demands on working capital are (1) the monthly payments for purchased power costs from the Utility's suppliers, (2) monthly and semi-annual interest payments on long-term debt and (3) semi-monthly payments for the lignite fuel source for TNP One. The purchased power and fuel costs are eventually recovered through the Utility's customers' rates and the purchased power and fuel costs recovery adjustment clauses and fixed fuel factors, more fully described in note 1(g) to the consolidated financial statements contained in the Annual Report to Shareholders for the year ended December 31, 1993. Unlike many other generating utilities, the Utility does not have the requirement of maintaining a large fuel inventory (lignite) due to the proximity of TNP One with the lignite mine site. The Utility sells customer receivables, as do many other utilities. The Utility sells its customer receivables to a nonaffiliated company on a nonrecourse basis. TNP ENTERPRISES, INC. FORM 10-K Competitive Conditions As a regulated public utility, the Utility operates with little direct competition throughout most of its service territory. Pursuant to the Texas Public Utility Regulatory Act, the PUCT has issued to all electric utilities in the State certificates of public convenience and necessity authorizing them to render elec- tric service. Rural electric cooperatives, investor-owned electric utilities and municipally owned electric utilities are all defined in such act as public utilities. In 72 of the 81 Texas municipalities served, the Utility has been the only electric utility issued a certificate to serve customers within the municipal limits. The Utility is also the only electric utility authorized to serve customers in some of the rural areas where it has electric facilities. In other rural areas served by the Utility, other electric utilities have also been authorized to serve customers; however, rural electric cooperatives may, under certain circumstances, become exempt from the PUCT's rate regulation. Where other electric utilities have also been certificated to serve customers within the same service area, the Utility may be subject to competition. From time to time, industrial customers of the Utility express interest in cogeneration as a method of reducing or eliminating reliance upon the Utility as a source of electric service, or to lower fuel costs and improve operating efficiency of process steam generation. During 1993, a major industrial customer in the Utility's Southeast Division requested proposals for a cogeneration project for evaluation by the customer. The Utility's operating revenues from this customer during 1993 were approximately $28 million. In January 1994, a potential developer for the proposed project was selected by the customer. The Utility's goal is to retain this customer and to lower overall system operating costs through coordination with the potential developer. Although the Utility cannot predict the ultimate outcome of the process, the current project as proposed by the customer, and as outlined by the potential developer, appears to present a means by which the Utility may retain electric service to this customer, at current levels. The Utility is actively pursuing the development of the necessary agreements with the potential developer to further define the degree to which electric service to this customer is retained and overall system operating costs may be lowered. In New Mexico, a utility subject to the jurisdiction of the NMPUC may not extend into territory served by another utility or into territory not contiguous to its service territory without a certificate of public convenience and necessity from the NMPUC. Investor-owned electric utilities and rural electric cooperatives are subject to the jurisdiction of the NMPUC. The Energy Policy Act of 1992, adopted in October 1992, significantly changed the U.S. energy policy, including the governing of the electric utility industry. Among the features of this act is the creation of Exempt Wholesale Generators and the authorization of the FERC to order, on a case-by-case basis, wholesale transmission access. It appears that these particular features will create competition for the generation and supply of electricity. Management continues to evaluate the effects of this act on the Utility. Although the act may not affect the Utility directly, the Utility believes that this increased competition will not have an unfavorable impact on it. Environmental Requirements Environmental requirements are not expected to materially affect capital outlays or materially affect the Utility directly. As the Utility's electric suppliers may be affected by environmental requirements and resulting costs, the rates charged by them to the Utility may be increased and thus the Utility will be affected indirectly. The Utility's facilities in Texas and New Mexico are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. The Utility maintains continuous procedures to insure compliance with all applicable environmental laws, rules and regulations. Various Utility activities require permits, licenses, registrations and approvals from such agencies. The Utility has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. TNP ENTERPRISES, INC. FORM 10-K TNP One's circulating fluidized bed technology produces "clean" emissions, without the addition of costly scrubbers. Unit 1 and Unit 2 meet the standards of the Clean Air Act of 1990. Under this act, an entity will be given an allotted number of allowances which permit emissions up to a specified level. The Utility believes the allowances received to be sufficient for the level of emissions to be created by TNP One. The construction costs for TNP One included approximately $89 million for environmental protection facilities. During 1993, 1992 and 1991, as an ongoing operation of air pollution abatement, including ash removal, TNP One incurred expenses of approximately $2.6 million, $2.7 million and $1.9 million, respectively. The Utility anticipates additional capital expenditures of $875,000 by 1995 for air emissions monitoring equipment for TNP One. The operations of the Utility are subject to a number of federal, state and local environmental laws and regulations, which govern the storage of motor fuels, including those regulating underground storage tanks. In September 1988, the Environmental Protection Agency (EPA) issued regulations that required all newly installed underground storage tanks be protected from corrosion, be equipped with devices to prevent spills and overfills, and have a leak detection method that meets certain minimum requirements. The effective commencement date for newly installed tanks was December 22, 1988. Underground storage tanks in place prior to December 22, 1988, must conform to the new standards by December 1998. The Utility currently estimates the cost over the next five years to bring its existing underground storage tanks into compliance with the EPA guidelines will be $100,000. The Utility also has the option of removing any existing underground storage tanks. During 1993, 1992, and 1991, the Utility incurred cleanup and testing costs on both leaking and nonleaking storage tanks of approximately $98,000, $89,000, and $84,000, respectively, in complying with these EPA regulations. A change in the regulations in the State of Texas permitted the Utility to collect in 1992 from the state environmental trust fund $65,000 of expenditures paid in prior years. Both states in which the Utility owns or operates underground storage tanks have state operated funds which reimburse the Utility for certain cleanup costs and liabilities incurred as a result of leaks in underground storage tanks. These funds, which essentially provide insurance coverage for certain environmental liabilities, are funded by taxes on underground storage tanks or on motor fuels purchased within each respective state. The funds require the Utility to pay deductibles of less than $5,000 per occurrence. During 1992, the Texas state environmental trust fund delayed reimbursement payments after September 30, 1992, of certain cleanup costs due to an increase in claims. Because the state and federal government have the right, by law, to levy additional fees on fuel purchases, the Utility believes these cleanup costs will ultimately be reimbursed. Employees The number of employees on December 31, 1993, was 1,051. TNP ENTERPRISES, INC. FORM 10-K Executive Officers of the Registrant Identification of Executive Officers Executive Officers of the Company Positions & Offices Held Period of with the Company Such Office Name Age Within the Past 5 Years1 Years Months D. R. Spurlock2 61 Interim President & Chief 0 1 Executive Officer and Director D. R. Barnard 61 Vice President & 4 8 Chief Financial Officer Vice President & 4 6 Treasurer M. D. Blanchard 43 Corporate Secretary & 6 4 General Counsel Monte W. Smith 40 Treasurer 4 8 Director - Internal Audit 2 11 Executive Officers of the Utility Positions & Offices Held Period of with the Utility Such Office Name Age Within the Past 5 Years1 Years Months D. R. Spurlock 61 Interim President & Chief 0 1 Executive Officer and Director Sector Vice President - 2 4 Operations Vice President - 11 1 Division Manager D. R. Barnard 61 Sector Vice President & 3 8 Chief Financial Officer Vice President & 1 0 Chief Financial Officer Vice President & 17 0 Treasurer J. V. Chambers, Jr. 44 Sector Vice President - 3 8 Revenue Production Vice President - Contracts 3 2 & Regulation 1, 2 See respective explanation appearing on the following page. TNP ENTERPRISES, INC. FORM 10-K Positions & Offices Held Period of with the Utility Such Office Name Age Within the Past 5 Years1 Years Months M. C. Davie 58 Vice President - Corporate 10 11 Affairs A. B. Davis 56 Vice President - Chief Engineer 1 8 Chief Engineer 1 4 Assistant Chief Engineer 0 1 Manager - Engineering 5 8 L.W. Dillon 39 Vice President - Operations 0 1 Division Manager 3 6 Division Engineering Manager 4 11 R. J. Wright 46 Vice President - 0 6 Corporate Services/Generation Vice President - Manager - Generation 4 8 M. D. Blanchard 43 Corporate Secretary & 6 4 General Counsel Monte W. Smith 40 Treasurer 4 8 Director - Internal Audit 2 11 1 All officers are elected annually by the respective Board of Directors for a one-year term until the next annual meeting of the Board of Directors or until their successors shall be elected and qualified. The term of an officer elected at any other time by the Board also will run until the next succeeding annual meeting of the Board of Directors or until a successor shall be elected and qualified. 2 Retired as Sector Vice President of the Utility effective December 31, 1992; named Interim President & Chief Executive Officer effective November 9, 1993. With the exception of D. R. Spurlock, each of the above-named officers is a full-time employee of the Utility and has been for more than five years prior to the date of the filing of this Form 10-K. TNP ENTERPRISES, INC. FORM 10-K Item 2. Properties. The Utility's electric properties served a total of 211,911 customers at year-end and consisted of the installations described in the following sections. (1) Electric generation, transmission and distribution facilities located in the State of Texas are as follows: (A) Central Division. Electric transmission and distribution sys- tems serving 25 municipalities and 18 unincorporated communities in 17 counties to the south and west of Fort Worth, Texas. The division is based at Clifton, Texas. (B) Northern Division. Electric transmission and distribution systems serving 36 municipalities and 19 unincorporated communities in 14 North Texas counties and 3 counties in the Texas Panhandle. The division is based at Lewisville, Texas. (C) Southeast Division. Electric transmission and distribution systems serving 14 municipalities and 2 unincorporated communities in 3 counties on the Texas Gulf Coast. The division is based at Texas City, Texas. (D) Western Division. Electric transmission and distribution sys- tems serving 6 municipalities and 1 unincorporated community in 5 counties in West Texas. The division is based at Pecos, Texas. (E) Robertson County, Texas. Two 150-megawatt lignite-fueled generating units (Unit 1 and Unit 2, collectively referred to as TNP One) using circulating fluidized bed technology. The Utility also has an 18-mile long transmission line to connect TNP One to a major transmission grid in Texas. (2) Electric generation, transmission and distribution facilities in the State of New Mexico serve 5 municipalities and 5 unincorporated communities in Grant and Hidalgo Counties, and 4 municipalities and 1 unincorporated community in Otero and Lincoln Counties. The New Mexico Division is based at Silver City, New Mexico. (3) The facilities owned by the Utility include those normally used in the electric utility business. The facilities are of sufficient capacity to adequately serve existing customers, and such facilities may be extended and expanded to serve future customer growth of the Utility in existing service areas. The Utility generally constructs its transmission and distribution facilities upon real property held pursuant to easements or public rights of way and not upon real property held in fee simple by the Utility. (4) All real and personal property of the Utility, with certain exceptions such as much of TNP One, is subject to the lien of the Indenture of Mortgage and Deed of Trust (Bond Indenture) under which the Utility's First Mortgage Bonds are issued. Certain exceptions are set forth in the Bond Indenture. The lenders in the Unit 2 financing facility and the holders of all secured debentures hold a second lien on all real and personal Texas property of the Utility. Holders of the Utility's Secured Debentures, due 1999 and Series A, Secured Debentures, due 2003 equally and ratably hold first liens on approximately 59% of Unit 1. The remaining amount of Unit 1 property is subject to a first lien under the Utility's Bond Indenture and a second lien under the secured debentures' indentures. The lenders under the Unit 2 financing facility and the Utility's Secured Debentures, due 1999, equally and ratably hold first liens on approximately 74% of Unit 2. The remaining amount of Unit 2 property is subject to a first lien under the Utility's Bond Indenture and a second lien under the secured debentures' indentures. Under certain conditions, upon repayment of portions of the loans or secured debentures under the financing facilities, the Utility may purchase undivided interests in Unit 1 or Unit 2 from TGC or TGC II, respectively, whereupon such undivided interests become subject to the first lien of the Utility's Bond Indenture. See note 2 to the consolidated financial statements contained in the Annual Report to Shareholders for the year ended December 31, 1993 for additional information. TNP ENTERPRISES, INC. FORM 10-K Item 3. Legal Proceedings. Appeals of Regulatory Orders The following summary discusses the Utility's most recent regulatory proceedings before the PUCT and the judicial appeals. While the ultimate outcome of these cases and of other matters discussed below cannot be predicted, the Utility is vigorously pursuing their favorable conclusion. Material adverse resolution of certain of the matters discussed below would have a material adverse impact on earnings in the period of resolution. More detailed discussions of the proceedings and related impacts are included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and note 5 to the consolidated financial statements contained in the Annual Report to Shareholders for the year ended December 31, 1993. PUCT Docket No. 9491 On April 11, 1990, the Utility filed a rate application, Docket No. 9491, with the PUCT for inclusion of the costs of Unit 1 in the Utility's rate base and for the setting of rates to recover the costs of that unit. On February 7, 1991, the Utility received a final order which allowed $298.5 million of the costs of Unit 1 in rate base; however, the PUCT disallowed from rate base $39.5 million of the requested investment costs of $338 million for that unit. The PUCT approved an increase in annualized revenues of approximately $36.7 million, or 67% of the Utility's original $54.9 million rate request. The PUCT also found that the Utility failed to prove that its decision to start construction of Unit 2 was prudent. Nevertheless, the PUCT granted rate base treatment for Unit 2 in Docket No. 10200, as discussed below. On appeal by the Utility of the PUCT's order in Docket No. 9491, a State district court in Travis County, Texas, ruled that the PUCT's disallowance of rate base treatment for certain costs of Unit 1 was in error and that the PUCT's "decision to deny $39,508,409 in capital costs for TNP One Unit 1 is not supported by substantial evidence and is arbitrary and capricious." On appeal of the State district court's order by the Utility, the PUCT and certain of the intervenor cities (the Cities), a Third District Court of Appeals in Austin, Texas, rendered a judgment partially reversing the State district court and affirming the PUCT's disallowances for $30.4 million of the total $39.5 million. The Court of Appeals remanded the cause to the district court with instructions that the cause be remanded to the PUCT for proceedings not inconsistent with the appellate opinion. On September 9, 1993, the Utility, the Cities and the PUCT filed motions for rehearing with the Court of Appeals. The Utility's opponents are seeking, among other things, lower rates and greater disallowances, and the Utility is seeking higher rates and no disallowances. The PUCT is not expected to act upon the district court's ordered remand, discussed above, until the appellate process, including appeals to the Texas Supreme Court, has been completed. Based upon the opinions of the Utility's Texas regulatory counsel, Johnson & Gibbs, a Professional Corporation, management believes that it will prevail in obtaining a remand of a significant portion of the disallowances in Docket No. 9491; however, the ultimate disposition and quantification of these items cannot presently be determined. Accordingly, no provision for any loss that may ultimately be required upon resolution of these matters has been made in the consolidated financial statements. If the Utility is not successful in obtaining a final favorable disposition in the appellate proceedings relating to the disallowances in Docket No. 9491, a write-off of some portion of the $39.5 million disallowances would be required, which could result in a significant negative impact on earnings in the period of final resolution. PUCT Docket No. 10200 On April 11, 1991, the Utility filed a rate application, Docket No. 10200, with the PUCT for inclusion of $275.2 million of capital costs of Unit 2 in the Utility's rate base and for the setting of rates to recover the costs of that unit. TNP ENTERPRISES, INC. FORM 10-K On March 18, 1993, the Utility received a final order which allowed $250.7 million of the Unit 2 costs in rate base; however, the PUCT disallowed from rate base $21.1 million associated with Unit 2 and $0.8 million additional costs requested for Unit 1. The PUCT also determined that $11.1 million of Unit 2 costs would be addressed in a future Texas rate application. The PUCT approved an increase in annualized revenues of approximately $19 million, or 53%, of the Utility's original $35.8 million rate request. The order in Docket No. 10200 also reflects application to the Utility of a new method for calculating the amount of Federal income tax expense allowed in cost of service, which significantly reduced the Utility's level of annualized revenue increase from $26 million to $19 million. The Docket No. 10200 rate order has been appealed to a Texas district court by the Utility and other parties. Because of the Court of Appeals judgment relating to the prudence of starting construction of Unit 2 (FF No. 84 in the docket No. 9491), the presiding judge in the Texas district court for the Docket No. 10200 appeal has ordered that the procedural schedule in this appeal be abated until final resolution of the FF No. 84 issue in Docket No. 9491. The Utility will vigorously pursue reversal of the PUCT's new position regarding Federal income tax expenses, in addition to seeking judicial relief from the disallowances and certain other rulings by the PUCT in Docket No. 10200. The opposing parties are seeking a variety of relief to obtain lower rates and greater disallowances, including overturning the basis of the Utility's case as presented to the PUCT and sustaining the PUCT's adverse Federal income tax position without regard to any IRS ruling on the normalization issue. Based upon the opinions of the Utility's Texas regulatory counsel, Johnson & Gibbs, a Professional Corporation, management believes that it will prevail in obtaining a remand of a significant portion of the disallowances in Docket No. 10200; however, the ultimate disposition and quantification of these items cannot presently be determined. Accordingly, no provision for any loss that may ultimately be required upon resolution of these matters has been made in the consolidated financial statements. If the Utility is not successful in obtaining a final favorable disposition in the appellate proceedings relating to the disallowances in Docket No. 10200, a write-off of some portion of the $21.9 million disallowances would be required, which could result in a significant negative impact on earnings in the period of final resolution. Other Legal Matters The Utility is involved in various claims and other legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Utility's consolidated financial position. Item 4. Submission of Matters to a Vote of Security Holders. There were no matters submitted to a vote of security holders in the fourth quarter of 1993. PART II Item 5. Market For The Registrant's Common Equity and Related Shareholder Matters. This information is incorporated by reference to "Common Stock Information" on page 38 of the Annual Report to Shareholders for the year ended December 31, 1993. For the years ended December 31, 1993 and 1992, the Company paid $17,344,000, and $13,780,000, respectively, in common dividends. Dividends were paid on a quarterly basis. Since most of the assets, liabilities and earnings capability of the Company are those of the Utility, the ability of the Company to pay dividends will be largely dependent upon the Utility's operations and the Utility's restrictions regarding payment of its dividends as discussed in notes 2 and 3 to the consolidated financial statements contained in the Annual Report to Shareholders for the year ended December 31, 1993. TNP ENTERPRISES 10-K Item 6. Selected Consolidated Financial Data. This information is incorporated by reference to "Selected Annual Consolidated Financial Data" on page 36 of the Annual Report to Shareholders for the year ended December 31, 1993. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and note 5 to the consolidated financial statements contained in the Annual Report to Shareholders for the year ended December 31, 1993 for discussion of material uncertainties which might cause the information incorporated by reference above not to be indicative of future financial condition or results of operations. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. This information is incorporated by reference to "Management's Discussion and Analysis of Financial Condition and Results of Operations" on pages 6 through 16 of the Annual Report to Shareholders for the year ended December 31, 1993. Item 8. Financial Statements and Supplementary Data. This information is incorporated by reference to the appropriate sections on pages 17 through 35 of the Annual Report to Shareholders for the year ended December 31, 1993. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None. PART III Item 10. Directors and Executive Officers of the Registrant. Identification of Directors and Directorships The information required by this item is incorporated by reference from "The Nominees and Continuing Directors" of the definitive Proxy Statement relating to the annual meeting of holders of common stock of the Company, pursuant to Regulation 14A, filed with the SEC and mailed on or about March 28, 1994 to the holders of common stock of the Company. Identification of Executive Officers The information required by this item with respect to executive officers is set forth in Item 1 of Part I of this Form 10-K under "Executive Officers of the Registrant, " pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K. Item 11. Executive Compensation.* Item 12. Security Ownership of Certain Beneficial Owners and Management.* Item 13. Certain Relationships and Related Transactions.* * The information required by Items 11, 12, and 13 is incorporated by reference from the definitive Proxy Statement relating to the Annual Meeting of holders of common stock of the Company, pursuant to Regulation 14A, filed with the SEC and mailed on or about March 28, 1994 to the holders of common stock of the Company. TNP ENTERPRISES, INC. FORM 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. (a) Items Filed as Part of This Report Financial Statements and Supplementary Data The following information is incorporated by reference to pages 17 through 35 of the Annual Report to Shareholders for the year ended December 31, 1993: Independent Auditors' Report Consolidated Statements of Earnings, Three Years Ended December 31, 1993 Consolidated Balance Sheets, December 31, 1993 and 1992 Consolidated Statements of Common Stock Equity and Redeemable Cumulative Preferred Stocks, Three Years Ended December 31, 1993 Consolidated Statements of Cash Flows, Three Years Ended December 31, 1993 Notes to Consolidated Financial Statements, December 31, 1993, 1992 and 1991 Selected Quarterly Consolidated Financial Data (Unaudited), Quarters ended March 31, June 30, September 30, and December 31, 1993 and 1992 Financial Statement Schedules Page Independent Auditors' Report. . . . . . . . . . . . . . 17 V - Utility Plant, Three Years Ended December 31, 1993 . . . . . 18 VI - Accumulated Depreciation of Utility Plant, Three Years Ended December 31, 1993 . . . . . . . . . . . . . . 19 IX - Short-term Borrowings, Three Years Ended December 31, 1993 20 X - Supplementary Consolidated Earnings Statement Information, Three Years Ended December 31, 1993 . . . . . 21 All other schedules are omitted, as the required information is inapplicable or the information is presented in the consolidated financial statements or related notes contained in the Annual Report to Shareholders for the year ended December 31, 1993. Exhibits. See Exhibit Index, Pages 22 through 33. (b) Reports on Form 8-K None during the last quarter covered by this report. TNP ENTERPRISES, INC. FORM 10-K 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. (Registrant) TNP ENTERPRISES, INC. By /s/ D. R. Barnard D. R. Barnard, Vice President & Chief Financial Officer Date: March 22, 1994 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 and on the dates indicated. Title Date By /s/ R. D. Woofter Chairman 3-22-94 R. D. Woofter By /s/ Dwight R. Spurlock Interim President & 3-22-94 D. R. Spurlock Chief Executive Officer By /s/ D. R. Barnard Vice President & 3-22-94 D. R. Barnard Chief Financial Officer By /s/ Monte W. Smith Treasurer (Principal 3-22-94 Monte W. Smith Accounting Officer) By /s/ R. Denny Alexander Director 3-22-94 R. Denny Alexander By /s/ Cass O. Edwards, II Director 3-22-94 Cass O. Edwards, II By /s/ John A. Fanning Director 3-22-94 John A. Fanning By /s/ Harris L. Kempner, Jr. Director 3-22-94 Harris L. Kempner, Jr. TNP ENTERPRISES, INC. FORM 10-K Index to Financial Statement Schedules Independent Auditors' Report Schedules: V - Utility Plant, Three Years Ended December 31, 1993 VI - Accumulated Depreciation of Utility Plant, Three Years Ended December 31, 1993 IX - Short-term Borrowings, Three Years Ended December 31, 1993 X - Supplementary Consolidated Earnings Statement Information, Three Years Ended December 31, 1993 All other schedules are omitted, as the required information is inapplicable or the information is presented in the consolidated financial statements or related notes. The consolidated balance sheets of the Company and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of earnings, common stock equity and redeemable cumulative preferred stocks, and cash flows for each of the years in the three-year period ended December 31, 1993, together with the related notes and the report of KPMG Peat Marwick, independent certified public accountants, all contained in the Annual Report to Shareholders for the year ended December 31, 1993, are incorporated herein by reference. TNP ENTERPRISES, INC. FORM 10-K Independent Auditors' Report The Shareholders and Board of Directors TNP Enterprises, Inc.: Under date of January 28, 1994, we reported on the consolidated balance sheets of TNP Enterprises, Inc. and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of earnings, common stock equity and redeemable cumulative preferred stocks, and cash flows for each of the years in the three-year period ended December 31, 1993, as contained in the 1993 annual report to shareholders. These consolidated financial statements and our report thereon are incorporated by reference in the annual report on Form 10-K for the year 1993. In connection with our audits of the aforementioned consolidated financial statements, we also have audited the related financial statement schedules as listed in the accompanying index. These financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statement schedules based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. The report includes an explanatory paragraph that states that uncertainties exist with respect to the outcome of certain regulatory matters as discussed in note 5 to the consolidated financial statements. The ultimate outcome of these matters cannot presently be determined. Accordingly, no provision for any loss that may ultimately be required upon resolution of these matters has been made in the above consolidated financial statements and financial statement schedules. As discussed in note 4 to the consolidated financial statements, the Company changed its method of accounting for income taxes in 1993 to adopt the provisions of the Financial Accounting Standards Board's Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes. As discussed in note 1(j), the Company also adopted the provisions of the Financial Accounting Standards Board's SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions in 1993. KPMG PEAT MARWICK Fort Worth, Texas January 28, 1994 TNP ENTERPRISES, INC. FORM 10-K Utility Plant Schedule V
Three Years Ended December 31, 1993 (In Thousands) Other Balance at changes: Balance at beginning Additions add end of Classification of period at cost(1) Retirements (deduct) period Year ended December 31, 1993: Electric plant $1,184,635 17,587 5,436 6,850 1,203,636 Construction work in progress 3,922 8,210 - (6,850) 5,282 $1,188,557 25,797 5,436 - 1,208,918 Year ended December 31, 1992: Electric plant $1,159,511 30,365 (6,683) 1,442 1,184,635 Construction work in progress 2,279 3,085 - (1,442) 3,922 $1,161,790 33,450 (6,683) - 1,188,557 Year ended December 31, 1991: Electric plant $850,160 313,259 (6,650) 2,742 1,159,511 Construction work in progress 2,844 2,177 - (2,742) 2,279 $853,004 315,436 (6,650) - 1,161,790 Note: See note 1(c) to the consolidated financial statements contained in the Annual Report to Shareholders for the year ended December 31, 1993 for disclosure of depreciation method. (1) On July 26, 1991, the Utility's wholly owned subsidiary, TGCII, assumed ownership of TNP One, Unit 2 and assumed the related liabilities totaling approximately $269 million. In addition, approximately $12 million of deferred charges related to TNP One, Unit 2 were reclassified to utility plant. These amounts are included in the 1991 additions above. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and note 5 to the consolidated financial statements contained in the Annual Report to Shareholders for the year ended December 31, 1993, and Items 1 and 2, for more information about Unit 2. During 1992, the Utility reclassified approximately $12 million of deferred charges to utility plant.
TNP ENTERPRISES, INC. FORM 10-K Accumulated Depreciation of Utility Plant Schedule VI Three Years Ended December 31, 1993 (In Thousands)
Other Additions changes: Balance at charged to add Balance at beginning costs and Net (deduct) end of Description of period expenses retirements (See Notes) period Year ended December 31, 1993: Electric plant $172,848 36,015 (6,268) 328 202,923 Year ended December 31, 1992: Electric plant $145,188 35,098 (7,687) 249 172,848 Year ended December 31, 1991: Electric plant $124,015 28,027 (7,444) 590 145,188 Notes: Other additions represent depreciation of transportation equipment charged to property accounts in accordance with the equipment's use. See note 1(c) to the consolidated financial statements contained in the Annual Report to Shareholders for the year ended December 31, 1993 for disclosure of depreciation method.
TNP ENTERPRISES, INC. FORM 10-K Short-term Borrowings (1) Schedule IX Three Years Ended December 31, 1993 (Dollars in Thousands)
Weighted Maximum Average Weighted Category of average amount amount average aggregate Balance interest rateout standing outstandinginterest rate short-term at end at end during the during the during the Period borrowings of period of period period(3) period(2) period (2) 1993 Unsecured Notes Payable to Banks $ -0- N/A $-0- -0- N/A 1992 Unsecured Notes Payable to Banks $ -0- N/A(2) $36,000 13,004 5.70% 1991 Unsecured Notes Payable to Banks $ 36,000 7.10% $60,000 36,698 7.70% Notes: (1) Unsecured notes payable to banks were issued under revolving lines of credit. Under the terms of the revolving lines of credit, the interest rates were determined under several alternative methods. All rates at the time of issuance were the prime lending rate plus 1/2% or lower. A fee of 1/4 of 1% per annum of the average unused commitments was payable quarterly, with no compensating bank balance requirements. (2) For 1991, computation was based on days outstanding for the year. For 1992, computation was based on the period of January 1, 1992 to August 12, 1992 when all outstanding unsecured notes payable to banks were retired. (3) For 1991, represents the maximum amount outstanding at any month end. For 1992, represents the balance outstanding at January 1, 1992.
TNP ENTERPRISES, INC. FORM 10-K Supplementary Consolidated Earnings Statement InformationSchedule X Three Years Ended December 31, 1993 (In Thousands) Charged to costs and expenses Item 1993 1992 1991 Taxes, other than payroll and income taxes: Gross receipts and street rentals $11,387 10,064 9,484 Property 14,132 14,272 10,302 Other 2,613 2,431 1,689 $28,132 26,767 21,475 TNP ENTERPRISES, INC. FORM 10-K EXHIBIT INDEX Exhibits filed herewith are denoted by "*." The other exhibits have heretofore been filed with the Commission and are incorporated herein by reference. Exhibit No. Description 3(a) - Articles of Incorporation and Amendments through March 6, 1984 (Exhibit 3(a), File No. 2-89800). 3(b) - Amendment to Articles of Incorporation filed September 25, 1984. (Exhibit 3(b) to Form 10-K for the year ended December 31, 1987, File No. 1-8847). 3(c) - Amendment to Articles of Incorporation filed August 29, 1985 (Exhibit 3(a) to Form 10-K for the year ended December 31, 1985, File No. 1-8847). 3(d) - Amendment to Articles of Incorporation filed June 2, 1986 (Exhibit 3(a) to Form 10-K for the year ended December 31, 1986, File No. 1-8847). 3(e) - Amendment to Articles of Incorporation filed May 10, 1988 (Exhibit 3(e) to Form 10-K for the year ended December 31, 1988, File No. 1-8847). 3(f) - Amendment to Articles of Incorporation filed May 10, 1988 (Exhibit 3(f) to Form 10-K for the year ended December 31, 1988, File No. 1-8847). 3(g) - Amendment to Articles of Incorporation filed December 27, 1988 (Exhibit 3(g) to Form 10-K for the year ended December 31, 1988, File No. 1-8847). 3(h) - Bylaws of the Company, as amended February 18, 1992 (Exhibit 4(h), File No. 33-53918). 4(a) - Indenture of Mortgage and Deed of Trust of the Utility dated as of November 1, 1944 (Exhibit 2(d), File No. 2-61323). 4(b) - Seventh Supplemental Indenture dated as of May 1, 1963 (Exhibit 2(k), File No. 2-61323). 4(c) - Eighth Supplemental Indenture dated as of July 1, 1963 (Exhibit 2(1), File No. 2-61323). TNP ENTERPRISES, INC. FORM 10-K Exhibit Description No. 4(d) - Ninth Supplemental Indenture dated as of August 1, 1965 (Exhibit 2(m), File No. 2-61323). 4(e) - Tenth Supplemental Indenture dated as of May 1, 1966 (Exhibit 2(n), File No. 2-61323). 4(f) - Eleventh Supplemental Indenture dated as of October 1, 1969 (Exhibit 2(o), File No. 2-61323). 4(g) - Twelfth Supplemental Indenture dated as of May 1, 1971 (Exhibit 2(p), File No. 2-61323). 4(h) - Thirteenth Supplemental Indenture dated as of July 1, 1974 (Exhibit 2(q), File No. 2-61323). 4(i) - Fourteenth Supplemental Indenture dated as of March 1, 1975 (Exhibit 2(r), File No. 2-61323). 4(j) - Fifteenth Supplemental Indenture dated as of September 1, 1976 (Exhibit 2(e), File No. 2-57034). 4(k) - Sixteenth Supplemental Indenture dated as of November 1, 1981 (Exhibit 4(x), File No. 2-74332). 4(l) - Seventeenth Supplemental Indenture dated as of December 1, 1982 (Exhibit 4(cc), File No. 2-80407). 4(m) - Eighteenth Supplemental Indenture dated as of September 1, 1983 (Exhibit (a) to Form 10-Q of Texas-New Mexico Power Company for the quarter ended September 30, 1983, File No. 1-4756). 4(n) - Nineteenth Supplemental Indenture dated as of May 1, 1985 (Exhibit 4(v), File No. 2-97230). 4(o) - Twentieth Supplemental Indenture dated as of July 1, 1987 (Exhibit 4(o) to Form 10-K of Texas-New Mexico Power Company for the year ended December 31, 1987, File No. 2-97230). 4(p) - Twenty-First Supplemental Indenture dated as of July 1, 1989 (Exhibit 4(p) to Form 10-Q of Texas-New Mexico Power Company for the quarter ended June 30, 1989, File No. 2-97230). 4(q) - Twenty-Second Supplemental Indenture dated as of January 15, 1992 (Exhibit 4(q) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). TNP ENTERPRISES, INC. FORM 10-K Exhibit No. Description 4(r) - Twenty-Third Supplemental Indenture dated as of September 15, 1993 (Exhibit 4(r) to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). 4(s) - Indenture and Security Agreement for Secured Debentures dated as of January 15, 1992 (Exhibit 4(r) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 4(t) - Indenture and Security Agreement for Secured Debentures dated as of September 15, 1993 (Exhibit 4(t) to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). 4(u) - Rights Agreement and Form of Right Certificate, as amended, effective November 13, 1990 (Exhibit 2.1 to Form 8-A, File No. 1-8847). Material Contracts Relating to TNP One 10(a) - Fuel Supply Agreement, dated November 18, 1987, between Phillips Coal Company and the Utility (Exhibit 10(j) to Form 10-K of the Utility for the year ended December 31, 1987, File No. 2-97230). 10(b) - Unit 1 First Amended and Restated Project Loan and Credit Agreement, dated as of January 8, 1992 (the "Unit 1 Credit Agreement"), among the Utility, Texas Generating Company ("TGC"), the banks named therein as Banks (the "Unit 1 Banks") and The Chase Manhattan Bank (National Association), as Agent for the Unit 1 Banks (the "Unit 1 Agent"), amending and restating the Project Loan and Credit Agreement among such parties dated as of December 1, 1987 (Exhibit 10(c) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(b)1 - Participation Agreement, dated as of January 8, 1992, among the banks named therein as Banks, the parties named therein as Participants and the Unit 1 Agent (Exhibit 10(c)1) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(b)2 - Amendment No. 1, dated as of September 21, 1993, to the Unit 1 Credit Agreement (Exhibit 10(b)2 to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). 10(c) - Assignment and Security Agreement, dated as of January 8, 1992, among TGC and the Unit 1 Agent, for the benefit of the Secured Parties, as defined in the Unit 1 Credit Agreement, amending and restating the Assignment and Security Agreement among such parties dated as of December 1, 1987 (Exhibit 10(d) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). TNP ENTERPRISES, INC. FORM 10-K Exhibit No. Description 10(d) - Assignment and Security Agreement, dated December 1, 1987, executed by the Utility in favor of the Unit 1 Agent for the benefit of the Secured Parties, as defined therein (Exhibit 10(u) to Form 10-K of the Utility for the year ended December 31, 1987, File No. 2-97230). 10(e) - Amended and Restated Subordination Agreement, dated as of October 1, 1988, among the Utility, Continental Illinois National Bank and Trust Company of Chicago and the Unit 1 Agent, amending and restating the Subordination Agreement among such parties dated as of December 1, 1987 (Exhibit 10(uu) to Form 10- K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(f) - Mortgage and Deed of Trust (With Security Agreement and UCC Financing Statement for Fixture Filing), dated to be effective as of December 1, 1987, and executed by Project Funding Corporation ("PFC"), as Mortgagor, to Donald H. Snell, as Mortgage Trustee, for the benefit of the Secured Parties, as defined therein (Exhibit 10(ee) to Form 10-K of the Utility for the year ended December 31, 1987, File No. 2-97230). 10(f)1 - Supplemental Mortgage and Deed of Trust (With Security Agreement and UCC Financing Statement for Fixture Filing), executed by TGC, as Mortgagor, on January 27, 1992, to be effective as of December 1, 1987, to Donald H. Snell, as Mortgage Trustee, for the benefit of the Secured Parties, as defined therein (Exhibit 10(g)4) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(f)2 - First TGC Modification and Extension Agreement, dated as of January 24, 1992, among the Unit 1 Banks, the Unit 1 Agent, the Utility and TGC (Exhibit 10(g)1) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(f)3 - Second TGC Modification and Extension Agreement, dated as of January 27, 1992, among the Unit 1 Banks, the Unit 1 Agent, the Utility and TGC (Exhibit 10(g)2) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(f)4 - Third TGC Modification and Extension Agreement, dated as of January 27, 1992, among the Unit 1 Banks, the Unit 1 Agent, the Utility and TGC (Exhibit 10(g)3) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(f)5 - Fourth TGC Modification and Extension Agreement, dated as of September 29, 1993, among the Unit 1 Banks, the Unit 1 Agent, the Utility and TGC (Exhibit 10(f)5 to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). TNP ENTERPRISES, INC. FORM 10-K Exhibit No. Description 10(f)6 - Fifth TGC Modification and Extension Agreement, dated as of September 29, 1993, among the Unit 1 Banks, the Unit 1 Agent, the Utility and TGC (Exhibit 10(f)6 to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). 10(g) - Indemnity Agreement, made as of the 1st day of December, 1987, by Westinghouse, CE and Zachry, as Indemnitors, for the benefit of the Secured Parties, as defined therein (Exhibit 10(ff) to Form 10-K of the Utility for the year ended December 31, 1987, File No. 2-97230). 10(h) - Second Lien Mortgage and Deed of Trust (With Security Agreement) executed by the Utility, as Mortgagor, to Donald H. Snell, as Mortgage Trustee, for the benefit of the Secured Parties, as defined therein (Exhibit 10(jj) to Form 10-K of the Utility for the year ended December 31, 1987, File No. 2-97230). 10(h)1 - Correction Second Lien Mortgage and Deed of Trust (with Security Agreement), dated as of December 1, 1987, executed by the Utility, as Mortgagor, to Donald H. Snell, as Mortgage Trustee, for the benefit of the Secured Parties, as defined therein (Exhibit 10(vv) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(h)2 - Second Lien Mortgage and Deed of Trust (with Security Agreement) Modification, Extension and Amendment Agreement, dated as of January 8, 1992, executed by the Utility to Donald H. Snell, as Mortgage Trustee, for the benefit of the Secured Parties, as defined therein (Exhibit 10(i)2) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(h)3 - TNP Second Lien Mortgage Modification No. 2, dated as of September 21, 1993, executed by the Utility to Donald H. Snell, as Mortgage Trustee, for the benefit of the Secured Parties, as defined therein (Exhibit 10(h)3 to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). 10(i) - Agreement for Conveyance and Partial Release of Liens, made as of the 1st day of December, 1987, by PFC and the Unit 1 Agent for the benefit of the Utility (Exhibit 10(kk) to Form 10-K of the Utility for the year ended December 31, 1987, File No. 2-97230). 10(j) - Inducement and Consent Agreement, dated as of June 15, 1988, between Phillips Coal Company, Kiewit Texas Mining Company, the Utility, Phillips Petroleum Company and Peter Kiewit Son's, Inc. (Exhibit 10(nn) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(k) - Assumption Agreement, dated as of October 1, 1988, executed by TGC, in favor of the Issuing Bank, as defined therein, the Unit 1 Banks, the Unit 1 Agent and the Depositary, as defined therein (Exhibit 10(ww) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). TNP ENTERPRISES, INC. FORM 10-K Exhibit No. Description 10(l) - Guaranty, dated as of October 1, 1988, executed by the Utility and given in respect of the TGC obligations under the Unit 1 Credit Agreement (Exhibit 10(xx) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(m) - First Amended and Restated Facility Purchase Agreement, dated as of January 8, 1992, among the Utility, as the Purchaser, and TGC, as the Seller, amending and restating the Facility Purchase Agreement among such parties dated as of October 1, 1988 (Exhibit 10(n) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(n) - Operating Agreement, dated as of October 1, 1988, among the Utility and TGC (Exhibit 10(zz) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(o) - Unit 2 First Amended and Restated Project Loan and Credit Agreement, dated as of January 8, 1992 (the "Unit 2 Credit Agreement"), among the Utility, Texas Generating Company II ("TGCII"), the banks named therein as Banks (the "Unit 2 Banks") and The Chase Manhattan Bank (National Association), as Agent for the Unit 2 Banks (the "Unit 2 Agent"), amending and restating the Project Loan and Credit Agreement among such parties dated as of October 1, 1988 (Exhibit 10(q) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(o)1 - Amendment No. 1, dated as of September 21, 1993, to the Unit 2 Credit Agreement (Exhibit 10(o)1 to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). 10(p) - Assignment and Security Agreement, dated as of January 8, 1992, among TGCII and the Unit 2 Agent, for the benefit of the Secured Parties, as defined in the Unit 2 Credit Agreement, amending and restating the Assignment and Security Agreement among such parties dated as of October 1, 1988 (Exhibit 10(r) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(q) - Assignment and Security Agreement, dated as of October 1, 1988, executed by the Utility in favor of the Unit 2 Agent for the benefit of the Secured Parties, as defined therein (Exhibit 10(jjj) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(r) - Subordination Agreement, dated as of October 1, 1988, among the Utility, Continental Illinois National Bank and Trust Company of Chicago and the Unit 2 Agent (Exhibit 10(mmm) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). TNP ENTERPRISES, INC. FORM 10-K Exhibit No. Description 10(s) - Mortgage and Deed of Trust (With Security Agreement and UCC Financing Statement for Fixture Filing), dated to be effective as of October 1, 1988, and executed by Texas PFC, Inc., as Mortgagor, to Donald H. Snell, as Mortgage Trustee, for the benefit of the Secured Parties, as defined therein (Exhibit 10(uuu) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(s)1 - First TGCII Modification and Extension Agreement, dated as of January 24, 1992, among the Unit 2 Banks, the Unit 2 Agent, the Utility and TGCII (Exhibit 10(u)1) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(s)2 - Second TGCII Modification and Extension Agreement, dated as of January 27, 1992, among the Unit 2 Banks, the Unit 2 Agent, the Utility and TGCII (Exhibit 10(u)2) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(s)3 - Third TGCII Modification and Extension Agreement, dated as of January 27, 1992, among the Unit 2 Banks, the Unit 2 Agent, the Utility and TGCII (Exhibit 10(u)3) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(s)4 - Fourth TGCII Modification and Extension Agreement, dated as of September 29, 1993, among the Unit 2 Banks, the Unit 2 Agent, the Utility and TGCII (Exhibit 10(s)4 to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). 10(t) - Release and Waiver of Liens and Indemnity Agreement, made effective as of the 1st day of October, 1988, by a consortium composed of Westinghouse, CE, and Zachry (Exhibit 10(vvv) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(u) - Second Lien Mortgage and Deed of Trust (With Security Agreement), dated as of October 1, 1988, and executed by the Utility, as Mortgagor, to Donald H. Snell, as Mortgage Trustee, for the benefit of the Secured Parties, as defined therein (Exhibit 10(www) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(u)1 - Second Lien Mortgage and Deed of Trust (with Security Agreement) Modification, Extension and Amendment Agreement, dated as of January 8, 1992, executed by the Utility to Donald H. Snell, as Mortgage Trustee, for the benefit of the Secured Parties, as defined therein (Exhibit 10(w)1) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). TNP ENTERPRISES, INC. FORM 10-K Exhibit No. Description 10(u)2 - TNP Second Lien Mortgage Modification No. 2, dated as of September 21, 1993, executed by the Utility to Donald H. Snell, as Mortgage Trustee, for the benefit of the Secured Parties, as defined therein (Exhibit 10(u)2 to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). 10(v) - Intercreditor and Nondisturbance Agreement, dated as of October 1, 1988, among PFC, Texas PFC, Inc., the Utility, the Project Creditors, as defined therein, and the Collateral Agent, as defined therein (Exhibit 10(xxx) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(v)1 - Amendment #1, dated as of January 8, 1992, to the Intercreditor and Nondisturbance Agreement, dated as of October 1, 1988, among TGC, TGCII, the Utility, the Unit 1 Banks, the Unit 2 Banks and The Chase Manhattan Bank (National Association) in its capacity as collateral agent for the Unit 1 Banks and the Unit 2 Banks (Exhibit 10(x)1) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2-97230). 10(v)2 - Amendment No. 2, dated as of September 21, 1993, to the Intercreditor and Nondisturbance Agreement among TGC, TGCII, the Utility, the Unit 1 Banks, the Unit 2 Banks and The Chase Manhattan Bank (National Association) in its capacity as collateral agent for the Unit 1 Banks and the Unit 2 Banks (Exhibit 10(v)2 to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). 10(w) - Grant of Reciprocal Easements and Declaration of Covenants Running with the Land, dated as of the 1st day of October, 1988 between PFC and Texas PFC, Inc. (Exhibit 10(yyy) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(x) - Non-Partition Agreement, dated as of May 30, 1990, among the Utility, TGC and The Chase Manhattan Bank (National Association), as Agent for the Banks which are parties to the Unit 1 Credit Agreement (Exhibit 10(ss) to Form 10-K for the year ended December 31, 1990, File No. 1-8847). 10(y) - Assumption Agreement, dated July 26, 1991, to be effective as of May 31, 1991, by TGCII in favor of the Issuing Bank, the Unit 2 Banks, the Unit 2 Agent and the Depositary, as defined therein (Exhibit 10(kkk) to Amendment No. 1 to File No. 33-41903). 10(z) - Guaranty, dated July 26, 1991, to be effective as of May 31, 1991, by the Utility and given in respect of the TGCII obligations under the Unit 2 Credit Agreement (Exhibit 10(lll) to Amendment No. 1 to File No. 33-41903). TNP ENTERPRISES, INC. FORM 10-K Exhibit No. Description 10(aa) - First Amended and Restated Facility Purchase Agreement, dated as of January 8, 1992, among the Utility, as the Purchaser, and TGCII, as the Seller, amending and restating the Facility Purchase Agreement among such parties dated July 26, 1991, to be effective as of May 31, 1991 (Exhibit 10(dd) to Form 10-K of the Utility for the year ended December 31, 1991, File No. 2- 97230). 10(aa)1 - Amendment No. 1 to the Unit 2 First Amended and Restated Facility Purchase Agreement, dated as of September 21, 1993, among the Utility, as the Purchaser, and TGCII, as the Seller (Exhibit 10(aa)1 to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). 10(bb) - Operating Agreement, dated July 26, 1991, to be effective as of May 31, 1991, between the Utility and TGCII (Exhibit 10(nnn) to Amendment No. 1 to File No. 33-41903). 10(cc) - Non-Partition Agreement, executed July 26, 1991, to be effective as of May 31, 1991, among the Utility, TGCII and The Chase Manhattan Bank (National Association) (Exhibit 10(ppp) to Amendment No. 1 to File No. 33-41903). Power Supply Contracts 10(dd) - Contract dated May 12, 1976 between the Utility and Houston Lighting & Power Company (Exhibit 5(a), File No. 2-69353). 10(dd)1 - Amendment, dated January 4, 1989, to the Contract dated May 12, 1976 between the Utility and Houston Lighting & Power Company (Exhibit 10(cccc) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(ee) - Contract dated May 1, 1986 between the Utility and Texas Electric Utilities Company, amended September 29, 1986, October 24, 1986 and February 21, 1987 (Exhibit 10(c) of Form 8 applicable to Form 10-K of the Utility for the year ended December 31, 1986, File No. 2-97230). 10(ff) - Amended and Restated Agreement for Electric Service dated May 14, 1990 between the Utility and Texas Utilities Electric Company (Exhibit 10(vv) to Form 10-K for the year ended December 31, 1990, File No. 1-8847). 10(ff)1 - Amendment, dated April 19, 1993, to Amended and Restated Agreement for Electric Service, dated May 14, 1990, As Amended between the Utility and Texas Utilities Electric Company (Exhibit 10(ii)1 to Form S-2 Registration Statement, filed on July 19, 1993, File No. 33-66232). 10(gg) - Contract dated June 11, 1984 between the Utility and Southwestern Public Service Company (Exhibit 10(d) of Form 8 applicable to Form 10-K of the Utility for the year ended December 31, 1986, File No. 2-97230). TNP ENTERPRISES, INC. FORM 10-K Exhibit No. Description 10(hh) - Contract dated April 27, 1977 between the Utility and West Texas Utilities Company amended April 14, 1982, April 19, 1983, May 18, 1984 and October 21, 1985 (Exhibit 10(e) of Form 8 applicable to Form 10-K of the Utility for the year ended December 31, 1986, File No. 2-97230). 10(ii) - Contract dated April 29, 1987 between the Utility and El Paso Electric Company (Exhibit 10(f) of Form 8 applicable to Form 10- K of the Utility for the year ended December 31, 1986, File No. 2-97230). 10(jj) - Contract dated February 28, 1974, amended May 13, 1974, November 26, 1975, August 26, 1976 and October 7, 1980 between the Utility and Public Service Company of New Mexico (Exhibit 10(g) of Form 8 applicable to Form 10-K of the Utility for the year ended December 31, 1986, File No. 2-97230). 10(jj)1 - Amendment, dated February 22, 1982, to the Contract dated February 28, 1974, amended May 13, 1974, November 26, 1975, August 26, 1976, and October 7, 1980 between the Utility and Public Service Company of New Mexico (Exhibit 10(iiii) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2- 97230). 10(jj)2 - Amendment, dated February 8, 1988, to the Contract dated February 28, 1974, amended May 13, 1974, November 26, 1975, August 26, 1976, and October 7, 1980 between the Utility and Public Service Company of New Mexico (Exhibit 10(jjjj) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2- 97230). 10(jj)3 - Amended and Restated Contract for Electric Service, dated April 29, 1988, between the Utility and Public Service Company of New Mexico (Exhibit 10(zz)3 to Amendment No. 1 to File No. 33-41903). 10(kk) - Contract dated December 8, 1981 between the Utility and Southwestern Public Service Company amended December 12, 1984, December 2, 1985 and December 19, 1986 (Exhibit 10(h) of Form 8 applicable to Form 10-K of the Utility for the year ended December 31, 1986, File No. 2-97230). 10(kk)1 - Amendment, dated December 12, 1988, to the Contract dated December 8, 1981 between the Utility and Southwestern Public Service Company amended December 12, 1984, December 2, 1985 and December 19, 1986 (Exhibit 10(llll) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(kk)2 - Amendment, dated December 12, 1990, to the Contract dated December 8, 1981 between the Utility and Southwestern Public Service Company (Exhibit 19(t) to Form 10-K of the Utility for the year ended December 31, 1990, File No. 2-97230). TNP ENTERPRISES, INC. FORM 10-K Exhibit No. Description 10(ll) - Contract dated August 31, 1983, between the Utility and Capitol Cogeneration Company, Ltd. (including letter agreement dated August 14, 1986) (Exhibit 10(i) of Form 8 applicable to Form 10-K of the Utility for the year ended December 31, 1986, File No. 2-97230). 10(ll)1 - Agreement Substituting a Party, dated May 3, 1988, among Capitol Cogeneration Company, Ltd., Clear Lake Cogeneration Limited Partnership and the Utility (Exhibit 10(nnnn) to Form 10-K of the Utility for the year ended December 31, 1988, File No. 2-97230). 10(ll)2 - Letter Agreements, dated May 30, 1990 and August 28, 1991, between Clear Lake Cogeneration Limited Partnership and the Utility (Exhibit 10(oo)2 to Form 10-K of the Utility for the year ended December 31, 1992, File No. 2-97230). 10(ll)3 - Notice of Extension Letter, dated August 31, 1992, between Clear Lake Cogeneration Limited Partnership and the Utility (Exhibit 10(oo)3 to Form 10-K of the Utility for the year ended December 31, 1992, File No. 2-97230). 10(ll)4 - Scheduling Agreement, dated September 15, 1992, between Clear Lake Cogeneration Limited Partnership and the Utility (Exhibit 10(oo)4 to Form 10-K of the Utility for the year ended December 31, 1992, File No. 2-97230). 10(mm) - Interconnection Agreement between the Utility and Plains Electric Generation and Transmission Cooperative, Inc. dated July 19, 1984 (Exhibit 10(j) of Form 8 applicable to Form 10-K of the Utility for the year ended December 31, 1986, File No. 2-97230). 10(nn) - Interchange Agreement between the Utility and El Paso Electric Company dated April 29, 1987 (Exhibit 10(l) of Form 8 applicable to Form 10-K of the Utility for the year ended December 31, 1986, File No. 2-97230). 10(oo) - DC Terminal Participation Agreement between the Utility and El Paso Electric Company dated December 8, 1981 amended April 29, 1987 (Exhibit 10(m) of Form 8 applicable to Form 10-K of the Utility for the year ended December 31, 1986, File No. 2-97230). Employment Contracts 10(pp) - Texas-New Mexico Power Company Executive Agreement for Severance Compensation Upon Change in Control, executed November 11, 1993, between Sector Vice President and Chief Financial Officer and the Utility (Pursuant to Instruction 2 of Reg. 229.601(a), accompanying this document is a schedule: (i) identifying documents substantially identical to the document which have been omitted from the Exhibits; and (ii) setting forth the material details in which such omitted documents differ from the document) (Exhibit 10(pp) to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). TNP ENTERPRISES, INC. FORM 10-K Exhibit No. Description 10(qq) - Texas-New Mexico Power Company Key Employee Agreement for Severance Compensation Upon Change in Control, executed November 11, 1993, between Assistant Treasurer and the Utility (Pursuant to Instruction 2 of Reg. 229.601(a), accompanying this document is a schedule: (i) identifying documents substantially identical to the document which have been omitted from the Exhibits; and (ii) setting forth the material details in which such omitted documents differ from the document) (Exhibit 10(qq) to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). 10(rr) - Agreement between James M. Tarpley and the Company and the Utility, effective January 1, 1994 (Exhibit 10(rr) to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). 10(ss) - Agreement between Dwight R. Spurlock and the Company and the Utility, effective November 9, 1993 (Exhibit 10(ss) to Form 10-K of the Utility for the year ended December 31, 1993, File No. 2-97230). *13 - Annual Report to Shareholders for the year ended December 31, 1993. *21 - Subsidiaries of the Registrant. *23 - Independent Auditors' Consent - KPMG Peat Marwick. TNP ENTERPRISES, INC. FORM 10-K EX-21 2 SUBSIDIARIES OF THE REGISTRANT Exhibit 21 SUBSIDIARIES OF THE REGISTRANT Name State of Incorporation Texas-New Mexico Power Company Texas Bayport Cogeneration, Inc. Texas TNP Operating Company Texas Each subsidiary of the Company conducts its business under its own name. Texas-New Mexico Power Company has two wholly owned subsidiaries, Texas Generating Company and Texas Generating Company II, each incorporated in Texas. EX-23 3 CONSENT OF INDEPENDENT AUDITORS TNP ENTERPRISES, INC. FORM 10-K Exhibit 23 Independent Auditors' Consent The Board of Directors TNP Enterprises, Inc.: We consent to incorporation by reference in the Registration Statement (No. 2-93266) on Form S-3 and in the Registration Statement (No. 2-93265) on Form S-8 of TNP Enterprises, Inc. of our report dated January 28, 1994, relating to the consolidated balance sheets of TNP Enterprises, Inc. and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of earnings, common stock equity and redeemable cumulative preferred stocks, and cash flows and related schedules for each of the years in the three-year period ended December 31, 1993, which report is incorporated by reference in the December 31, 1993 annual report on Form 10-K of TNP Enterprises, Inc. Our report includes an explanatory paragraph that states that uncertainties exist with respect to the outcome of certain regulatory matters as discussed in note 5 to the consolidated financial statements. The ultimate outcome of these matters cannot presently be determined. Accordingly, no provision for any loss that may ultimately be required upon resolution of these matters has been made in the above consolidated financial statements. As discussed in note 4 to the consolidated financial statements, the Company changed its method of accounting for income taxes in 1993 to adopt the provisions of the Financial Accounting Standards Board's Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes. As discussed in note 1(j), the Company also adopted the provisions of the Financial Accounting Standards Board's SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions in 1993. KPMG PEAT MARWICK Fort Worth, Texas March 22, 1994 EX-13 4 EXHIBIT 13 TNP ENTERPRISES, INC. & SUBSIDIARIES 1993 ANNUAL REPORT CONTENTS To the Shareholders 2 Sources of Energy 4 Management's Discussion and Analysis of Financial Condition and Results of Operations 6 Independent Audirots' Report 17 Consolidated Financial Statements 18 Selected Electric Operating Statistics 37 Common Stock Information 38 Directors and Officers 39 Shareholder Information 40 HIGHLIGHTS
(Amounts in thousands - except as noted by *) 1993 1992 % Change Total operating revenues $ 474,242 443,827 6.9 Net earnings $ 11,605 10,930 6.2 Earnings available for common stock $ 10,726 9,962 7.7 Weighted average number of common shares outstanding 10,641 8,545 24.5 Earnings per share of common stock* $ 1.01 1.17 (13.7) Dividends per share of common stock* $ 1.63 1.63 0.0 Net book value of utility plant $1,005,995 1,015,709 (1.0) Kilowatt-hour (KWH) sales 6,286,877 6,066,311 3.6 Average annual KWH sales per residential customer* 11,362 11,003 3.3 Electric customers served (year-end)* 211,911 208,897 1.4 Number of employees* 1,051 1,086 (3.2)
CORPORATE PROFILE TNP Enterprises, Inc. (Company), based in Fort Worth, Texas, is the parent company of Texas-New Mexico Power Company (Utility). Through the Utility, the Company's principal subsidiary, the Company engages in the production, transmission and distribution of electricity to residential, commercial and industrial customers. The Utility serves approximately 212,000 customers in its four Texas divisions and its New Mexico division. Its service areas are located in southeast Texas near Houston, north central Texas in areas surrounding the Dallas-Fort Worth metroplex, the northeast corner of the Texas Panhandle, west Texas in the trans-Pecos region, and in southwest and south central New Mexico. [CENTERED IN PAGE ONE IS A TNP SERVICE AREA GRAPHIC MAP COVERING THE STATES OF NEW MEXICO AND TEXAS] Prior to 1990, the Utility purchased virtually all of its energy requirements from wholesale third party generators. The Utility reduced its dependence on such third party generators when it acquired, through its subsidiaries, a two-unit, 300-megawatt, lignite-fired power plant in Robertson County, Texas, in 1990 and 1991. The plant, called TNP One, uses the circulating fluidized bed technology to produce electricity. This environmentally superior technology allows TNP One to burn Texas lignite, its primary fuel, as well as Western coal, natural gas and petroleum coke. The plant's clean-fuel technology and fuel flexibility will provide benefits to the Utility's customers and the environment for years to come. At present, the Company's other two subsidiaries, Bayport Cogeneration, Inc. and TNP Operating Company, are not involved in any business activities. TO THE SHAREHOLDERS 1993 was a year of tough decisions, decisions requiring management to concentrate on the requirements of our customers while assuring the integrity of the Company for our shareholders. For our customers, we took direct steps to add value to the service we provide. For our shareholders, we executed a strategy to stabilize the financing requirements and, for the long-term, to improve the financial performance of TNP Enterprises, Inc. (Company) and its principal subsidiary, Texas-New Mexico Power Company (Utility). Financial efforts influenced by regulatory actions Our efforts to jointly address the interests of shareholders and of customers continued to be negatively affected by regulatory actions in Texas. During 1993, the Public Utility Commission of Texas (PUCT) completed its Final Order proceedings on the Utility's request to include the second unit of its two-unit power plant, TNP One, in base rates. The PUCT granted a rate increase of approximately $19 million, or 53% of the $35.8 million we had requested. We have appealed this decision to a Texas district court. The principal adverse effect of the PUCT's actions resulted from its decision to abandon its long-standing method for calculating the amount allowed in cost of service for Federal income tax expense. The effect of this decision was a reduction of approximately $7 million in annualized revenues. The PUCT finally granted, subject to refund, $1.6 million of additional annualized revenues, conditioned upon the Utility obtaining a private letter ruling from the Internal Revenue Service supporting the Utility's position on certain related tax consequences. This issue is reviewed extensively in the notes to consolidated financial statements in this report and is addressed in Management's Discussion and Analysis of Financial Condition and Results of Operations. Despite adverse regulatory actions, we were able to improve the debt structure of the Utility. We accomplished this by issuing $240 million in new debt securities last September. The proceeds were used primarily to discharge substantial portions of the indebtedness incurred for the construction of each unit of TNP One and, together with proceeds applied from prior securities offerings, reduced to $147.75 million the original $633.5 million amount of construction debt. This reduction, including a significant prepayment of outstanding indebtedness under the Unit 2 financing facility, was an integral part of an agreement with the lenders to extend the payment schedule for the remaining balance of the construction debt. The extension allows additional time for overall financial improvement, including additional rate relief. We believe the end result was the stabilizing of the financing requirements of the Utility for the balance of the 1990s. Earnings increase slightly For 1993, earnings available for common stock increased 7.7%; however, based upon the 24.5% increase of the weighted average number of common shares outstanding for 1993, earnings per share decreased to $1.01 in 1993 from $1.17 in 1992. Total revenues for the year increased (6.9%), as did kilowatt-hour sales (3.6%) and the number of customers served (1.4%). These results were assisted by more typical weather experienced in 1993 as compared to 1992. Definition of "service" evolving Our customer base has grown, and so have customer expectations. To meet these expectations, our employees have made a dedicated effort to go beyond the basic requirement of providing a reliable source of electricity to our customers. An example is our personalized energy service program directed to assist customers in their more economical use of energy. During the past year, this program involved our employees in approximately 750 on-site audits for customers and over 6,000 direct mail energy audits. During the past three years, several of our local billing offices have been consolidated to increase operating efficiency, but our local employee base remains a central part of our commitment to customers. By our reliance upon employees who are themselves part of the communities we serve, we believe we are in a position to be more aware of our customers' expectations and to more rapidly respond to their needs on a true neighbor-to- neighbor basis. This is that "little bit extra" to which we believe the customer is entitled, in addition to our creating jobs and contributing to the tax revenues of our service areas. We will continue to look at the dynamics of different population centers for consolidation opportunities, but always with the commitment of the Utility and our employees to remain a meaningful part of the communities we serve. TNP One reflects commitment to customers The TNP One power plant is another example of our efforts to exceed customer expectations. Recognizing that customers want environmental accountability, we selected an innovative clean fuel technology for the Utility's 300-megawatt lignite-fired plant. In June, the National Environmental Development Association awarded the plant its 1993 Honor Roll Award for the selection and successful implementation of circulating-fluidized bed technology. In 1993 TNP One was also honored to be among the superior plants in the State based on nitrous oxide emissions. The first unit of TNP One began commercial operation in September 1990, and the second unit began commercial operation in October 1991. Both units have exceeded their output specifications. The two units produce approximately 30% of the Utility's capacity requirements in Texas. The balance of our customers' requirements are purchased pursuant to negotiated contractual arrangements with third party generators. Parties reach agreement in New Mexico rate application In August 1993, the Utility filed an application to increase its base rate revenues in New Mexico by $1.95 million, or 2.87%, while being able to allow a decrease in overall annualized revenues by $5.13 million for the ultimate benefit to its customers. In January 1994, a unanimous settlement was agreed upon by all parties involved in the rate proceeding. Approval of the settlement by the New Mexico Public Utility Commission would effect an increase in the Utility's annual base rate revenues in New Mexico by approximately $400,000, or 0.57%. In addition, as a result of a scheduled decrease of approximately $7.1 million in firm purchased power costs, New Mexico customers will receive a net decrease in their overall rates. Because such a large part of the total revenue requirements in the Utility's New Mexico operations is related to the cost of purchased power, the Utility's effort in contracting for lower costs of power is a principal reason for the positive result for our customers. Lowering of overall rates for customers while allowing the Utility to recover its reasonable costs of providing service is a prime example of the results we are striving to achieve for the benefit of both our customers and our shareholders. Pending approval of the settlement by the New Mexico Public Utility Commission, the rates are expected to become effective this spring. Quarterly dividends paid to shareholders Despite earnings that were not as high as we would have preferred, the Company continued to pay quarterly dividends of $0.4075 per share of common stock during 1993. Employees' commitment Your Company is committed to addressing the interests of both customers and shareholders. We rely upon our employees as our major resource to achieve this goal, and they continued to meet these challenges with excellence during 1993, although with our labor force reduced 3.2% from 1992 and without cost-of-living wage increases in 1992 or 1993. To our employees, our grateful acknowledgement of your loyalty and achievements. And to our shareholders, our appreciation for your support as we address the tasks at hand. By Order of the Board of Directors March 11, 1994 \s\ Dwight R. Spurlock DWIGHT R. SPURLOCK Interim President and Chief Executive Officer \s\ R. D. Woofter R. D. WOOFTER Chairman of the Board SOURCES OF ENERGY The Utility obtained its electric energy requirements during the year ended December 31, 1993, from sources shown in the table on the next page. The Utility's future load growth is considered by the Utility and its suppliers in planning their future construction expenditures based on projections or official contract notifications furnished to its suppliers by the Utility. Currently the resources of TNP One and the suppliers availability of lignite-, coal-, nuclear-, and gas-fired units are adequate to assure projected requirements for power. To the extent the Utility's suppliers experience delays or increases in the costs of construction of new generating facilities, additional costs of complying with regulatory and environmental laws, or increases in the cost of fuel or shortages in fuel supplies, the availability and cost of energy to the Utility will likewise be affected for that portion of supply purchased by the Utility. The Utility does not expect that the factors discussed in this section will result in the inability of its suppliers to provide the portions of power requirements to be purchased by the Utility. The Utility expects to refund or collect within two months or less those amounts of total purchased power costs (including supplier fuel costs) billed to the Utility from suppliers that are over- or under-collected in the current month. Terminations of service by those suppliers regulated by the Federal Energy Regulatory Commission (El Paso Electric Company, Southwestern Public Service Company, West Texas Utilities Company and Public Service Company of New Mexico) would require authorization by that commission. The Utility anticipates renewing and amending its purchased power contracts with its suppliers as necessary. As a result of the Utility's efforts in contracting for lower costs of purchased power, the Utility's New Mexico customers are expected to benefit from a scheduled decrease of approximately $7.1 million in annualized firm purchased power costs in 1994, the effect of which will be reduced by a $400,000 increase in base rates. In 1990 and 1991, the Utility commenced replacing portions of its Texas purchased power requirements when Unit 1 and Unit 2, respectively, became operational. Beginning in 1992, the full effect of the electric generation of both units was realized. Provisions in the contracts with Texas Utilities Electric Company and Houston Lighting & Power Company allow for reductions in future purchased power commitments. Power generated at TNP One is transmitted over the Utility's own transmission line to other utilities' transmission systems for delivery to the Utility's Texas service area systems. To aid in maintaining a reliable supply of power for its customers and to coordinate interconnected operations, the Utility is a member of the Electric Reliability Council of Texas (ERCOT), the Inland Power Pool and the New Mexico Power Pool. See Management's Discussion and Analysis of Financial Condition and Results of Operations and notes 2 and 5 to the consolidated financial statements for additional information about TNP One. Sources of Energy
Year of Percent Contract of Energy Fuel Sources* Area Served Expiration Required Source TEXAS Generation TNP One Texas Gulf Coast, - 45.2% Texas Lignite Central & (Western Coal, Northern Texas Petroleum Coke & Natural Gas Capabilities) Purchased Power Clear Lake Cogeneration Texas Gulf Coast 2004 23.5 Natural Gas Limited Partnership (Oil Standby) Texas Utilities Electric Company** Central, Northern 2006 & 22.7 Natural Gas, Lignite (Subsidiary of Texas & West Texas 2010 & Nuclear Utilities Company) (Oil Standby) Houston Lighting & Power Texas Gulf Coast 2001 4.0 Natural Gas, Coal, Company (Subsidiary of Lignite, Nuclear Houston Industries, Inc.) & Cogeneration (Oil Standby) West Texas Utilities West Texas 2005 2.5 Natural Gas & Company (Subsidiary Coal of Central and South (Oil Standby) West Corp.) Southwestern Public Texas Panhandle 2005 2.1 Coal & Natural Gas Service Company (Oil Standby) Total 100.0% NEW MEXICO Purchased Power El Paso Electric Southwest 2002 47.9% Coal, Natural Gas, Company New Mexico Oil & Nuclear Southwestern Public South Central 2001 22.2 Coal & Natural Gas Service Company New Mexico (Oil Standby) Public Service South Central & 2006 16.6 Coal, Natural Gas Company of Southwest & Nuclear New Mexico New Mexico (Oil Standby) Other South Central & Various 13.3 Coal, Natural Gas, Southwest Oil & New Mexico Cogeneration Total 100.0% * The Utility also has a continual contract with Union Carbide to provide energy from natural gas sources for the Texas Gulf Coast. This source did not contribute to the percent of energy required in 1993. ** Except as to one point of delivery, a major source of supply under the contract with an expiration date of 2010, the contract expires in 2006.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This discussion presents management's analysis of significant factors in the Company's financial condition and results of operations and should be read in conjunction with the consolidated financial statements and notes thereto. The only business of the Company is conducted by the Utility. The principal effects of nonutility activities on the consolidated financial statements are from short-term investments, certain tax benefits and issuance of the Company's common stock. The Utility and the Company currently face challenges to their financial stability as a result of uncertainties with respect to detrimental regulatory treatment and the servicing of debt incurred for refinancings of both the Unit 1 and the Unit 2 financing facilities. These matters have arisen by reason of the acquisition and operation by the Utility of TNP One, a two-unit, 300-megawatt, lignite-fueled, circulating fluidized bed generating facility located in Robertson County, Texas, and the related rate proceedings in Texas which disallowed recovery in rates of certain costs of TNP One. While the outcome of certain of these matters, and of other matters discussed below, cannot be predicted, the Utility is vigorously pursuing their favorable conclusion. The adverse resolution of certain of the matters discussed below would require a write-off of some portion of the disallowances and could result in a significant negative impact on earnings in the period of final resolution. The following discussion of certain regulatory proceedings related to TNP One is essential to an analysis of the Company's financial condition and results of operations. FINANCIAL CONDITION TNP One Generating Units and Related Regulatory Matters Unit 1 and Unit 2 of TNP One each supply 150 megawatts and together are providing, on an annualized basis, approximately 30% of the Utility's electric capacity requirements in Texas. The Utility operates the two units and sells the output of TNP One to its Texas customers. Unit 1 began commercial operation on September 12, 1990, and Unit 2 on October 16, 1991. As of December 31, 1993, the costs of Unit 1 and Unit 2 were $357 million and $282.9 million, respectively. The costs of the two units were funded principally by separate financing facilities. PUCT Docket No. 9491 On February 7, 1991, in Docket No. 9491, the Public Utility Commission of Texas (PUCT) approved an increase in annualized revenues of approximately $36.7 million, or 67% of the Utility's original $54.9 million rate request, primarily related to Unit 1. The PUCT's final order allowed $298.5 million of the costs of Unit 1 in rate base; however, the PUCT disallowed from rate base $39.5 million of the requested investment costs of $338 million for that unit. On appeal, a State district court overturned the disallowances and ordered the case remanded to the PUCT for further proceedings consistent with the court's judgment. The Utility, the PUCT and certain intervenor cities (Cities) appealed the State district court's judgment to a Texas Court of Appeals. On August 25, 1993, the Court of Appeals rendered a judgment partially reversing the State district court and affirming the PUCT's disallowances for $30.4 million of the total $39.5 million. The Court of Appeals remanded the cause to the district court with instructions that the cause be remanded to the PUCT for proceedings not inconsistent with the appellate opinion. On September 9, 1993, the Utility, the Cities and the PUCT filed motions for rehearing with the Court of Appeals. The PUCT is not expected to act upon the district court's ordered remand until the appellate process, including appeals to the Texas Supreme Court, has been completed. Based upon the opinions of the Utility's Texas regulatory counsel, Johnson & Gibbs, a Professional Corporation, management believes that it will prevail in obtaining a remand of a significant portion of the disallowances in Docket No. 9491; however, the ultimate disposition and quantification of these items cannot presently be determined. Accordingly, no provision for any loss that may ultimately be required upon resolution of these matters has been made in the consolidated financial statements. If the Utility is not successful in obtaining a final favorable disposition in the appellate proceedings relating to the disallowances in Docket No. 9491, a write-off of some portion of the $39.5 million disallowances would be required, which could result in a significant negative impact on earnings in the period of final resolution. For a further discussion of Docket No. 9491, see note 5 to the consolidated financial statements. PUCT Docket No. 10200 On March 18, 1993, in Docket No. 10200, the PUCT approved an increase in annualized revenues of $19 million, or 53% of the Utility's original $35.8 million requested rate increase, primarily related to Unit 2. The PUCT's order determined that the reasonable costs for Unit 2 were $261.8 million. The PUCT allowed in rate base $250.7 million of the $275.2 million requested for Unit 2 costs. The difference between the $261.8 million in costs found to be prudent by the PUCT and the $282.9 million total costs of Unit 2 consisted of disallowances of approximately $21.1 million. The PUCT also determined that $11.1 million of Unit 2 costs would be addressed in a future Texas rate application. The PUCT also disallowed $800,000 of $16.1 million in additional costs requested for Unit 1. The revenue increase approved by the PUCT reflects application to the Utility of a new method for calculating the amount of Federal income tax expense allowed in cost of service, which had the effect of reducing the allowed revenue increase from $26 million to $19 million. The PUCT subsequently approved collection by the Utility of an additional $1.6 million in annualized revenues, subject to refund, on the condition that the Utility seek and receive from the Internal Revenue Service (IRS) a private letter ruling supporting the Utility's position on "normalization" rules with respect to the PUCT order regarding Federal income tax treatment for ratemaking purposes. After receiving PUCT approval on October 19, 1993, the Utility filed, on October 20, 1993, a request with the IRS for a private letter ruling on the issue of a normalization violation. The Utility expects to receive the private letter ruling in 1994. If the private letter ruling supports the Utility's position, the amount of revenues subject to refund ($3.4 million at December 31, 1993) will be recognized in operations upon receipt of the letter. The Docket No. 10200 rate order has been appealed to a Texas district court by the Utility and other parties. Because of the Court of Appeals judgment relating to the prudence of starting construction of Unit 2 (Finding of Fact No. 84 in Docket No. 9491), the presiding judge in the Texas district court for the Docket No. 10200 appeal has ordered that the procedural schedule in this appeal be abated until final resolution of the Finding of Fact No. 84 issue in Docket No. 9491. The Utility will vigorously pursue reversal of the PUCT's new position regarding Federal income tax expenses, in addition to seeking judicial relief from the disallowances and certain other rulings by the PUCT in Docket No. 10200. The opposing parties are seeking a variety of relief to obtain lower rates and greater disallowances, including overturning the basis of the Utility's case as presented to the PUCT and sustaining the PUCT's adverse Federal income tax position without regard to any IRS ruling on the normalization issue. Based upon the opinions of the Utility's Texas regulatory counsel, Johnson & Gibbs, a Professional Corporation, management believes that it will prevail in obtaining a remand of a significant portion of the disallowances in Docket No. 10200; however, the ultimate disposition and quantification of these items cannot presently be determined. Accordingly, no provision for any loss that may ultimately be required upon resolution of these matters has been made in the consolidated financial statements. If the Utility is not successful in obtaining a final favorable disposition in the appellate proceedings relating to the disallowances in Docket No. 10200, a write-off of some portion of the $21.9 million disallowances would be required, which could result in a significant negative impact on earnings in the period of final resolution. For a further discussion of Docket No. 10200, see note 5 to the consolidated financial statements. Other TNP One Matters In November 1987, the Utility entered into a fuel supply agreement with Phillips Coal Company (Phillips), owner of a 300- million-ton lignite reserve in Robertson County in proximity to the TNP One site, to provide a lignite fuel source for the 38-year life of TNP One. Phillips subsequently entered into an agreement with a subsidiary of Peter Kiewit Sons', Inc. for development of the lignite mine by a joint venture partnership, Walnut Creek Mining Company. Unit 1 and Unit 2 are capable of utilizing Western coal, petroleum coke and natural gas as alternative fuel sources. New Mexico Rate Application In August 1993, the Utility filed an application with the New Mexico Public Utility Commission (NMPUC) to increase its base rate revenues in New Mexico by $1.95 million, or 2.87%, and to decrease overall its annualized revenues by $5.13 million. On January 28, 1994, a unanimous settlement was executed by all parties involved in the Utility's New Mexico rate application. The settlement, if approved by the NMPUC, would increase the Utility's annual base rate revenues in New Mexico by approximately $400,000, or 0.57%. However, when a scheduled decrease of approximately $7.1 million in firm purchased power costs is considered with the $400,000 increase in base rates, the Utility's customers will receive a net decrease in their overall rates. The overall rate decrease is influenced by the fact that a large part of the total revenue requirements in the Utility's New Mexico operations is related to the cost of purchased power. The settlement provides rates that have two very positive aspects. First, it allows the Utility to recover through the increase in base rates the current operating cost of providing service to its customers in New Mexico including a reasonable return on the Utility's investments. Second, it lowers the overall rates charged to the Utility's New Mexico customers. Subject to the successful completion of the proceedings before the NMPUC on the settlement, the proposed rates would become effective in the spring of 1994. Consolidated Financial Condition Nonutility operations did not substantially impact the consolidated financial condition in 1993. Nonutility operations from earlier periods allowed tax benefits in 1991 and in 1992 to be carried back to those periods. The Company's capital requirements are primarily those of the Utility as discussed below in "Utility Financial Condition." As a result of the assumption by the Utility of the financing facilities for Unit 1 and Unit 2 in 1990 and 1991, respectively, and related refinancings, the Company's capital structure consisted of 75.2% debt, 23.7% common equity and 1.1% preferred stock at December 31, 1993. Prior to 1990, the Company's capital structure contained less than 50% debt. The Company's long-term goal is to strive for an appropriate capital structure in line with future business activities. (For capital structure ratios for the years 1989 through 1993, see "Selected Annual Consolidated Financial Data" elsewhere in this annual report.) The preferred stock and the debt in the consolidated capital structure were issued by the Utility. Although the Company has the ability to issue both preferred stock and bonds, the Company does not currently expect to issue either. Therefore, the consolidated capital structure will be affected by the ability of the Utility to obtain financing as discussed in "Utility Financial Condition" and by the ability of the Company to issue common stock. Since most of the assets, liabilities and earnings capability of the Company are those of the Utility, the ability of the Company to issue common stock and pay dividends will be largely dependent upon the Utility's operations and the Utility's restrictions regarding payment of its dividends as discussed in "Capital Requirements" under "Utility Financial Condition." The Company has a Shareholder Rights Plan designed to protect the Company's shareholders from coercive takeover tactics and inadequate or unfair takeover bids. See note 1(m) to the consolidated financial statements. Utility Financial Condition Liquidity and Capital Resources Unit 1 and Unit 2 Financing Facilities The Unit 1 and Unit 2 financing facilities were originally entered into by separate subsidiaries of a construction consortium for the construction of Unit 1 and Unit 2 of TNP One. The Unit 1 financing facility was assumed by Texas Generating Company (TGC) on July 20, 1990. The Unit 2 financing facility was assumed by Texas Generating Company II (TGC II) on July 26, 1991. TGC and TGC II are wholly owned subsidiaries of the Utility. As discussed further below, the balance of the secured notes payable of the Unit 1 financing facility and a substantial amount of loans under the Unit 2 financing facility were purchased or prepaid on September 29, 1993 with proceeds from the issuance of new debt securities. Such purchases and prepayments reduced the amounts remaining to be repaid under the Unit 2 financing facility to $147.75 million. Thereafter, the Utility made additional unscheduled prepayments of approximately $69 million under the Unit 2 financing facility; the Utility used existing cash and a $15 million equity contribution from the Company to make these additional prepayments. At December 31, 1993, the Unit 2 financing facility balance was $78.8 million which represents secured notes payable, consisting of a series of renewable loans from various lenders in a financing syndicate. In contemplation of the prepayments of the Unit 1 and Unit 2 financing facilities, the related credit agreements between the secured lenders and the Utility were amended as of September 21, 1993 to facilitate the issuance of the secured debentures, due 2003, and to extend the maturities of the remaining loans from due dates in 1994 and 1995. The effectiveness of the amendments was contingent upon the application of net proceeds from the sale of the secured debentures, due 2003, and the Series U Bonds. The extension of the maturities of the remaining loans to be outstanding under the Unit 2 financing facility has been approved by the Federal Energy Regulatory Commission and is subject to approval by the NMPUC. The Utility expects to receive the necessary approval prior to June 30, 1994, as required by the amendments. Upon the effective date of the extension, the lenders will receive an extension fee of 1/4 of 1% on their pro-rata share of the $147.75 million commitment. Based upon the December 31, 1993 balance and assuming the approval of the extensions of the maturities under the Unit 2 financing facility, $1.6 million will be due on December 31, 1995, $3.4 million will be due on December 31, 1996, with the remaining amounts due in two equal installments of approximately $36.9 million on December 31, 1997 and 1998. Under the amendments to the Unit 2 credit agreement, the Utility is permitted to prepay up to $141.5 million of the $147.75 million commitment under the Unit 2 financing facility and reborrow thereunder up to the amount of such prepayments, subject to scheduled reductions of the commitment of approximately $36.9 million each in 1996, 1997 and 1998. Such reborrowings under the Unit 2 financing facility will be subject to compliance with the EBIT test (as described in note 2 to the consolidated financial statements) and maintenance of an equity to total capital ratio of 20% or more as defined in the credit agreement. As of December 31, 1993, the unused commitment available to be borrowed under the Unit 2 financing facility was approximately $69 million. A commitment fee of 1/4 of 1% per annum is payable on the unused portion of the reducing commitment. The Utility expects to file, during the first half of 1994, a Texas application requesting an increase in annualized revenues. If the Utility receives satisfactory results from the application, the Utility expects to be able to repay the remaining amount due under the Unit 2 financing facility through receipt of common equity from the Company, internal cash generation and issuance of debt. See "Capital Resources" below for a discussion of the Utility's external sources for acquiring capital. Issuance of New Debt Securities On September 29, 1993, the Utility issued $100,000,000 of 9.25% First Mortgage Bonds, Series U (New Bonds), due 2000, and $140,000,000 of 10.75% Secured Debentures, Series A, due 2003. Net proceeds from the issuance of the new securities and existing cash were applied as follows: (i) $21.78 million to call the aggregate principal amount, including redemption premiums, of Series H, I, J and K First Mortgage Bonds, (ii) $9.14 million to reimburse the Utility's treasury for funds used to redeem Series G First Mortgage Bonds at maturity on July 1, 1993, (iii) $146 million to prepay or purchase all of the outstanding secured notes payable to lenders under the Unit 1 financing facility and (iv) $75.75 million to prepay secured notes payable under the Unit 2 financing facility. Redemption of Series H, I, J and K First Mortgage Bonds was necessary to permit the issuance of the $100,000,000 in New Bonds because of certain restrictions under the Utility's first mortgage bond indenture (Bond Indenture), as discussed below. Supplemental indentures relating to Series H, I, J and K First Mortgage Bonds contained a requirement that Net Earnings Available for Interest of the Utility for 12 consecutive months out of the preceding 15 months be at least two-and-one-half (2.5) times the aggregate amount of annual Interest Charges on Bonded Indebtedness which gives effect to the interest on the additional Bonds to be issued (the Interest Coverage Ratio). Under the 2.5 times Interest Coverage Ratio required for issuance of additional First Mortgage Bonds, only a minimal amount of additional First Mortgage Bonds could have been issued. Under the supplemental indentures for the series of Bonds outstanding after the deposit of proceeds from the offering of the new securities for the redemption of Series H, I, J and K Bonds, the Interest Coverage Ratio was reduced to two (2) times. Capital Requirements The Utility's 1993 capital requirements consisted of (1) additions to utility plant and (2) bond sinking fund payments and maturities and preferred stock redemptions. The Utility's cash flows from operations for 1993 were reduced by an $18 million rate refund to the appropriate Texas customers. The refund, discussed in note 5 to the consolidated financial statements, was related to the period from October 1991 through April 1993, during which customers were billed at bonded rates which exceeded the finally authorized rates. During 1993, the Utility's capital requirements were funded with cash flows from operations (after payment of cash dividends on common and preferred stock), excluding the rate refund funded from existing cash. Due to the seasonal nature of the Utility's business, cash flows from operations may fluctuate between quarters, but the Utility expects positive cash flows from operations on an annual basis. During the period from January 1, 1994 to December 31, 1999, the Utility currently estimates that its total debt and preferred stock repayments will be $349.4 million. This amount includes the repayments in 1995, 1996, 1997 and 1998 in discharge of the $78.8 million balance outstanding under the Unit 2 financing facility at December 31, 1993. In addition, the Utility expects its utility plant additions to be approximately $180.9 million during the period from January 1, 1994 to December 31, 1999. The Utility expects the requirements for utility plant additions will be funded internally with cash flows from operations. The amounts and types of the foregoing requirements through 1999, after giving effect to the extensions under the Unit 2 financing facility, assuming pending regulatory approval, are estimated as follows:
Capital Requirements (1) 1994 1995 1996 1997 1998 1999 Total (Dollars in Millions) Preferred stock redemptions $ 0.9 0.9 0.8 0.6 0.6 0.2 4.0 Unit 2 financing facility (2) - 1.6 3.4 36.9 36.9 - 78.8 First Mortgage Bond sinking fund payments and retirements 1.1 1.1 1.1 131.1 1.1 1.1 136.6 Secured Debentures, due 1999 maturity. . . . . - - - - - 130.0 130.0 Total debt and preferred stock repayments. . . . . 2.0 3.6 5.3 168.6 38.6 131.3 349.4 Utility plant additions . . 25.9 28.3 32.7 30.4 31.5 32.1 180.9 Total capital requirements $27.9 31.9 38.0 199.0 70.1 163.4 530.3 (1) See note 2 to the consolidated financial statements for details of the maturities of all outstanding debt. (2) Based upon the balance outstanding at December 31, 1993.
Included in the First Mortgage Bond sinking fund payments and retirements amount for 1997 is $130 million of First Mortgage Bonds, Series T, which mature January 15, 1997. The Utility anticipates that it will refinance these bonds and the Secured Debentures due in 1999 through the issuance of additional First Mortgage Bonds or other debt securities, and/or the receipt of common equity from the Company. The Utility does not need additional Available Additions (described below under "Capital Resources") in order to issue First Mortgage Bonds for the purpose of refunding outstanding First Mortgage Bonds. As a result of the assumption by the Utility of the financing facilities for Unit 1 and Unit 2 in 1990 and 1991, respectively, and related refinancings, the Utility's capital structure consisted of 75.2% debt, 23.7% common equity and 1.1% preferred stock at December 31, 1993. Prior to 1990, the Utility's capital structure contained less than 50% debt. The Utility's long-term goal is to strive for a conservative capital structure with a debt ratio of less than 50%. Capital Resources At any time, the Utility's ability to access the capital markets on a reasonable basis or otherwise obtain needed financing for operating and capital requirements is subject to the receipt of adequate and timely regulatory relief and market conditions. The Utility's ability to access the capital markets at reasonable costs will specifically be impacted by the ultimate resolution of (1) the amount of rate relief granted for Unit 1 and Unit 2, (2) the contested disallowances of up to $40.3 million and $21.1 million of the costs of Unit 1 and Unit 2, respectively, and (3) the adverse PUCT ruling concerning the treatment of the Federal income tax component of the Utility's cost of service. In addition to the aforementioned Unit 2 financing facility, the Utility's external sources for acquiring capital are outlined below: First Mortgage Bonds. Assuming an interest rate of 9.25% and satisfactory market conditions, based upon December 31, 1993 financial information, the Utility could have issued approximately $59 million of additional First Mortgage Bonds under the Interest Coverage Ratio requirement. With certain exceptions, the amount of additional First Mortgage Bonds that may be issued is also limited by the Bond Indenture to a certain amount of physical properties which are to be collateralized by the first lien mortgage of the Bond Indenture (Available Additions). Because of the issuance of the New Bonds in September 1993, the Utility has limited ability to issue additional First Mortgage Bonds until more Available Additions are provided upon further repayment of amounts under the financing facilities. Secured Debentures. The indenture, under which the Series A Secured Debentures were issued, permits, generally, the issuance of additional secured debentures to the extent that the proceeds from such issuance are used to purchase an equal amount of loans under the Unit 1 and Unit 2 financing facilities. Preferred Stock. Due to interest and dividend coverage tests required for issuance of its preferred stock, the Utility cannot presently issue any preferred stock. The Utility does not expect to have the ability to issue preferred stock through 1996. Receipt of Common Equity. One source for repayment of the Unit 2 financing facility is anticipated to be the receipt of common equity from the Company. Receipt of future equity contributions by the Utility from the Company will be largely dependent upon the Company's ability to issue common stock. Since most of the assets, liabilities and earnings capability of the Company are those of the Utility, the ability of the Company to issue common stock and pay dividends will be largely dependent upon the Utility's operations and the Utility's restrictions regarding payment of cash dividends on its common stock. The Utility may not pay dividends on its common stock unless all past and current dividends on outstanding preferred stock of the Utility have been paid or declared and set apart for payment and all requisite sinking or purchase fund obligations for the preferred stock of the Utility have been fulfilled. Charter provisions relating to the preferred stock and the Bond Indenture under which First Mortgage Bonds are issued contain restrictions regarding the retained earnings of the Utility. At December 31, 1993, pursuant to the terms of the Bond Indenture, approximately $12.8 million of the Utility's $38.9 million of retained earnings was restricted. In addition, the financing facilities place certain restrictions on the Utility's ability to pay dividends on its common stock, unless certain threshold tests are met. The Utility has satisfied the threshold tests since they became effective, and the Utility does not expect that any of the aforementioned contractual restrictions on the payment of dividends will become operative in 1994. However, the Utility can give no assurance that the Utility will satisfy such tests in the future. The Utility's 1993 common stock dividends of $17.3 million exceeded 1993 earnings available for common stock of $10.6 million; however, the Utility's retained earnings were sufficient to allow the dividends to be paid. Contributing to the low-level of earnings in 1993 were the lower rates from the December 1992 adverse ruling of the PUCT regarding the Utility's Federal income tax component in its cost of service and significant interest charges. As discussed in "Net Earnings" under "Results of Operations", management has implemented cost saving measures during 1993 and is seeking equitable regulatory treatment in efforts to improve future results of operations. Cash dividend payments are subject to approval of the Board of Directors and are dependent, especially in the longer term, on the Utility's and the Company's future financial condition and adequate and timely regulatory relief, including favorable resolution of pending judicial appeals of rate cases. Other Matters Accounting for Postretirement Benefits On January 1, 1993, the Utility implemented Statement of Financial Accounting Standards No. 106 (SFAS 106), "Employers' Accounting for Postretirement Benefits Other Than Pensions," which addresses the accounting for other postretirement employee benefits (OPEBs). For the Utility, OPEBs are comprised primarily of health care and death benefits for retired employees. Prior to 1993, the costs of these OPEBs were expensed on a "pay-as-you-go" basis. Beginning in 1993, SFAS 106 requires a change from the "pay-as-you- go" basis to the accrual basis of recognizing the costs of OPEBs during the periods that employees render service to earn the benefits. The 1993 accrual for OPEBs of $2,952,000, based on adoption of SFAS 106, was $2,276,000 greater than the amount that would have been recorded under the "pay-as-you-go" basis. In March 1993, the PUCT issued its rules for ratemaking treatment of OPEBs. As part of a general rate case, a utility may request OPEBs expense in cost of service for ratemaking purposes on an accrual basis in accordance with generally accepted accounting principles. The PUCT's rule requires that the amounts included in rates shall be placed in an irrevocable external trust fund dedicated to the payment of OPEBs expenses. Based on the PUCT's rule, the Utility intends to seek recovery of OPEBs expense attributable to its Texas jurisdiction in its next Texas rate case. In order to comply with the PUCT's condition for possible recovery of OPEBs expenses, the Utility established in June 1993 a Voluntary Employees' Beneficiary Association (VEBA) trust fund, dedicated to the payment of OPEBs expenses. Monthly cash payments made to the VEBA, which began in June 1993, will fund OPEBs costs for the Utility's Texas and New Mexico operations. See note 1(j) to the consolidated financial statements for information about the funded status of the plan. On August 23, 1993, the Utility filed a rate application with the NMPUC which included a request for recovery of the applicable costs of OPEBs. A stipulated agreement among the parties to the proceeding, dated January 28, 1994, subject to approval by the NMPUC, would include such applicable costs in the proposed New Mexico rates, beginning in 1994. For future periods, the costs of OPEBs will be affected by changes in the assumed interest rate and the trends in health care costs; based on actuarial assumptions, national health care costs are expected to increase in the future, resulting in further increases in the Utility's costs. Accounting for Income Taxes On January 1, 1993, the Company implemented Statement of Financial Accounting Standards No. 109 (SFAS 109), "Accounting for Income Taxes." The implementation of SFAS 109 did not result in any significant charge to operations. See note 4 to the consolidated financial statements for details relating to the implementation of SFAS 109. Accounting for Postemployment Benefits The FASB has issued Statement of Financial Accounting Standards No. 112 (SFAS 112), "Employers' Accounting for Postemployment Benefits" which addresses the accounting and reporting for the estimated costs of benefits provided by an employer to former or inactive employees after employment but before retirement. SFAS 112 is effective for fiscal years beginning after December 15, 1993. The Utility estimates such costs to be immaterial. Effects of Inflation The Company does not believe that the effects of inflation, as measured by the Consumer Price Index over the last three years, have had a material impact on the Company's consolidated results of operations and financial condition. Tax Law Change The Omnibus Budget Reconciliation Act of 1993 was signed into law on August 10, 1993. Beginning in 1994, the act provides for the disallowance of certain business deductions, the effect of which is not expected to be material for the Company. The act also provided, effective January 1, 1993, for a corporate income tax rate increase from 34% to 35% to be phased in for taxable income between $10 million and $18 million. RESULTS OF OPERATIONS Consolidated The Company and its subsidiaries, the Utility, Bayport Cogeneration, Inc. and TNP Operating Company, combined to produce consolidated earnings available for common stock and earnings per share of common stock for each of the years shown as follows: 1993 1992 1991 Earnings Available for Common Stock (In Thousands) Utility operations $10,644 9,877 18,762 Nonutility operations 82 85 (307) Total $10,726 9,962 18,455 Earnings Per Share of Common Stock Utility operations $ 1.00 1.16 2.27 Nonutility operations .01 .01 (.04) Total $ 1.01 1.17 2.23 The following table sets forth the percentage relationship of items to operating revenues in the consolidated statements of earnings: 1993 1992 1991 Operating revenues 100.0% 100.0 100.0 Operating expenses: Power purchased for resale 42.2 39.3 49.1 Fuel 9.4 10.1 5.8 Other operating and general expenses 14.6 15.8 14.8 Maintenance 2.4 2.6 2.5 Depreciation of utility plant 7.6 7.9 6.4 Taxes, other than on income 6.4 6.6 5.4 Income taxes 0.9 0.4 1.8 Total operating expenses 83.5 82.7 85.8 Net operating income 16.5 17.3 14.2 Other income, net of taxes 0.2 0.6 0.1 Earnings before interest charges 16.7 17.9 14.3 Total interest charges 14.3 15.4 9.9 Net earnings 2.4% 2.5 4.4 Utility Operations Operating Revenues Operating revenues for 1993 and 1992 reflect increases of $30,415,000 and $2,484,000 over the respective prior years. The following table presents the components of the changes in operating revenues: Increase (Decrease) From Prior Year 1993 1992 (Dollars In Thousands) Base operating revenues $(1,515) (0.3)% $35,785 8.1% Recovery of purchased power costs 25,926 5.8 (42,561) (9.6) Recovery of fuel costs (1,230) (0.3) 19,204 4.4 Customer usage 8,291 1.9 (11,746) (2.7) Other revenues (1,057) (0.2) 1,802 0.4 Total $ 30,415 6.9% $ 2,484 0.6% Base operating revenues are affected primarily by changes in base rates resulting from regulatory commission orders and the effects of variations in sales between customer classifications. The significant increase in base operating revenues for 1992 was primarily attributable to bonded rates for Docket No. 10200 being placed into effect in October 1991. The PUCT's final order approving these rates was received on October 16, 1992 and subsequently was amended by the PUCT in an Order on Rehearing on December 22, 1992. The result of this Order on Rehearing was to lower the previously approved increase in annualized revenues by approximately $7 million, from $26 million to approximately $19 million. The PUCT later increased, subject to refund, the annualized revenues by an additional $1.6 million. Because the increase continued to be subject to a possible refund, no additional revenues were recognized in 1992 or 1993 and such amounts were included in revenues subject to refund in the consolidated balance sheets. For more information regarding Docket No. 10200, see note 5 to the consolidated financial statements. Purchased power costs are recovered through cost recovery factor clauses in both Texas and New Mexico. Fuel costs are recovered through a fixed fuel factor approved by the PUCT. Recoveries of purchased power and fuel costs are discussed further in "Operating Expenses." Customer usage increased in 1993 due to a 3.6% increase in kilowatt-hour (KWH) sales to residential, commercial and industrial customers. The residential usage increase related to an increase in the number of residential customers and warmer temperatures in the Texas service areas; in 1992, milder than normal weather was experienced in the Texas service areas. Commercial usage increased in the Utility's Texas service areas as the result of general retail development in the Northern Division and Southeast Division and the addition of a greyhound race track in the Southeast Division. During 1993, the number of industrial customers decreased by 14, but that decrease included the consolidation of 10 customers into 2 customers for billing purposes and the reclassification of 3 customers to the commercial class of customers. The industrial usage increase in the Utility's New Mexico service area resulted from increased consumption of an existing mining customer and the addition of a new mining customer. The 1992 decrease in customer usage primarily reflected a 5.46% KWH sales decline. Part of the decrease in customer usage was attributable to the milder than normal temperatures experienced in Texas during 1992. Also contributing to the sales decline was the failure of new customers and revenues to materialize as expected within the industrial class to ameliorate the loss of KWH sales to certain industrial customers. From time to time, industrial customers of the Utility express interest in cogeneration as a method of reducing or eliminating reliance upon the Utility as a source of electric service, or to lower fuel costs and improve operating efficiency of process steam generation. During 1993, a major industrial customer in the Utility's Southeast Division requested proposals for a cogeneration project for evaluation by the customer. The Utility's operating revenues from this customer during 1993 were approximately $28 million. In January 1994, a potential developer for the proposed project was selected by the customer. The Utility's goal is to retain this customer and to lower overall system operating costs through coordination with the potential developer. Although the Utility cannot predict the ultimate outcome of the process, the current project as proposed by the customer, and as outlined by the potential developer, appears to present a means by which the Utility may retain electric service to this customer, at current levels. The Utility is actively pursuing the development of the necessary agreements with the potential developer to further define the degree to which electric service to this customer is retained and overall system operating costs may be lowered. For information relating to actual KWH sales, number of customers, and revenues, see "Selected Electric Operating Statistics" elsewhere in this report. Operating Expenses As a regulated entity, the Utility must demonstrate to the regulatory commissions in its rate filings that its requests for recovery of operating expenses to provide service to its customers are reasonable and necessary. In order to provide reliable service to its customers at reasonable rates, management endeavors to control costs through budgeting and monitoring of operating expenses. Commencement of commercial operations of Unit 1 in September 1990 and Unit 2 in October 1991 led to increases in certain expenses and interest charges over prior years; however, the Utility experienced decreases in the potential cost of power purchased for resale as a result of the operations of Unit 1 and Unit 2. The 1993 and 1992 levels of expenses each reflect a full year's operations of both units. Variances in expenses from 1991 to 1992 due to a partial year's operation of Unit 2 in 1991 are noted in the following discussion. Power Purchased for Resale Factors affecting the expense of power purchased for resale are (1) the number of KWH purchased from suppliers, (2) the cost per KWH purchased, (3) the recovery or refund of prior under- or over-collections, respectively, of purchased power costs (deferred purchased power costs), and (4) occasional fuel cost refunds from the Utility's suppliers. The Utility's policy regarding the accounting for deferred purchased power costs is discussed in note 1(g) to the consolidated financial statements. Power purchased for resale increased $25,926,000 in 1993, and a decrease of $42,561,000 was experienced in 1992. The increase in purchased power expense for 1993 was mainly due to an increase in the average cost of KWH purchased from suppliers. Information concerning the Utility's suppliers is disclosed in "Sources of Energy," elsewhere in this report. Also contributing to the increase in 1993 was an increase in the number of KWH purchased as a result of increased customer usage, discussed under "Operating Revenues." The decrease in 1992 resulted from a decline in the number of KWH purchased. This KWH decrease was caused by the replacement of purchased power with a full year's generation of Unit 2 of TNP One and the decrease in customer usage, discussed under "Operating Revenues." Partially offsetting the effect of this reduction in the number of KWH purchased in 1992 was an increase in the recovery of deferred purchased power costs. As in 1992, the 1993 level of KWH purchases reflects a full year's generation of TNP One; therefore, KWH purchases for 1993 and 1992 are comparable in this respect. No significant changes in KWH purchased resulting from TNP One's operations are expected in the future. While costs per KWH from purchased power suppliers are not directly controllable, wholesale rates charged by various suppliers are subject to regulatory authority. The Utility has intervened and will continue to intervene in suppliers rate cases for the purpose of assuring fair and equitable costs to its customers. Fuel Fuel expense decreased $629,000 in 1993, as compared to an increase of $19,204,000 in 1992. The decrease in recovery of fuel costs for 1993 resulted from a slightly lower fuel cost recovery factor than that utilized in 1992. These differing fuel factors resulted from using a factor related to bonded rates in 1992 which was adjusted downward in 1993 to comply with the final order in Docket No. 10200. The large increase in 1992 was related to a full year's commercial operation of both Unit 1 and Unit 2. Fuel expense primarily represents the recovery of fuel costs through a fixed fuel factor set by the PUCT. The fixed fuel factor is intended to permit the Utility to recover the cost of fuel utilized to generate electricity sold in Texas. The factor may be changed only upon approval of the PUCT and is expected to be adjusted for any cumulative under- or over-recovery of fuel costs. At December 31, 1993, the Utility had under-recovered fuel costs, including interest, of approximately $13.6 million related to both units of TNP One. Any requests to the PUCT for recovery of fuel costs require the Utility's demonstration that the costs were reasonable. Beginning in 1993, a filing with the PUCT for a reconciliation of fuel costs is required if for any given period of time there is an over-or under-recovery of fuel costs of at least 4% of revenues. Under the PUCT's rules, the months in which utilities may initiate fuel reconciliation proceedings are specified; for the Utility, these months are June and December. In the event of an over- or under-recovery of fuel costs less than the 4% threshold, a filing to adjust the fuel factor may be made at the discretion of management. The Utility expects to file a fuel reconciliation with its next Texas rate application during the first half of 1994. Management will continue to monitor its fuel cost recovery to determine the need to request a change in its fixed fuel factor. For a discussion of the fuel supply agreement for TNP One, see "Other TNP One Matters" under "Financial Condition." Other Operating and General Expenses and Maintenance Other operating and general expenses decreased $597,000 in 1993 after an increase of $4,716,000 in 1992. The 1993 decrease represents primarily decreases in employee pension and thrift benefits and payroll costs which were offset somewhat by an increase in employee postretirement medical costs resulting from implementation of SFAS 106. The decrease in the employee benefits for 1993 was due to an amendment to the pension plan and the curtailment of employer thrift plan contributions on January 1, 1993. Payroll costs declined due to a 3.2% reduction in the number of employees. The increase in other operating and general expenses for 1992 was due primarily to additional wheeling costs which were incurred for a full year's transfer of power generated by Unit 2 and to amortization of previously deferred rate case expenses. Wheeling costs are incurred for the transfer of TNP One power over other utilities' transmission systems for delivery to the Utility's Texas systems. The years 1993 and 1992 reflected wheeling costs for both Unit 1 and Unit 2; therefore, any future changes in this level of expense would be the result of changes in monthly wheeling charges. Regarding deferred rate case expenses, a full year's amortization was reflected in both 1993 and 1992, making them comparable in this respect; in 1994, another year's amortization remains for the deferred rate case expenses. As previously discussed under "Financial Condition," implementation of SFAS 106 may lead to additional costs in the future. Other operating and general expenses will be affected in 1994 because of a 3% cost-of-living payroll adjustment for full-time employees effective January 10, and the restoration of employer thrift plan contributions scheduled to resume beginning July 1. Since the last cost-of-living payroll adjustment granted to the Utility's employees was in 1991, these changes were made to maintain the level of experienced personnel necessary for providing quality service to the Utility's customers. No significant variances have occurred in maintenance expense over the last three years. Maintenance outages are scheduled in the first and fourth quarters of 1994 for Unit 2 and Unit 1, respectively. Since prior years reflect expenses for past scheduled outages of the units, no significant increase in maintenance expense is anticipated in 1994. Depreciation of Utility Plant Depreciation expense increased $917,000 and $7,071,000 in 1993 and 1992, respectively. The 1993 increase was related to normal additions to utility plant while the large increase in 1992 reflects a full year's expense for Unit 2 and Unit 1. Future increases in depreciation would be the result of normal utility plant additions and regulatory approvals of changes in depreciation rates as supported by required periodic independent studies. Taxes, Other Than On Income Taxes, other than on income increased $1,046,000 and $5,462,000 in 1993 and 1992, respectively. The 1993 increase related primarily to an increase in revenue-related taxes which resulted from increased revenues upon which the taxes are based. The increase in 1992 was primarily related to an increase in property-related taxes resulting from (1) a full year's expense related to Unit 2 as compared to only a partial year in 1991 and (2) increases in the property tax rates in Texas. Income Taxes Income taxes increased $2,397,000 in 1993 after a decrease of $5,963,000 in 1992. The increase in 1993 resulted from an increase in earnings over 1992, a decline in the regulatory-ordered amortization of excess deferred taxes, and an increase in Federal income tax rates. Income taxes decreased in 1992 due to the decline in net earnings compared to 1991. For the years 1993, 1992 and 1991, the Utility incurred tax net operating losses due to accelerated tax depreciation deductions and increased interest charges on debt related to TNP One and subsequent refinancings; however, payments of current income taxes were required based on minimum tax (MT) requirements. To the extent that the Utility is subject to MT requirements and limitations on the utilization of available credits, payments of current Federal income taxes are expected to be required in 1994. As discussed in "Accounting for Income Taxes" under "Financial Condition," implementation of SFAS 109 did not result in any significant charge to earnings. For information regarding the Company's income taxes, see note 4 to the consolidated financial statements. As with all areas of the Utility's cost of service, recovery of income tax expenses is expected in rates charged to customers. However, as discussed in "PUCT Docket No. 10200" under "Financial Condition," uncertainties exist with respect to the Utility's Federal income tax expense component of cost of service. The Utility is pursuing reversal of the PUCT's adverse decisions. Other Income, Net of Taxes The Utility's contribution to other income, net of taxes increased in 1992 by $1,290,000 primarily because of interest earned on short-term investments, principally repurchase agreements and government money trusts, during the year. Considerable cash was used in 1993 to make optional payments under the Unit 2 financing facility thereby reducing cash available for the aforementioned investments. This contributed to the decrease of $901,000 in 1993. (For a discussion of nonutility operations contribution to other income, see "Nonutility Operations.") Interest Charges Total interest charges decreased slightly by $342,000 in 1993 after an increase of $24,723,000 in 1992. The slight decrease in interest on long-term debt in 1993 was the net result of several transactions. Decreases in 1993 expense resulted from (1) redemption of Series G First Mortgage Bonds at maturity on July 1, 1993, (2) redemption of Series H, I, J and K First Mortgage Bonds to permit issuance of Series U First Mortgage Bonds and (3) prepayments made under the Unit 1 and Unit 2 financing facilities. Partially offsetting these decreases in interest on long-term debt were the issuances of Series U First Mortgage Bonds and Series A Secured Debentures in September 1993. Interest on long-term debt increased in 1992 due to the issuance in January 1992 of $130 million of 11.25% Series T First Mortgage Bonds and $130 million of 12.50% Secured Debentures, due in 1999. The Utility used $194 million of the proceeds from the issuance to retire a portion of the Unit 1 and Unit 2 financing facilities, as was required for extended payment dates under the amended terms of the financing facilities. The notes payable under the financing facilities had lower interest rates than the new securities. Interest charges also increased in 1992 due to the debt for Unit 2 being outstanding for a full year as compared to a partial year in 1991. In 1994, the full effects of the 1993 redemptions and new issuances are expected to result in a net increase in interest on long-term debt. Any changes in the interest rates or balances related to the Unit 2 financing facility in 1994 will also have an effect on long-term debt interest. Other interest and amortization of debt discount, premium and expense for 1993 reflects a fourth quarter amortization of debt expense associated with the issuances of Series U Bonds and Series A Secured Debentures and further amendments to the Unit 1 and Unit 2 financing facilities; therefore, an increase in this expense can be expected in 1994 due to a full year's amortization. In 1993, other interest included interest on the provision for a refund of bonded revenues billed in excess of the amounts allowed under Docket No. 10200. Other interest and amortization of debt discount, premium and expense increased during 1992 primarily as the result of the issuances of the Series T Bonds and Secured Debentures, due 1999 discussed above, as well as the amortization of expenses related to the amendments of the Unit 1 and Unit 2 financing facilities. Other interest expense increased due to the accrual of interest on the provision for a refund of bonded revenues billed in excess of the amounts allowed in Docket No. 10200. Partially offsetting these increases was a decrease in interest on unsecured notes payable to banks. The Utility utilized a portion of the proceeds from the issuance of the Series T Bonds and Secured Debentures, due 1999 to retire $26 million of unsecured notes payable to banks. The remaining $10 million portion of such notes was retired in August 1992. Allowance for borrowed funds used during construction (AFUDC) decreased in 1992 when compared to 1991 because Unit 2 was placed in commercial operation on October 16, 1991. AFUDC for 1991 reflected primarily the qualified capitalization of interest on the financing facility for Unit 2 from the date of assumption (July 26, 1991) until the date Unit 2 began commercial operation. The Utility's receipt of equity contributions and proceeds from future issuances of debt securities are anticipated to help satisfy the scheduled repayments of the Unit 2 financing facility. Interest rates on debt securities are expected to be greater than those interest rates under the financing facility. Interest rates on additional debt may be further increased if the Utility's outstanding regulatory matters are not satisfactorily resolved. Net Earnings The Utility's contribution to consolidated net earnings increased $678,000 in 1993 after a significant decline of $8,995,000 in 1992. The decline in the Utility's contribution to consolidated net earnings in 1992 was due primarily to (1) the decrease in customer usage as discussed in "Operating Revenues," (2) the PUCT's abandonment of its long-standing methodology for determination of the Federal income tax expense component of cost of service in the PUCT's Order on Rehearing in Docket No. 10200 and (3) the increases in interest expense. The slight increase in 1993 resulted from increased KWH sales, the effect of which was reduced by increases in depreciation expense, taxes, other than on income and income taxes and a decrease in other income as previously discussed. The level of 1993 contribution to net earnings also reflects the adverse tax ruling by the PUCT, discussed above in "PUCT Docket No. 10200" under "Financial Condition." Early in 1993, the Utility implemented cost saving measures such as (1) suspension of the Utility's matching contributions to the employees thrift plan, (2) revision to the Utility's pension plan and (3) implementation of a general employee salary and wage freeze and limitations on hiring new employees and replacements. These cost saving measures more than offset the increase in expenses related to the health care and death benefits plans resulting from implementation of SFAS 106. With the exception of the Utility's wage-step progression increases reactivated in April 1993, these measures continued in effect throughout 1993. The Utility reduced its labor force by 3.2% during 1993, trimming $1.1 million from operations and maintenance expenses. Even so, the Utility's return on common equity for 1993 and 1992 was 4.97% and 4.80%, respectively, although the Utility's rate of return granted in Docket No. 10200 authorized a return on common equity of 13.16%. Based on the Utility's earnings for 1993 and 1992 and the expected increases in interest on long-term debt and certain other expenses, equitable rate relief in Texas appears to be necessary for any significant improvement in financial results to occur during 1994. Future regulatory treatment and court decisions regarding Docket Nos. 9491 and 10200, as previously discussed, will have a direct bearing on future earnings. Nonutility Operations Contributions to earnings from nonutility operations during 1993 and 1992 were principally from short-term investment activities and, during 1993, a refund of a portion of state franchise tax paid by the Company in prior periods. Due to the Company's equity contribution to the Utility in November 1993, the Company's short-term investments declined during 1993. Nonutility operations are reflected in other income, net of taxes in the consolidated statements of earnings. The contributions from nonutility operations to consolidated earnings are not expected to increase until such time as nonutility operations include new business that generates earnings; however, presently the Company has no specific plans for new business. INDEPENDENT AUDITORS' REPORT The Shareholders and Board of Directors TNP Enterprises, Inc.: We have audited the accompanying consolidated balance sheets of TNP Enterprises, Inc. and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of earnings, common stock equity and redeemable cumulative preferred stocks, and cash flows for each of the years in the three-year period ended December 31, 1993. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of TNP Enterprises, Inc. and subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 1993, in conformity with generally accepted accounting principles. As discussed in note 5 to the consolidated financial statements, uncertainties exist with respect to the outcome of certain regulatory matters. The ultimate outcome of these matters cannot presently be determined. Accordingly, no provision for any loss that may ultimately be required upon resolution of these matters has been made in the accompanying consolidated financial statements. As discussed in note 4 to the consolidated financial statements, the Company changed its method of accounting for income taxes in 1993 to adopt the provisions of the Financial Accounting Standards Board's Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes. As discussed in note 1(j), the Company also adopted the provisions of the Financial Accounting Standards Board's SFAS No. 106, Employers Accounting for Postretirement Benefits Other Than Pensions in 1993. KPMG PEAT MARWICK Fort Worth, Texas January 28, 1994 CONSOLIDATED FINANCIAL STATEMENTS Consolidated Statements of Earnings Three Years Ended December 31, 1993
1993 1992 1991 (In Thousands Except Per Share Amounts) Operating revenues (note 5) $474,242 443,827 441,343 Operating expenses: Power purchased for resale 200,183 174,257 216,818 Fuel 44,348 44,977 25,773 Other operating and general expenses (note 1(j)) 69,406 70,003 65,287 Maintenance 11,460 11,342 11,225 Depreciation of utility plant 36,015 35,098 28,027 Taxes, other than on income 30,296 29,250 23,788 Income taxes (note 4) 4,294 1,897 7,860 Total operating expenses 396,002 366,824 378,778 Net operating income 78,240 77,003 62,565 Other income, net of taxes (note 4) 1,306 2,210 528 Earnings before interest charges 79,546 79,213 63,093 Interest charges: Interest on long-term debt 63,833 63,893 44,919 Other interest and amortization of debt discount,premium and expense 4,411 4,539 3,266 Allowance for borrowed funds used during construction (303) (149) (4,625) Total interest charges 67,941 68,283 43,560 Net earnings 11,605 10,930 19,533 Dividends on preferred stocks 879 968 1,078 Earnings available for common stock $ 10,726 9,962 18,455 Weighted average number of common shares outstanding 10,641 8,545 8,275 Earnings per share of common stock $ 1.01 1.17 2.23 Dividends per share of common stock $ 1.63 1.63 1.63 See accompanying notes to consolidated financial statements.
CONSOLIDATED BALANCE SHEETS December 31, 1993 and 1992 1993 1992 (In Thousands) ASSETS Utility plant, at original cost (notes 2,5): Electric plant $1,203,636 1,184,635 Construction work in progress 5,282 3,922 1,208,918 1,188,557 Less accumulated depreciation 202,923 172,848 Net utility plant 1,005,995 1,015,709 Nonutility property, at cost 1,673 1,322 Current assets: Cash and cash equivalents 12,423 86,785 Customer receivables 764 122 Refundable income taxes - 2,636 Inventories, at the lower of average cost or market: Fuel 1,422 1,246 Materials and supplies 7,793 7,185 Deferred purchased power and fuel costs 15,151 17,735 Accumulated deferred taxes on income (note 4) 4,251 - Other current assets 1,071 545 Total current assets 42,875 116,254 Regulatory tax assets (note 4) 16,915 - Deferred charges (note 4) 37,779 49,422 $1,105,237 1,182,707 CAPITALIZATION AND LIABILITIES Capitalization: Common stock equity: Common stock, no par value per share. Authorized 50,000,000 shares; issued 10,695,860 shares in 1993 and 10,597,564 shares in 1992 $ 131,615 129,914 Retained earnings (note 3) 82,012 88,621 Total common stock equity 213,627 218,535 Redeemable cumulative preferred stocks (note 3) 9,560 10,440 Long-term debt, net of amount due within one year (note 2) 678,994 742,087 Total capitalization 902,181 971,062 Current liabilities: Long-term debt due within one year 1,070 10,288 Accounts payable 22,450 25,809 Accrued interest 16,115 8,869 Accrued taxes (note 4) 17,221 22,243 Customers' deposits 4,464 4,236 Revenues subject to refund (note 5) 3,400 17,515 Other current and accrued liabilities 13,412 8,029 Total current liabilities 78,132 96,989 Customers' advances for construction 169 311 Regulatory tax liabilities (note 4) 20,412 - Accumulated deferred taxes on income (note 4) 85,995 93,879 Accumulated deferred investment tax credits (note 4) 18,348 20,466 Commitments and contingencies (note 5) $1,105,237 1,182,707 See accompanying notes to consolidated financial statements.
Consolidated Statements of Common Stock Equity and Redeemable Cumulative Preferred Stocks Three Years Ended December 31, 1993
Common Stock Equity Redeemable Cumulative Common Stock Retained Preferred Shares Amount Earnings Total Stocks (In Thousands) Year ended December 31, 1991: Balance, January 1, 1991 8,238 $ 84,462 87,377 171,839 12,600 Net earnings for the year 19,533 19,533 Dividends on preferred stocks (1,078) (1,078) Dividends on common stock - $1.63 per share (13,485) (13,485) Sale of common stock 80 1,527 1,527 Purchase and retirement of preferred stocks - 1,200 shares 4.65% Series B, 600 shares 4.75% Series C, 1,200 shares 11% Series D, 600 shares 11% Series E, 1,200 shares 11% Series F and 8,000 shares 11.875% Series G 52 52 (1,280) Balance, December 31, 1991 8,318 85,989 92,399 178,388 11,320 Year ended December 31, 1992: Net earnings for the year 10,930 10,930 Dividends on preferred stocks (968) (968) Dividends on common stock - $1.63 per share (13,780) (13,780) Sale of common stock 2,280 43,925 43,925 Purchase and retirement of preferred stocks - 1,200 shares 4.65% Series B, 600 shares 4.75% Series C, 1,200 shares 11% Series D, 600 shares 11% Series E, 1,200 shares 11% Series F and 4,000 shares 11.875% Series G 40 40 (880) Balance, December 31, 1992 10,598 129,914 88,621 218,535 10,440 Year ended December 31, 1993: Net earnings for the year 11,605 11,605 Dividends on preferred stocks (879) (879) Dividends on common stock - $1.63 per share (17,344) (17,344) Sale of common stock 98 1,701 1,701 Purchase and retirement of preferred stocks - 1,200 shares 4.65% Series B, 600 shares 4.75% Series C, 1,200 shares 11% Series D, 600 shares 11% Series E, 1,200 shares 11% Series F and 4,000 shares 11.875% Series G 9 9 (880) Balance, December 31, 1993 10,696 $131,615 82,012 213,627 9,560 See accompanying notes to consolidated financial statements.
Consolidated Statements of Cash Flows Three Years Ended December 31, 1993 1993 1992 1991 (In Thousands) Cash flows from operations: Net earnings $ 11,605 10,930 19,533 Items not requiring cash: Depreciation of utility plant 36,015 35,098 28,027 Amortization of debt expense, discount and premium, and other deferred charges 4,939 5,667 1,227 Allowance for borrowed funds used during construction (303) (149) (4,625) Deferred taxes on income 5,534 541 19,370 Investment tax credit adjustments (953) (2,479) (10,825) Changes in certain current assets and liabilities: Customer receivables (642) 1,784 (1,097) Refundable income taxes 2,636 14,732 Inventories (784) (451) 113 Deferred purchased power and fuel costs 2,584 (5,493) (8,202) Other current assets (203) 659 723 Accounts payable (3,359) (2,007) 3,271 Accrued interest 7,246 2,256 (1,865) Accrued taxes (3,729) 5,542 7,377 Customers' deposits 228 284 55 Revenues subject to refund (14,115) 15,961 1,554 Other current and accrued liabilities 5,383 (1,553) (2,332) Other - net (1,384) (4,042) (9,511) TOTAL 50,698 62,548 57,525 Cash flows from investing activities: Additions to utility plant, net of capitalized depreciation and interest (25,998) (22,098) (29,931) Additions to deferred charges (362) (312) (12,605) TOTAL (26,360) (22,410) (42,536) Cash flows from financing activities: Dividends on preferred and common stocks (18,223) (14,748) (14,563) Issuances: Common stock 1,701 43,925 1,527 Long-term debt 240,000 271,500 32,000 Deferred expenses associated with financings (8,940) (9,124) - Redemptions: Preferred stocks (880) (880) (1,280) Long-term debt (312,358) (245,498) (574) Short-term debt - (36,000) (5,900) TOTAL (98,700) 9,175 11,210 Net change in cash and cash equivalents (74,362) 49,313 26,199 Cash and cash equivalents at beginning of year 86,785 37,472 11,273 Cash and cash equivalents at end of year $ 12,423 86,785 37,472 Supplemental disclosures of cash flow information: Cash paid during the years for: Interest (net of amount capitalized) $ 59,028 62,130 41,708 Income taxes 3,263 1,230 847 See accompanying notes to consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1993, 1992 and 1991 (1) Summary of Significant Accounting Policies (a) Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, Texas- New Mexico Power Company (Utility), Bayport Cogeneration, Inc. and TNP Operating Company. The Utility has two wholly owned subsidiaries, Texas Generating Company (TGC) and Texas Generating Company II (TGC II). All intercompany transactions and balances have been eliminated in consolidation. The principal subsidiary is the Utility. The Utility is a public utility engaged in the generation, purchase, transmission, distribution and sale of electricity within the states of Texas and New Mexico. The Utility is subject to regulation by the Public Utility Commission of Texas (PUCT) and the New Mexico Public Utility Commission (NMPUC). The Utility is subject in some of its activities, including the issuance of securities, to the jurisdiction of the Federal Energy Regulatory Commission (FERC), and its accounting records are maintained in accordance with the FERC's Uniform System of Accounts. TGC and TGC II were incorporated in Texas in 1988 and 1991, respectively, as financing entities for the assumption of ownership and liabilities related to two 150-megawatt lignite-fueled generating units, Unit 1 and Unit 2, respectively, collectively referred to as TNP One. The units were constructed by a nonaffiliated consortium in Robertson County, Texas, and are operated by the Utility under the terms of operating agreements between the Utility and its subsidiaries. Notes 2 and 5 provide additional information about the financings and regulatory treatments of Unit 1 and Unit 2. (b) Utility Plant The costs of additions to utility plant and replacement of retired units of property are capitalized. Costs include labor, materials and similar items and indirect charges for such items as engineering, supervision and transportation. Property repairs and replacement of minor items of property are included in maintenance expense. The cost of depreciable units of plant retired or disposed of in the normal course of business is eliminated from utility plant accounts, and such cost plus removal expenses less salvage is charged to accumulated depreciation. When complete operating units are disposed of, appropriate adjustments are made to accumulated depreciation, and the resulting gains or losses, if any, are recognized. (c) Depreciation Depreciation is provided on a straight-line basis over the estimated service lives of the properties. Depreciation of utility plant, other than transportation equipment, is charged to earnings. Depreciation of transportation equipment is charged to earnings and property accounts in accordance with the equipment's use. Depreciation as a percentage of average depreciable cost was 3.00%, 3.10% and 3.17% in 1993, 1992 and 1991, respectively. (d) Unamortized Debt Expense, Discount and Premium on Debt Expenses incurred in connection with the issuance of outstanding long-term debt and discount and premium related to such debt are amortized on a straight-line basis over the lives of the respective issues. (e) Revenues and Purchased Power Revenues are recognized on the basis of meter readings which are made on a monthly cycle. The Utility does not accrue revenues for power sold but not billed at the end of an accounting period. Power purchased is recorded on the basis of billings from suppliers; no accrual is made for power delivered to the Utility between the dates of such billings and the end of an accounting period. (f) Customer Receivables The Utility sells customer receivables to a nonaffiliated company on a nonrecourse basis. (g) Deferred Purchased Power and Fuel Costs The deferral method of accounting is used for the portions of purchased power and fuel costs which are recoverable in subsequent periods under purchased power costs recovery adjustment clauses. These clauses provide the ability to refund or collect, in the second succeeding month, those amounts of purchased power costs over- or under-collected in the current month. At December 31, 1993 and 1992, the Utility had under-recovered purchased power costs of approximately $1,520,000 and $6,640,000, respectively. At December 31, 1993 and 1992, the Utility also had under-recovered fuel costs of approximately $13,631,000 and $11,095,000, respectively, related to TNP One. A fixed fuel factor approved by the PUCT is intended to permit the Utility to recover the cost of fuel utilized to generate electricity sold in Texas. The factor may be changed only upon approval of the PUCT and is expected to be adjusted for any cumulative over- or under-recovery of fuel costs. (h) Allowance for Borrowed Funds Used During Construction The applicable regulatory uniform system of accounts defines allowance for funds used during construction as including the net cost during the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used. In that connection, the Utility used an accrual rate of 7.53% in 1993, 5.8% in 1992 and 8.0% in 1991 for borrowed funds used during construction, excluding capitalized interest related to the financing facilities. Capitalized interest related to the financing facility for Unit 2 (note 2) was approximately $4,234,000 in 1991. Interest was capitalized from the date of assumption of the Unit 2 indebtedness, July 26, 1991, until the date on which Unit 2 began commercial operation, October 16, 1991. (i) Income Taxes The Company and its subsidiaries account for certain income and expense items differently for financial reporting purposes than for income tax purposes. Provisions for deferred income taxes are made for such differences. As discussed in note 4, the Company changed its method of accounting for income taxes in 1993 to adopt the provisions of the Financial Accounting Standards Board's Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes." Investment tax credits utilized are deferred and amortized to earnings ratably over the estimated service lives of the related assets. (j) Employee Benefit Plans The Utility has in effect a trusteed defined benefit retirement plan available to employees who are 21 years of age and over and have at least one year of service with the Utility. The Utility's funding policy is to contribute annually at least the minimum amount required by government funding standards, but not more than that which can be deducted for Federal income tax purposes. The net pension costs for 1993, 1992 and 1991 included the following components:
1993 1992 1991 (In Thousands) Service cost $1,472 2,148 1,914 Interest cost on projected benefit obligation 4,191 4,504 4,197 Reduction for actual return on plan assets (6,126) (5,071) (12,276) Other - net 300 258 7,706 $ (163) 1,839 1,541
The following table is a summary of the plan's funded status at December 31, 1993 and 1992:
1993 1992 (In Thousands) Plan assets (principally marketable securities) at estimated fair value $69,763 66,643 Projected benefit obligation (including accumulated benefit obligations for 1993 and 1992 of approximately $55,509,000 and $43,894,000, respectively) (60,618) (58,190) 9,145 8,453 Unrecognized net asset (171) (198) Unrecognized prior service cost (2,990) 3,668 Unrecognized net gain (9,554) (15,657) Net pension liability (included in other current and accrued liabilities in the consolidated balance sheets) $ (3,570) (3,734)
The weighted average discount rate and the rate of increase in future compensation levels used in determining the actuarial present value of the projected benefit obligation were 7.15% and 4.15%, respectively, for 1993 and 8.5% and 5.75%, respectively, for 1992. The weighted average expected long-term rate of return on plan assets for 1993 and 1992 was 9.5%. The vested benefit obligations at December 31, 1993 and 1992, were approximately $50,457,000 and $39,757,000, respectively. The defined benefit retirement plan was amended to change, for all participants retiring after December 31, 1992, the determination of average monthly compensation used in calculating the amount of retirement benefits from the average of the three highest consecutive calendar years to the average of the completed calendar years of compensation after 1992. The Utility has a voluntary thrift plan, administered by a trustee, with a provision for the Utility to contribute to the plan amounts equal to certain percentages of amounts contributed by employees. Employees have the option of investing their contributions and contributions of the Utility, if any, in either, or a combination of, certain government securities, the Company's common stock or, since January 1, 1992, two mutual funds. Effective January 1, 1992, the plan calls for the Utility's contributions to be used to purchase the Company's common stock which the employees may later convert into investments in one or more of the other investing options. Effective January 1, 1993, the Utility suspended its matching contributions to the thrift plan for an indefinite period; however, the Utility's Board of Directors has approved restoration of the Utility's matching contributions, to be effective for employee contributions made after June 30, 1994. The Utility's contributions to the thrift plan amounted to approximately $1,592,000 and $1,487,000 in 1992 and 1991, respectively. Thrift plan assets included 1,471,213 shares and 1,482,490 shares of the Company's common stock at December 31, 1993 and 1992, respectively. On November 9, 1993, the Board of Directors of the Utility renewed forms of employment contracts between the Utility and its officers and its other key personnel. The principal purpose of the contracts is to encourage retention of management and other key personnel required for the orderly conduct of the business of the Utility during any threatened or pending acquisition of the Company or the Utility and during any transition of ownership. The terms of the contracts, from date of execution, are three years as to certain officers and managers of the Utility and two years as to the other key personnel. Upon the expiration date of each contract, the Utility, at its option, may extend the contract for additional three or two year periods, as appropriate. The contracts provide for lump sum compensation payments and other rights to the officers and the other key personnel in the event of termination of employment or other adverse treatment of such persons following a "change in control" of the Company or the Utility, which event is defined to include, among other things, substantial changes in the corporate structure or ownership of either entity or in the Board of Directors of either entity. Health care and death benefits and an excess benefit plan have been provided at minimal or no cost to retired employees. The excess benefit plan is provided under an insurance policy arrangement and is backed by a letter of credit which will be funded only if a change in control occurs. On January 1, 1993, the Utility implemented Statement of Financial Accounting Standards No. 106 (SFAS 106), "Employers' Accounting for Postretirement Benefits Other Than Pensions," which addresses the accounting for other postretirement employee benefits (OPEBs). For the Utility, OPEBs are comprised primarily of health care and death benefits for retired employees. Prior to 1993, the costs of these OPEBs were expensed on a "pay-as-you-go" basis. For 1992, these costs were approximately $760,000. Beginning in 1993, SFAS 106 requires a change from the "pay-as-you-go" basis to the accrual basis of recognizing the costs of OPEBs during the periods that employees render service to earn the benefits. SFAS 106 also requires employers to recognize the costs of benefits already earned by active employees and retirees at the date of adoption of SFAS 106 (the transition obligation). For the Utility, an annual accrual for OPEBs is comprised of (1) the portion of the expected postretirement benefit obligation attributed to employee service during that period (the service cost), (2) amortization of the transition obligation and (3) the interest costs associated with the total unfunded accumulated obligation for future benefits. For 1993, these costs amounted to approximately $508,000, $934,000 and $1,510,000, respectively. This total cost of $2,952,000 based on adoption of SFAS 106 was $2,276,000 greater than the amount of $676,000 that would have been recorded under the "pay-as-you-go" basis. The assumed health care cost trend rate used to measure the expected cost of benefits was 11.5% for 1993 and is assumed to diminish to 8.4% for 1994, then trend downward slightly each year to a level of 6% for 2003 and thereafter. The Utility's remaining transition obligation of $17,750,000 at December 31, 1993 is to be amortized over a remaining nineteen-year period. A 1% increase in the assumed health care cost trend rate would result in (1) an increase of $3,235,000 in the Utility's accumulated benefit obligation at December 31, 1993 and (2) an increase of $538,000 for 1993 in the aggregate service and interest costs. In March 1993, the PUCT issued its rules for ratemaking treatment of OPEBs. As part of a general rate case, a utility may request OPEBs expense in cost of service for ratemaking purposes on an accrual basis in accordance with generally accepted accounting principles. The PUCT's rule includes recovery of the transition obligation and requires that the amounts included in rates shall be placed in an irrevocable external trust fund dedicated to the payment of OPEBs expenses. Based on the PUCT's rule, the Utility intends to seek recovery of OPEBs expense attributable to its Texas jurisdiction in its next Texas rate case. In order to comply with the PUCT's condition for possible recovery of OPEBs expenses, the Utility established in June 1993 a Voluntary Employees Beneficiary Association (VEBA) trust fund, dedicated to the payment of OPEBs expenses. Monthly cash payments made to the VEBA, which began in June 1993, will fund the three OPEBs expense components of the Utility's total Texas and New Mexico operations. On August 23, 1993, the Utility filed a rate application with the NMPUC which included a request for recovery of the applicable costs of OPEBs. A stipulated agreement among the parties in the application, dated January 28, 1994, subject to approval by the NMPUC, would include such applicable costs in the proposed New Mexico rates, beginning in 1994. The following table presents the plan's funded status reconciled with amounts recognized in the consolidated balance sheets at December 31, 1993 and 1992:
1993 1992 (In Thousands) Accumulated postretirement benefit obligation: Retirees and dependents $(15,828) (13,604) Active employees (7,671) (5,080) (23,499) (18,684) Plan assets at fair value 1,297 - Accumulated postretirement benefit obligation in excess of plan assets (22,202) (18,684) Unrecognized net loss 3,533 - Unrecognized transition obligation 17,750 18,684 Accrued postretirement benefit cost included in other current and accrued liabilities $ (919) -
The discount rate used in determining the acutuarial present value of the accumulated post retirement benefit obligation was 7.15% and 8.50% for 1993 and 1992, respectively. (k) Fair Values of Financial Instruments The fair value amounts of certain financial instruments included in the accompanying consolidated balance sheets at December 31, 1993 and 1992 were as follows: * The fair value of cash and cash equivalents approximates the carrying amount because of the short maturity of those instruments. * The total estimated fair value of long-term debt was approximately $723 million and $755 million in 1993 and 1992, respectively. The total estimated fair value of preferred stocks was $7.6 million and $7.7 million in 1993 and 1992, respectively. The estimated fair values of long-term debt and preferred stocks were based on quoted market prices of the same or similar issues. (l) Statements of Cash Flows For purposes of the consolidated statements of cash flows, the Company considers temporary cash investments with original maturities of three months or less to be cash equivalents. On July 26, 1991, TGC II assumed ownership of TNP One, Unit 2 and assumed the related liabilities totaling approximately $269 million. In addition, approximately $12 million of deferred charges related to TNP One, Unit 2 was reclassified to utility plant. During 1992, the Utility reclassified approximately $12 million of deferred charges to utility plant. On January 1, 1993, the Utility recognized certain assets and liabilities and certain reclassifications as a result of implementation of Statement of Financial Accounting Standards No. 109 (SFAS 109). See note 4 for further discussion of SFAS 109, including amounts of these transactions. (m) Shareholder Rights Plan The Company has a Shareholder Rights Plan (Rights Plan) that is designed to protect the Company's shareholders from coercive takeover tactics and inadequate or unfair takeover bids. The Rights Plan, adopted in 1988 and amended on November 13, 1990, by the Company's Board of Directors, provides for the distribution of one right for each share of the Company's common stock held of record as of the close of business on November 4, 1988 and for each share of common stock issued thereafter until November 4, 1998. Each right entitles the shareholder to elect to exercise the right in whole or in part to purchase, upon the occurrence of certain events, one share of common stock at an initial price of $45 per share or, under certain circumstances, shares of common stock at half the then-current market price or, with an election to exercise such rights without payment of cash, to receive the number of shares of the Company's common stock or other securities having an aggregate value equal to the excess of (i) the value of the common stock or other securities on the date of the exercise of the rights over (ii) the cash payment that would have been payable upon the exercise of the rights if an election for cash payment had been made. Until certain triggering events occur, the rights will trade together with the Company's common stock and separate rights certificates will not be issued. Among the triggering events are the acquisition by a person or group of persons of 10% or more of the Company's outstanding common stock or the commencement of a tender or exchange offer which, upon consummation, would result in a person or group of persons owning 15% or more of the Company's outstanding common stock. The rights expire November 4, 1998, unless earlier redeemed or exchanged by the Company, and have had no effect on earnings per share. (n) Common Stock At December 31, 1993, 425,189 shares of the Company's common stock were reserved for issuance to the Utility's Employees Thrift Plan. Additionally, 417,991 shares of the Company's common stock were reserved for subsequent issuance to the Company's shareholders under a Dividend Reinvestment and Stock Purchase Plan. (o) Earnings Per Share Earnings per share of common stock are computed for each year based upon the weighted average number of common shares outstanding. Net earnings are reduced for preferred dividend requirements. (2) Long-term Debt Long-term debt outstanding was as follows:
1993 1992 (In Thousands) First mortgage bonds: Series G, 4.700% due 1993 $ - 9,138 Series H, 4.950 due 1995 - 3,700 Series I, 6.075 due 1996 - 3,750 Series J, 9.000 due 1999 - 7,800 Series K, 8.500 due 2001 - 6,400 Series L, 10.500 due 2000 9,840 9,960 Series M, 8.700 due 2006 8,400 8,500 Series R, 10.000 due 2017 63,700 64,350 Series S, 9.625 due 2019 20,000 20,000 Series T, 11.250 due 1997 130,000 130,000 Series U, 9.250 due 2000 100,000 - Total 331,940 263,598 Unamortized discount, net of premium (676) (723) First mortgage bonds, net 331,264 262,875 Secured debentures: 12.50% due 1999 130,000 130,000 Series A, 10.75% due 2003 140,000 - 270,000 130,000 Secured notes payable 78,800 359,500 Total long-term debt 680,064 752,375 Less long-term debt due within one year (1,070) (10,288) Total long-term debt, net $678,994 742,087
Issuance of Additional First Mortgage Bonds and Secured Debentures On September 29, 1993, the Utility issued $100 million of 9.25% First Mortgage Bonds, Series U, due September 15, 2000 (New Bonds), and $140 million of 10.75% Secured Debentures, Series A, due September 15, 2003 (Debentures, due 2003). After fees and expenses, combined net proceeds available to the Utility from the issuances of the New Bonds and the Debentures, due 2003, and existing cash were utilized as follows: (a) $146 million was used to prepay or purchase all of the outstanding secured notes payable to lenders under the Unit 1 financing facility, as discussed below; (b) $75.75 million was used to prepay secured notes payable under the Unit 2 financing facility, as discussed below; (c) $21.78 million was deposited for the call for redemption of the aggregate principal amount, including redemption premiums, of Series H, I, J and K First Mortgage Bonds; and (d) $9.14 million was used to reimburse the Utility's treasury for funds used to redeem Series G First Mortgage Bonds at maturity on July 1, 1993. Supplemental indentures relating to Series H, I, J and K First Mortgage Bonds contained a requirement that Net Earnings Available for Interest of the Utility for 12 consecutive months out of the preceding 15 months be at least two-and-one-half (2.5) times the aggregate amount of annual Interest Charges on Bonded Indebtedness which gives effect to the interest on the additional Bonds to be issued (the Interest Coverage Ratio). Under the 2.5 times Interest Coverage Ratio required for issuance of additional First Mortgage Bonds, only a minimal amount of additional First Mortgage Bonds could have been issued. Under the supplemental indentures for the series of Bonds outstanding after the deposit of proceeds from the offering for the redemption of Series H, I, J and K Bonds, the Interest Coverage Ratio was reduced to two (2) times. The maturity of Series G Bonds on July 1, 1993, and the call for redemption of Series H, I, J and K Bonds permitted the issuance of additional Bonds and consummation of the offering of $100 million of New Bonds. Amendments to the Financing Facilities At December 31, 1992, secured notes payable represented loans issued under two financing facilities, which were originally entered into by separate subsidiaries of a construction consortium, for the construction of Unit 1 and Unit 2 of the TNP One generating plant. The Unit 1 financing facility was assumed by TGC on July 20, 1990. The Unit 2 financing facility was assumed by TGC II on July 26, 1991. On September 29, 1993, the balance of the secured notes payable under the Unit 1 financing facility was purchased or prepaid, and $75.75 million of secured notes payable under the Unit 2 financing facility was prepaid, reducing that outstanding commitment to $147.75 million; funds used for these prepayments and purchases were provided from issuance of the New Bonds and the Debentures, due 2003, and from existing cash, as discussed above. Thereafter, the Utility made additional unscheduled prepayments of approximately $69 million under the Unit 2 financing facility. The $78.8 million balance at December 31, 1993 represents secured notes payable under the Unit 2 financing facility, consisting of a series of renewable loans from various lenders in a financing syndicate. In contemplation of the prepayments of the Unit 1 and Unit 2 financing facilities, the related credit agreements between the secured lenders and the Utility were amended as of September 21, 1993 to facilitate the issuance of the Debentures, due 2003, and to extend the maturities of the remaining loans from due dates in 1994 and 1995. The effectiveness of the amendments was contingent upon the application of proceeds from the sale of the Debentures, due 2003, and the New Bonds. The extension of the maturities of the remaining loans to be outstanding under the Unit 2 financing facility is subject to further approvals from the FERC and the NMPUC. The Utility expects to receive the necessary approvals within the period required by the amendments. Upon the effective date of the extension, the lenders will receive an extension fee of 1/4 of 1% on their pro-rata share of the $147.75 million commitment. Based upon the December 31, 1993 balance and assuming the regulatory approvals of the extensions of the maturities under the Unit 2 financing facility, $1.6 million will be due on December 31, 1995, $3.4 million will be due on December 31, 1996, with the remaining amounts due in two equal installments of approximately $36.9 million on December 31, 1997 and 1998. Under the amendments to the Unit 2 credit agreement, the Utility is permitted to prepay up to $141.5 million of the $147.75 million commitment under the Unit 2 financing facility and reborrow thereunder up to the amount of such prepayments, subject to scheduled reductions of the commitment of approximately $36.9 million each in 1996, 1997 and 1998. Such reborrowings under the Unit 2 financing facility will be subject to compliance with the EBIT test (as described below) and maintenance of an equity to total capital ratio of 20% or more as defined in the credit agreement. As of December 31, 1993, the unused commitment available to be borrowed under the Unit 2 financing facility was approximately $69 million. A commitment fee of 1/4 of 1% per annum is payable on the unused portion of the reducing commitment. The financing facilities contain certain covenants which, under specified conditions, restrict the payment of cash dividends on common stock of the Utility. The most restrictive of such covenants are an interest coverage test and an equity ratio test. Under the interest coverage test, the Utility may not pay cash dividends on its common stock unless its prior twelve months earnings (exclusive of any writedowns resulting from actions of the PUCT, to the extent included in operating expenses) before interest and income taxes equals or exceeds the sum of all of the interest expense on indebtedness for the same period (said calculation, the EBIT Test). This restriction becomes effective only after the third consecutive calendar quarter during which the Utility does not meet the EBIT Test and continues in effect until after the quarter in which the Utility has met the twelve-month EBIT Test. The Utility has met the EBIT Test at each quarterly date since this test became effective. Under the recently required equity ratio test, the Utility may not pay cash dividends on its common stock if, at the preceding quarterly date, the Utility's ratio of equity capitalization to total capitalization is less than 20%. As of December 31, 1993, this test was met. Under the two financing facilities, interest rates were determined under several alternative methods. During 1993, all rates at the time of each borrowing were no higher than the prime lending rate plus a margin of 1 3/8%. The effective costs of borrowing under the secured notes payable were 7.23% and 5.61% at December 31, 1993 and 1992, respectively. Under the amended Unit 2 financing facility, the margins will increase by 1/2 of 1% each year in 1994 and 1995 and by 1/4 of 1% each year in 1996, 1997 and 1998. Additional Information Substantially all utility plant owned directly by the Utility is subject to the first lien of the Utility's first mortgage bond indenture, as supplemented (the Bond Indenture). Until repaid, the holders of the secured notes payable and of the secured debentures have a lien junior to the first lien of the Bond Indenture on substantially all utility plant in Texas owned directly by the Utility. The Debentures, due 2003, are secured by a pledge by the Utility to the new debenture trustee of a replacement note (1993 Unit 1 Replacement Note) in an amount equal to the principal amount of the Debentures, due 2003, purchased by the Utility from secured lenders under the Unit 1 financing facility. The 1993 Unit 1 Replacement Note is secured ratably by the original Unit 1 First Lien Mortgage of the Unit 1 financing facility on the assets of TGC, the existing second mortgage lien on the Utility's Bond Indenture trust estate assets in Texas and certain other collateral. The Debentures, due 2003, rank pari passu with the outstanding secured debentures, due 1999, in their Unit 1 mortgage lien on the assets of TGC and other security interests. The secured debentures, due 1999, are secured ratably by a 1992 Unit 1 replacement note and a 1992 Unit 2 replacement note ($65 million each), which are in turn secured by first liens on the assets of TGC and TGC II, respectively, and by the existing second mortgage lien on the Utility s Bond Indenture trust estate assets in Texas and certain other collateral. Under the terms of each financing facility, the secured notes payable and the replacement notes are secured by related first liens on Unit 1 and Unit 2 until undivided interests in Unit 1 and Unit 2 have been purchased from TGC and TGC II, respectively, by the Utility, whereupon such undivided interests become subject to the lien of the Bond Indenture. In connection with the prepayments of the secured notes payable under the Unit 1 and Unit 2 financing facilities in September 1993, the Utility purchased from TGC and TGC II certain undivided direct interests in Unit 1 and Unit 2, respectively; accordingly, these interests were released from the first liens of the financing facilities. These purchases were in addition to interests in Unit 1 acquired by the Utility in 1992 and 1990. As of December 31, 1993, TGC owns a 205/345 undivided interest in Unit 1 with the remaining fractional interest being owned directly by the Utility. (The denominator of 345 represents the historical maximum balance of $345 million that was originally borrowed under the Unit 1 financing facility; the numerator of 205 represents $205 million of replacement notes secured by the Unit 1 First Lien Mortgage.) TGC's interest in Unit 1 is subject to the lien of the Unit 1 First Lien Mortgage, which secures equally and ratably the 1993 Unit 1 replacement note of $140 million and the 1992 Unit 1 replacement note of $65 million. As of December 31, 1993, TGC II owns a 212.75/288.50 undivided interest in Unit 2 with the remaining fractional interest being owned directly by the Utility. (The denominator of 288.50 represents the historical maximum balance of $288.50 million that was originally borrowed under the Unit 2 financing facility; the numerator of 212.75 represents $212.75 million of debt and available loan commitment that remains secured by the Unit 2 First Lien Mortgage.) TGC II's interest in Unit 2 is subject to the lien of the Unit 2 First Lien Mortgage, which secures all remaining secured notes payable outstanding under the Unit 2 financing facility and the 1992 Unit 2 replacement note of $65 million. During the repayment periods, the Utility will operate and finance Unit 1 and Unit 2. Under the terms of each financing facility, upon or after each repayment of construction debt or replacement notes by TGC or TGC II through financings by the Utility, the Utility may purchase a proportionate undivided direct interest in the respective unit from TGC or TGC II to the extent such purchase is necessary to enable the Utility to issue, from time to time, first mortgage bonds. Upon such purchase, the undivided interest will be released from the lien of such unit's financing facility. In any event, the Utility may not purchase and the respective subsidiary may not transfer any undivided interest which would cause the fraction of the undivided interest remaining subject to the lien of the respective financing facility to be less than a certain fraction. The numerator of such fraction is the sum of (a) the unused commitment provided by lenders and the outstanding principal amounts owed to the lenders under such financing facility and (b) the principal amount of the respective replacement notes held as security for secured debentures. The denominator of such fraction is (i) $345 million under the Unit 1 financing facility and (ii) $288.5 million under the Unit 2 financing facility. The Utility guarantees the obligations of TGC and TGC II under each respective financing facility. The Utility expects, assuming adequate regulatory treatment, to be able to repay the remaining amount due under the Unit 2 financing facility primarily through the receipt of common equity from the Company, internal cash generation and issuance of debt. Based upon the December 31, 1993 balance and assuming the approvals of the extensions of the maturities of secured notes payable under the Unit 2 financing facility, maturities and sinking fund requirements for the Utility's long-term debt for the five years following 1993 are as follows:
First Mortgage Secured Notes Bonds Payable (In Thousands) 1994 $ 1,070 - 1995 1,070 1,600 1996 1,070 3,400 1997 131,070 36,900 1998 1,070 36,900
(3) Redeemable Cumulative Preferred Stocks Redeemable cumulative preferred stocks (authorized 1,000,000 shares at $100 par value per share) issued by the Utility and outstanding at December 31, 1993 and 1992, with related redemption prices (at the Utility's option), were as follows:
Shares Outstanding Total Par Value Redemption Price (In Thousands) (In Thousands) Series 1993 1992 1993 1992 1993 1992 B 4.650% $100.000 100.000 25.2 26.4 $2,520 2,640 C 4.750 100.000 100.000 14.4 15.0 1,440 1,500 D 11.000 101.570 102.090 3.2 4.4 320 440 E 11.000 101.570 102.090 1.6 2.2 160 220 F 11.000 101.570 102.090 3.2 4.4 320 440 G 11.875 106.927 107.422 48.0 52.0 4,800 5,200 95.6 104.4 $9,560 10,440
On October 1 of each year, the Utility is required to offer to purchase from the holders of shares in Series B and Series C, at a price not exceeding $100 per share plus accrued dividends, a number of shares equal to 2% of the maximum number of shares of each series outstanding at any one time prior to August 15 of such year. In addition, the Utility is required to redeem, at a price of $100 per share plus accrued dividends, 1,200 shares each of Series D and F and 600 shares of Series E on each March 15 through March 1, 1996. The requirement to redeem such shares is cumulative and totals $300,000 on an annual basis. On each June 15 through June 15, 2008, the Utility is required to redeem 4,000 shares of Series G at a price of $100 per share plus accrued dividends; the requirement to redeem such shares is cumulative. The holders of Series G and/or the Utility separately have the noncumulative option for redemption of an additional 4,000 shares on each June 15 at a price of $100 per share plus accrued dividends. Charter provisions relating to the preferred stocks and the Bond Indenture under which the bonds are issued contain restrictions as to the payment of cash dividends on common stock of the Utility. At December 31, 1993, the amount of restricted retained earnings was approximately $12,800,000. As discussed in note 2, terms for additional restrictions as to the payment of common dividends became effective during 1992 and 1993 as a result of the amended terms of the Unit 1 and Unit 2 financing facilities. In the event of voluntary liquidation of the Utility, holders of the preferred stocks have a preference to the extent of amounts payable on redemption, and in the event of involuntary liquidation, to the extent of par plus accrued dividends. The Company has authorized, but unissued, 5,000,000 shares of no par value per share cumulative preferred stock. (4) Income Taxes Income taxes as set forth in the consolidated statements of earnings consisted of the following components: 1993 1992 1991 (In Thousands) Charged (credited) to operating expenses: Current: Federal $ (356) 655 (2,652) State 94 339 435 (262) 994 (2,217) Deferred Federal income taxes 5,515 1,347 12,946 Investment tax credit adjustments: Investment tax credits made available through net operating loss carrybacks - - (1,911) Investment tax credits utilized 89 607 66 Amortization of accumulated deferred investment tax credits (1,048) (1,051) (1,024) (959) (444) (2,869) Total 4,294 1,897 7,860 Charged (credited) to other income: Current - Federal 641 1,114 150 Deferred Federal income taxes 19 2,060 8,080 Investment tax credit adjustments: Investment tax credits made available through net operating loss carrybacks - (2,035) (7,956) Investment tax credits utilized 6 - - 6 (2,035) (7,956) Total 666 1,139 274 Total income taxes $4,960 3,036 8,134
The provisions for deferred income taxes for 1992 and 1991 resulted from the following timing differences: 1992 1991 (In Thousands) Charged (credited) to operating expenses: Tax depreciation in excess of book depreciation $13,615 19,540 Deferred charges and other costs expensed for tax purposes, net 674 1,943 Deferred purchased power and fuel costs expensed for tax purposes 1,765 2,049 Unbilled revenues for tax purposes 519 (1,778) Accrual for revenues subject to refund (5,069) - Minimum tax credit (2,608) (8,085) Amortization of excess deferred taxes (1,153) (810) Change in deferred taxes due to tax net operating loss (6,256) - Other (140) 87 1,347 12,946 Charged (credited) to other income: Recognition of deferred income taxes 6,256 - Minimum tax credit (4,196) 8,080 2,060 8,080 Total $ 3,407 21,026
Total income tax expense for 1993, 1992 and 1991 was less than the amount computed by applying the appropriate statutory Federal income tax rate to income before income taxes. The reasons for the differences were as follows: 1993 1992 1991 (In Thousands) Income tax expense at statutory rate $ 5,601 4,633 9,259 Amortization of accumulated deferred investment tax credits (1,048) (1,051) (1,024) Amortization of excess deferred taxes (142) (1,153) (810) Effect of tax rate change 235 - - State income tax 94 339 435 Other - net 220 268 274 $ 4,960 3,036 8,134
The Omnibus Budget Reconciliation Act of 1993 (Act) was signed into law on August 10, 1993. Among other provisions, the Act provided, effective January 1, 1993, for a corporate income tax rate increase from 34% to 35% to be phased in for taxable income between $10 million and $18 million. Adjustments have been made to deferred tax amounts to reflect the future reversal of temporary differences at the higher tax rate. Under transitional rules of the Tax Reform Act of 1986, certain capital expenditures incurred after December 31, 1985 continued to qualify for investment tax credits (ITC). Accordingly, ITC adjustments reflect credits for the utilized portion of ITC generated in 1990 associated with ITC applicable to transitional property. The Company has ITC carryforwards for Federal income tax purposes of approximately $17,400,000 which are available to reduce future Federal income taxes through 2005. The Company generated a Federal minimum tax (MT) for the year ended December 31, 1993. The MT resulted in a net current Federal income tax expense of approximately $285,000, after utilization of ITC. At December 31, 1993, the Company has a net operating loss (NOL) carryforward for Federal income tax purposes of approximately $28,600,000 which is available to offset future Federal taxable income through 2008. In addition, the Company has minimum tax credit carryforwards of approximately $10,100,000 which are available to reduce future Federal regular income taxes over an indefinite period. In order to fully realize the Federal regular tax NOL carryforwards, the Company will need to generate future taxable income of approximately $28,600,000 prior to expiration of the Federal regular tax NOL carryforwards which will expire in 2008. Based on the Company's historical and projected pretax earnings, management believes it is more likely than not that the Company will realize the benefit of the Federal regular tax NOL carryforward existing at December 31, 1993 before such carryforward expires in 2008. In addition, the remaining deferred tax assets, exclusive of the MT credit carryforwards, are considered current and expected to reverse in the next twelve months. The Company's consolidated Federal income tax returns for the years 1987 through 1989 have been examined by the Internal Revenue Service resulting in a revenue agent report (RAR). The Company's carryforwards referred to above and the accompanying consolidated financial statements reflect adjustments resulting from the RAR. The RAR had no effect on the Company's results of operations. On January 1, 1993, the Company implemented Statement of Financial Accounting Standards No. 109 (SFAS 109), "Accounting for Income Taxes." Prior to implementation of SFAS 109, the Company accounted for income taxes under Accounting Principles Board Opinion No. 11 (APB 11). Implementation of SFAS 109 changed the method of accounting for income taxes from the deferred method required under APB 11 to the asset and liability method. Under the deferred method, annual income tax expense was matched with pretax accounting income by providing deferred taxes at the then current tax rates for timing differences between pretax accounting income and taxable income. The objective of the asset and liability method is to establish deferred tax assets and liabilities for the temporary differences between the financial reporting basis and the tax basis of assets and liabilities at enacted tax rates expected to be in effect when such temporary differences are realized or settled. The Company elected to implement SFAS 109 on a prospective basis. SFAS 109 provides that regulated enterprises are allowed to recognize adjustments resulting from the adoption of SFAS 109 as regulatory tax assets or liabilities if such amounts are probable of being recovered from or returned to customers through future rates. Deferred taxes recorded under APB 11 were attributable primarily to differences associated with book and tax depreciation. Temporary differences under SFAS 109 include all items considered timing differences under APB 11, as well as certain new items including (1) a reduction in the depreciable tax basis due to ITC, (2) ITC accounted for under the deferred method and (3) prior flow-through treatment of tax benefits. Adoption of SFAS 109 has affected the consolidated balance sheet due to deferred Federal income tax effects for temporary differences associated with prior flow-through ratemak ing accounting practices, treatment of tax rate changes and unamortized ITC. Unamortized ITC represent amounts being shared with customers as future revenue requirements are reduced by the amortization of accumulated deferred ITC. This gives rise to a corresponding regulatory liability to reflect the ratemaking treatment. SFAS 109 requires the recognition of regulatory and deferred tax assets and liabilities for the cumulative unrecognized temporary differences. The result as of January 1, 1993 of implementing SFAS 109 was as follows:
December 31, Reclassi- January 1, 1992 fications 1993 (In Thousands) Assets: Deferred charges $ 49,422 (20,262) 29,160 Regulatory tax assets - 17,974 17,974 Accumulated deferred taxes on income - current - 6,006 6,006 $ 49,422 3,718 53,140 Liabilities: Accrued taxes $ 22,243 (3,756) 18,487 Accumulated deferred taxes on income - noncurrent 93,879 (15,719) 78,160 Regulatory tax liabilities - 23,193 23,193 $116,122 3,718 119,840
The above reclassifications resulted from the recognition of regulatory and deferred tax assets and liabilities for the cumulative unrecognized temporary differences and reclassification of certain other balances to comply with the provisions of SFAS 109. The implementation of SFAS 109 did not result in any significant charge to operations. The tax effects of temporary differences that gave rise to significant portions of net current accumulated deferred taxes on income and net noncurrent accumulated deferred taxes on income at December 31, 1993 are presented below (in thousands): Current accumulated deferred taxes on income: Deferred tax assets: Unbilled revenues $ 6,914 Revenues subject to refund 1,053 Other 1,435 9,402 Deferred tax liability - Deferred purchased power and fuel costs (5,151) Current accumulated deferred taxes on income, net $ 4,251 Noncurrent accumulated deferred taxes on income: Deferred tax assets: Minimum tax credit carryforwards $ 10,067 Federal regular tax NOL carryforwards 10,005 Other 1,036 21,108 Deferred tax liabilities: Utility plant, principally due to depreciation and capitalized basis differences (101,839) Deferred rate case expenses (2,553) Deferred loss on reacquired debt (1,823) Deferred accounting treatment (1,617) Other 729 (107,103) Noncurrent accumulated deferred taxes on income, net $ (85,995) (5) Commitments and Contingencies In October 1991, the second unit of TNP One, the Utility's two-unit, 300-megawatt, circulating fluidized bed generating facility, was completed and successfully placed in operation. At December 31, 1993, the costs of Unit 1 totalled approximately $357 million and the costs of Unit 2 totalled approximately $282.9 million. The Utility has received rate orders (in Docket Nos. 9491 and 10200) from the PUCT placing the majority of the costs of the two units of TNP One in rate base, resulting in rate increases for the Utility's Texas customers. In Docket No. 9491, the PUCT disallowed from rate base approximately $39.5 million of the costs of Unit 1. On appeal, a State district court overturned the disallowances; however, a Texas Court of Appeals rendered a judgment partially reversing the State district court. In its October 16, 1992 rate order in Docket No. 10200, the PUCT disallowed $21.1 million of the costs of Unit 2 . On rehearing of Docket No. 10200, the PUCT unexpectedly reversed consistent precedent to adopt a new methodology for calculating the amount allowed in rates for Federal income taxes. The immediate result was a reduction in the rate increase previously granted on October 16, 1992. Each of the rate orders is the subject of continuing appellate process in the courts. Further detailed information of Docket Nos. 9491 and 10200 is provided below. In litigating Docket Nos. 9491 and 10200, the Utility's opponents are seeking, among other things, lower rates and greater disallowances, and the Utility is seeking higher rates and no disallowances. While the ultimate outcome of these cases and of other matters discussed below cannot be predicted, the Utility is vigorously pursuing their favorable conclusion. Material adverse resolution of certain of the matters discussed below would have a material adverse impact on earnings in the period of resolution. PUCT Docket No. 9491 On February 7, 1991, in Docket No. 9491, the PUCT approved an increase in annualized revenues of approximately $36.7 million, or 67% of the Utility's original $54.9 million rate request filed in 1990. The approval allowed $298.5 million of the costs of TNP One, Unit 1 in rate base; however, the PUCT disallowed $39.5 million of the requested investment costs of $338 million for that unit. Additional Unit 1 costs, not requested in Docket No. 9491, were included in the Utility's subsequent Texas rate request, Docket No. 10200, filed on April 11, 1991. In Docket No. 9491 in Finding of Fact No. 84 (FF No. 84), the PUCT also found that the Utility failed to prove that its decision to start construction of Unit 2 was prudent. Since the costs incurred for Unit 2 construction were not at issue in the Docket No. 9491 proceeding, the quantification of a disallowance, if any, that might result from this finding was to be determined subsequently in Docket No. 10200. On June 5, 1991, the Utility filed a petition in a Travis County district court which sought to overturn the PUCT's ruling regarding the disallowances and prudence decisions in Docket No. 9491. Certain intervenors also appealed other aspects of the PUCT's decisions in Docket No. 9491. On July 6, 1992, the presiding judge of the district court signed a judgment finding that the PUCT's disallowance of rate base treatment for certain costs of Unit 1 was in error and that the PUCT's "decision to deny $39,508,409 in capital costs for TNP One Unit 1 is not supported by substantial evidence and is arbitrary and capricious." The Utility, the PUCT and certain of the intervenor cities (the Cities) appealed the district court's judgment regarding the appeal of the PUCT's decision in Docket No. 9491 to the Third District Court of Appeals in Austin, Texas. The Utility's appeal related to the district court s decision which upheld the PUCT finding that the Utility failed to prove that its decision to start construction of Unit 2 was prudent and certain other matters. The PUCT and the Cities sought to reinstate the disallowances, and the Cities sought, among other things, to deny rate base treatment and to significantly lower rates granted by the PUCT. On August 25, 1993, the Third District Court of Appeals rendered a judgment partially reversing the district court and affirming the PUCT s disallowances for $30.4 million of the total $39.5 million. The Court of Appeals judgment states that the district court erred in (1) reversing that part of the PUCT's order disallowing "the Compressed Schedule Payment, the Force Majeure Payment, and a portion of the increased costs for the installation of a natural gas pipeline in Change Order No. 9, Item 2;" (2) affirming that part of the PUCT's order dealing with the prudence of the decision to construct Unit 2 (FF No. 84); and (3) affirming that part of the PUCT's order that failed to pass on to ratepayers the federal income tax savings for expenses disallowed by the PUCT. The Court of Appeals remanded the cause to the district court with instructions that the cause be remanded to the PUCT for proceedings not inconsistent with the appellate opinion. On September 9, 1993, the Utility, the Cities and the PUCT filed motions for rehearing with the Court of Appeals. The PUCT is not expected to act upon the district court's ordered remand, discussed above, until the appellate process, including appeals to the Texas Supreme Court, has been completed. Based upon the opinions of the Utility's Texas regulatory counsel, Johnson & Gibbs, a Professional Corporation, management believes that it will prevail in obtaining a remand of a significant portion of the disallowances in Docket No. 9491; however, the ultimate disposition and quantification of these items cannot presently be determined. Accordingly, no provision for any loss that may ultimately be required upon resolution of these matters has been made in the accompanying consolidated financial statements. If the Utility is not successful in obtaining a final favorable disposition in the appellate proceedings relating to the disallowances in Docket No. 9491, a write-off of some portion of the $39.5 million disallowances would be required, which could result in a significant negative impact on earnings in the period of final resolution. PUCT Docket No. 10200 On April 11, 1991, the Utility filed a rate application, Docket No. 10200, with the PUCT for inclusion of $275.2 million of capital costs of Unit 2 and $16.1 million of additional capital costs of Unit 1 in the Utility's rate base. The Administrative Law Judge (ALJ) in Docket No. 10200 initially required briefs of all parties on the issue of whether the inclusion of Unit 2 in the Utility's rate base would be precluded by the PUCT finding in Docket No. 9491, FF No. 84, that the Utility failed to prove that its decision to start construction of Unit 2 was prudent. In its brief to the ALJ, the Utility argued that FF No. 84 could not have the effect of barring litigation in Docket No. 10200 of all aspects of Unit 2 costs, asserting that evidence as to Unit 2 costs presented in Docket No. 9491 had been presented for the purpose of discussion of facilities which were common to both Unit 1 and Unit 2. The General Counsel of the PUCT argued that the issue of the Utility's prudence as to Unit 2 was barred by FF No. 84 and requested that the Utility's entire prudence testimony in Docket No. 10200 be stricken, along with all associated schedules and exhibits. The ALJ ruled on June 7, 1991 that the PUCT's finding in Docket No. 9491 could not be relitigated in Docket No. 10200. However, the ALJ determined that the PUCT did not decide "what specific action by TNP, instead of beginning construction when it did, would have been prudent" and that the PUCT did not "quantify the disallowance resulting from its finding that TNP had failed to prove that beginning construction of Unit 2 was prudent." Therefore, the ALJ concluded that the parties could raise those particular issues in Docket No. 10200. The ALJ further stated that, "The disallowance, if any, will be determined using principles set forth in previous cases regarding prudence." The ALJ determined that, in order for the Utility's request for inclusion of the Unit 2 investment in rate base as plant in service to be considered, the Utility must present a prima facie case in its direct testimony as to how a disallowance resulting from FF No. 84 should be quantified. The Utility appealed the ALJ's ruling to the PUCT, which voted not to hear the appeal. On August 16, 1991, the Utility filed supplemental prudence testimony, under protest, responding to the ALJ's order and supporting the Utility's entitlement to rate base treatment for the costs of Unit 2. In its supplemental testimony, the Utility contended that it prudently could have released Unit 2 for construction in February 1989, rather than September 1988, when the unit was actually released. The Utility argued that this alternative would cost no less than the actual cost of Unit 2, and thus no disallowance should result from any imprudence in releasing Unit 2 for construction in September 1988. Two intervenors in this proceeding objected to the Utility's presentation of a prudent alternative, but the PUCT included such evidence in the record. In a "final" order dated October 16, 1992, the PUCT commissioners approved an increase in annualized revenues of $26 million, or 72% of the Utility's original $35.8 million requested increase. The PUCT's order determined that the reasonable costs for Unit 2 were $261.8 million. The PUCT allowed in rate base $250.7 million of the $275.2 million requested for Unit 2 costs. The difference between the $261.8 million in costs found to be prudent by the PUCT and the $282.9 million total costs of Unit 2 consisted of disallowances of approximately $21.1 million. The PUCT also determined that $11.1 million of Unit 2 costs will be addressed in a future Texas rate application. The order in Docket No. 10200 also allowed approximately $15.3 million of the requested approximately $16.1 million of Unit 1 costs not sought by the Utility in Docket No. 9491. The approximately $800,000 disallowance was primarily related to debt service on disallowed costs determined in Docket No. 9491. Subsequent to the issuance of the "final" order on October 16, 1992, motions for rehearing of certain issues were filed by parties to the case. On December 22, 1992, the PUCT issued an Order on Rehearing which reduced the $26 million increase in annualized revenues that was originally granted by the PUCT in its order on October 16, 1992. The primary issue in the Order on Rehearing was the PUCT's reversal of its original Docket No. 10200 order as to the use of the "return method" for calculating the amount allowed in cost of service for the Utility's Federal income tax expense. The "return method" of computing Federal income tax expense requested by the Utility followed consistent precedent of the PUCT. The concept of the return method is to match a utility s taxes with the same revenues and expenses included in rates. The new method adopted by the PUCT in the Order on Rehearing flowed through to ratepayers the tax benefits of expenses disallowed and not included in rates. The net effect of this Order on Rehearing was a decrease of approximately $7 million from the October 16, 1992 order, resulting in a $19 million increase in annualized revenues. On January 26, 1993, the PUCT considered motions for rehearing on the December 22, 1992 Order on Rehearing but did not alter the $19 million increase in annualized revenues or the disallowances. In its Order on Rehearing, dated February 4, 1993, the PUCT ordered the Utility to seek a private letter ruling from the Internal Revenue Service (IRS) to determine if the Order on Rehearing resulted in violations of the "normalization" rules concerning investment tax credits and accelerated tax depreciation on public utility property. The PUCT's February 4, 1993 Order on Rehearing stated that the tax method utilized does not violate the "normalization" rules of the Internal Revenue Code; however, a December 1992 private letter ruling of the IRS to an unrelated utility indicates that regulatory treatment which flows through tax benefits of investment tax credits on disallowed public utility property violates the "normalization" rules. A "normalization" violation ultimately results in a utility's loss of benefits from investment tax credit and/or accelerated depreciation on public utility property. Without the curative action of the PUCT on March 10, 1993, discussed in the following paragraph, an IRS determination that a "normalization" violation had occurred would subject the Utility to paying additional income taxes for the amount of the accumulated deferred investment tax credits as of the time of the violation and taxes on the amount of tax depreciation in excess of book depreciation for all tax years open for IRS review. On March 10, 1993, the PUCT considered motions for rehearing on the February 4, 1993 Order on Rehearing and expressed its position that its earlier actions not create a "normalization" violation for the Utility. As a result, in its Order on Rehearing, dated March 18, 1993, the PUCT ordered that the Utility be granted, subject to refund, an additional $1.6 million in annualized revenues which matches recovery in rates with only the investment tax credits and accelerated tax depreciation related to utility property included in rate base. Accordingly, the benefits of investment tax credits and accelerated tax depreciation related to disallowed public utility property would not be passed through to ratepayers; therefore, the Utility believes that the "normalization" rules with respect to investment tax credits and accelerated tax depreciation would not be violated. Further, the PUCT affirmed its February 4, 1993 Order on Rehearing directing the Utility to seek a private letter ruling from the IRS to determine if the earlier methodology adopted in the December 22, 1992 Order on Rehearing would violate the "normalization" rules concerning investment tax credits and accelerated tax depreciation on public utility property. If the IRS determines that the PUCT's December 22, 1992 order would not constitute a "normalization" violation, then the additional $1.6 million in annualized revenues would be revoked by the PUCT, and the Utility would be required to refund excess amounts collected. The PUCT did not reverse its December 22, 1992 position to pass through to ratepayers the tax benefits of interest charges related to disallowed public utility property. The net resultant effect of Docket No. 10200 (by the PUCT action of March 10, 1993) is an increase in annualized revenues of $20.6 million, of which $1.6 million is subject to refund. The March 18, 1993 Order on Rehearing was appealed by the Utility and certain intervening parties to a State district court. Because of the Court of Appeals judgment relating to FF No. 84 in the Docket No. 9491 appeals, the presiding judge in the State district court for the Docket No. 10200 appeal has ordered that the procedural schedule in this appeal be abated until final resolution of the FF No. 84 issue in Docket No. 9491. The Utility will vigorously pursue reversal of the PUCT's new position regarding Federal income tax expense in addition to seeking judicial relief from the disallowances and certain other rulings by the PUCT in Docket No. 10200. During the third quarter of 1993, the Utility refunded, to the appropriate Texas customers, amounts collected under bonded rates in excess of the $20.6 million in annualized revenues granted on rehearing in Docket No. 10200. The refund (approximately $18 million, including interest) was related to the period beginning on the effective date for bonded rates (October 16, 1991) through April 1993. After receiving PUCT approval on October 19, 1993, the Utility filed, on October 20, 1993, a request with the IRS for a private letter ruling on the issue of a "normalization" violation resulting from the PUCT's proposed treatment of investment tax credits and accelerated tax depreciation. Revenues related to the conditionally granted $1.6 million annualized increase will not be refunded unless the IRS determines that a "normalization" violation would not result from flowing through benefits of investment tax credits and accelerated tax depreciation related to disallowed public utility property. If the IRS so determines, a refund will be made after that determination. Accordingly, revenues associated with the $1.6 million annualized increase have not been recognized in results of operations as of December 31, 1993, and a provision for revenues subject to refund, including interest, has been made for $3.4 million in the consolidated balance sheet as of December 31, 1993. The Utility expects to receive the private letter ruling in 1994. Based upon the opinions of the Utility's Texas regulatory counsel, Johnson & Gibbs, a Professional Corporation, management believes that it will prevail in obtaining a remand of a significant portion of the disallowances in Docket No. 10200; however, the ultimate disposition and quantification of these items cannot presently be determined. Accordingly, no provision for any loss that may ultimately be required upon resolution of these matters has been made in the accompanying consolidated financial statements. If the Utility is not successful in obtaining a final favorable disposition in the appellate proceedings relating to the disallowances in Docket No. 10200, a write-off of some portion of the $21.9 million disallowances would be required, which could result in a significant negative impact on earnings in the period of final resolution. Other TNP One Matters In Docket No. 9491, the Utility requested deferred accounting treatment (DAT) for Unit 1 which would (1) defer $1.4 million and $2.8 million of operating costs and interest costs, respectively, (2) recover such amounts in rates through amortizations over the life of the unit and (3) include such unamortized amounts in the Utility's rate base, thereby recovering a carrying cost on the unamortized amount. The PUCT granted the Utility's DAT request except the inclusion of interest costs ($2.8 million) in rate base. In the final order meeting for Docket No. 9491, the PUCT commissioners indicated that their decision to exclude interest costs from the Utility's rate base was influenced by a recent appeals court ruling. In that ruling, which involved an appeal of a decision by the PUCT granting DAT to an unrelated electric utility, the appeals court found that the DAT component for interest costs could not be included in rate base. The electric utility has filed an application for writ of error with the Texas Supreme Court regarding the appeals court ruling. The ultimate effect of the appeals court ruling on the order granting DAT for Unit 1 is uncertain at this time. The Utility entered into a fuel supply agreement dated November 18, 1987 with Phillips Coal Company (Phillips), owner of a 300-million-ton lignite reserve in Robertson County in proximity to TNP One. The agreement provides for a lignite fuel source for the 38-year life of TNP One. Phillips subsequently entered into an agreement with a subsidiary of Peter Kiewit Sons', Inc. for development of the lignite mine by a joint venture partnership, Walnut Creek Mining Company. Unit 1 and Unit 2 are capable of utilizing Western coal, petroleum coke and natural gas as alternative fuel sources. Legal Actions The Utility is involved in various claims and other legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Utility's and the Company's consolidated financial position. SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED) The following selected quarterly consolidated financial data is unaudited, and, in the opinion of the Company's management, is a fair summary of the results of operations for such periods:
March 31 June 30 Sept. 30 Dec. 31 (In thousands - except per share amounts) 1993 Operating revenues $103,150 107,530 150,067 113,495 Net operating income $ 14,454 15,722 29,576 18,488 Net earnings (loss) $ (1,866) (410) 13,579 302 Earnings (loss) available for common stock $ (2,099) (634) 13,368 91 Weighted average number of common shares outstanding 10,604 10,626 10,653 10,680 Earnings (loss) per share of common stock $ (0.20) (0.06) 1.25 0.01 Dividends per share of common stock $ 0.4075 0.4075 0.4075 0.4075 1992 Operating revenues $ 98,719 105,847 137,287 101,974 Net operating income $ 15,625 19,669 29,110 12,599 Net earnings (loss) $ (772) 2,881 12,653 (3,832) Earnings (loss) available for common stock $ (1,027) 2,635 12,420 (4,066) Weighted average number of common shares outstanding 8,333 8,406 8,492 8,945 Earnings (loss) per share of common stock $ (0.12) 0.31 1.46 (0.45) Dividends per share of common stock $0.4075 0.4075 0.4075 0.4075
Generally, variations between quarters reflect seasonal variations in sales, increases in the weighted average number of common shares outstanding and other factors. In addition, quarterly results of operations have been affected by implementation in 1993 of Statement of Financial Accounting Standards No. 106, Employers Accounting for Postretirement Benefits Other Than Pensions, variations in interest charges, rate orders received by the Utility, customer growth and changes in customer usage. See notes 1(j), 2 and 5 to the consolidated financial statements and Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of these matters. SELECTED ANNUAL CONSOLIDATED FINANCIAL DATA
1993 1992 1991 1990 1989 (In thousands except per share amounts and percents) Operating revenues $ 474,242 443,827 441,343 397,289 378,289 Power purchased for resale $ 200,183 174,257 216,818 253,416 257,259 Total operating expenses $ 396,002 366,824 378,778 360,220 349,755 Net operating income $ 78,240 77,003 62,565 37,069 28,534 Net earnings $ 11,605 10,930 19,533 16,352 16,759 Earnings available for common stock $ 10,726 9,962 18,455 15,137 15,408 Common shares outstanding: Weighted average 10,641 8,545 8,275 8,207 8,130 End of year 10,696 10,598 8,318 8,238 8,179 Per share of common stock: Earnings $ 1.01 1.17 2.23 1.84 1.90 Cash dividends declared $ 1.63 1.63 1.63 1.63 1.55 Book value $ 19.97 20.62 21.45 20.86 20.66 Total assets (1) $1,105,237 1,182,707 1,122,591 807,854 442,840 Capitalization: Common stock equity $ 213,627 218,535 178,388 171,839 168,946 Redeemable cumulative preferred stocks 9,560 10,440 11,320 12,600 13,880 Long-term debt, net of amount due within one year (2, 3, 4) 678,994 742,087 525,060 350,301 134,893 Total capitalization $ 902,181 971,062 714,768 534,740 317,719 Capitalization ratios: Common stock equity 23.7% 22.5 25.0 32.1 53.2 Redeemable cumulative preferred stocks 1.1 1.1 1.6 2.4 4.4 Long-term debt, net of amount due within one year (2, 3) 75.2 76.4 73.4 65.5 42.4 Total capitalization 100.0% 100.0 100.0 100.0 100.0 Short-term debt: Long-term debt due within one year (2, 3, 4) $ 1,070 10,288 201,276 78,570 516 Notes payable to banks, unsecured (3) 36,000 41,900 13,900 $ 1,070 10,288 237,276 120,470 14,416 (1) The significant increases in total assets for 1990 and 1991 reflect the assumption of the costs of Unit 1 and Unit 2, respectively. Unit 1 and Unit 2 are two 150-megawatt lignite-fueled generating units using circulating fluidized bed technology. See Management's Discussion and Analysis of Financial Condition and Results of Operations and notes 2 and 5 to the consolidated financial statements for more information about the units. (2) The significant increases in long-term debt in 1990 and 1991 reflect the assumption of the debt obligations of the financing facilities related to Unit 1 and Unit 2, respectively. See note 2 to the consolidated financial statements for more information about the financing facilities. (3) With proceeds from the issuances of long-term debt securities in January 1992, the Utility repaid and prepaid certain amounts under the Unit 1 and Unit 2 financing facilities and repaid a portion of outstanding unsecured notes payable to banks. (4) With proceeds from the issuances of long-term debt securities in September 1993, the Utility prepaid additional amounts under the Unit 1 and Unit 2 financing facilities. See note 2 to the consolidated financial statements for more information. See Management's Discussion and Analysis of Financial Condition and Results of Operations and note 5 to the consolidated financial statements for discussion of material uncertainties which might cause the information above not to be indicative of future financial condition or results of operations.
SELECTED ELECTRIC OPERATING STATISTICS
1993 1992 1991 1990 1989 Operating revenues - thousands of dollars: Residential $ 193,484 175,885 176,651 153,844 143,070 Commercial 138,680 128,550 119,745 102,320 95,302 Industrial 124,474 121,027 128,356 125,640 125,098 Other 17,604 18,365 16,591 15,485 14,819 Total $ 474,242 443,827 441,343 397,289 378,289 Sales thousand kilowatt-hours: Residential 2,047,360 1,947,593 2,017,349 1,998,727 1,915,772 Commercial 1,567,083 1,499,927 1,485,211 1,441,275 1,363,518 Industrial 2,567,552 2,508,837 2,798,369 2,848,020 2,796,162 Other 104,882 109,954 115,406 133,549 136,701 Total (a) 6,286,877 6,066,311 6,416,335 6,421,571 6,212,153 Number of customers end of period: Residential 181,289 178,154 174,859 172,560 170,860 Commercial (b) 30,235 30,359 30,300 30,161 29,828 Industrial (b, c) 141 155 160 173 188 Other 246 229 230 227 229 Total 211,911 208,897 205,549 203,121 201,105 Average annual use per residential customer KWH 11,362 11,003 11,584 11,613 11,236 Average annual revenue per residential customer dollars 1,067 987 1,010 892 839 Average revenue per KWH sold residential - cents 9.45 9.03 8.76 7.70 7.47 Average revenue per KWH sold total sales - cents 7.54 7.32 6.88 6.19 5.98 Source net generated and purchased thousand kilowatt-hours: Generated 2,363,493 2,247,664 1,337,366 395,852 198 Purchased 4,385,697 4,261,129 5,452,132 6,375,418 6,596,650 Total (a) 6,749,190 6,508,793 6,789,498 6,771,270 6,596,848 Average cost per KWH generated and purchased - cents 4.13 3.86 3.94 3.92 3.94 Net utility plant - in thousands of dollars $1,005,995 1,015,709 1,016,602 728,989 363,242 Electric line total pole miles 10,532 10,472 10,397 10,335 10,280 Estimated population served at retail 616,000 605,000 595,000 587,000 581,000 Total employees 1,051 1,086 1,104 1,121 1,105 (a) Difference between total sources and total sales represents Utility use and line losses. (b) Three and seven industrial customers became commercial customers during 1993 and 1991, respectively. (c) Ten industrial customers were combined into two industrial customers for billing purposes during 1993.
COMMON STOCK INFORMATION In February 1994, the Company's Board of Directors declared quarterly common stock dividends of $0.4075 per share. This produces an indicated annual dividend of $1.63 per share. None of the dividends paid during 1993 constituted a return of capital. As of December 31, 1993, the Company had 7,031 common shareholders of record. During 1993, the Company obtained $1.7 million of new capital during the year by issuing 98,296 shares of common stock to the Dividend Reinvestment and Stock Purchase Plan and the Utility's Thrift Plan for Employees. The Company has a Shareholder Rights Plan which is described in note 1(m) to the consolidated financial statements. Charter provisions, bond indentures, and financing facilities contain certain restrictions as to the payment of cash dividends on common stock of the Utility. Explanations of these restrictions are included in notes 2 and 3 to the consolidated financial statements. Quarterly Dividends Paid Per Share * 1993 1992 1st Quarter $0.4075 0.4075 2nd Quarter 0.4075 0.4075 3rd Quarter 0.4075 0.4075 4th Quarter 0.4075 0.4075 Yearly $1.6300 1.6300 *Through 1993, TNP Enterprises, Inc., or its predecessor companies, paid 232 consecutive quarterly dividends.
Market Price Range Price of Common Stock (as reported by the New York Stock Exchange) 1993 1992 High Low High Low 1st Quarter $19 3/8 18 1/8 21 1/4 19 2nd Quarter 19 1/2 17 1/2 20 3/4 18 1/2 3rd Quarter 17 7/8 14 5/8 21 5/8 17 1/4 4th Quarter 17 3/4 16 3/8 21 1/2 17 1/4 Yearly $19 1/2 14 5/8 21 5/8 17 1/4
DIRECTORS AND OFFICERS Board of Directors TNP Enterprises, Inc. and Texas-New Mexico Power Company R. D. Woofter (19), A, B, C, D Chairman TNP Enterprises, Inc. Texas-New Mexico Power Company Fort Worth, Texas R. Denny Alexander (5), A, B Owner R. Denny Alexander & Co. (investment management) Fort Worth, Texas Cass O. Edwards II (19), A, C Managing Partner Edwards-Geren Limited (ranching and farming) Fort Worth, Texas John A. Fanning (10), A, B Executive Vice President Snyder Oil Corporation Fort Worth, Texas Harris L. Kempner, Jr. (14), B, D President Kempner Capital Management Galveston, Texas Dr. T. S. Mackey, P.E.* (17), C, D President Key Metals & Minerals Engineering Corp. Texas City, Texas Dwight R. Spurlock (1), B, D Interim President & Chief Executive Officer TNP Enterprises, Inc. Texas-New Mexico Power Company Fort Worth, Texas Gail Potts Williamson** (1) Chairman of the Board Williamson-Dickie Manufacturing Company Fort Worth, Texas *A member of the Board and Committees until the time of his death on February 25, 1994 **Advisory Director-TNP Enterprises, Inc. and Texas-New Mexico Power Company (A) Audit Committee (B) Financial Committee (C) Personnel, Organization and Nominating Committee (D) Administrative Committee of Employee Benefits (Numerals indicate years on board) Officers TNP Enterprises, Inc. D. R. Spurlock Interim President & Chief Executive Officer D. R. Barnard Vice President & Chief Financial Officer M. D. Blanchard Secretary M. W. Smith Treasurer B. Jan Adkins Assistant Secretary Officers Texas-New Mexico Power Company D. R. Spurlock Interim President & Chief Executive Officer Retired in 1992 with 33 years of service D. R. Barnard (32) Sector Vice President - Chief Financial Officer J. V. Chambers, Jr. (15) Sector Vice President - Revenue Production M. C. Davie (29) Vice President - Corporate Affairs A. B. Davis (28) Vice President - Chief Engineer L. W. Dillon (18) Vice President - Operations R. J. Wright (14) Vice President - Corporate Services/Generation T. R. Ownby (20) Assistant Vice President M. D. Blanchard (10) Secretary & General Counsel M. W. Smith (7) Treasurer B. Jan Adkins (24) Assistant Secretary P. L. Bridges (3) Assistant Treasurer G. L. Spooner (24) Assistant Treasurer (Numerals indicate years of service) Division Managers Texas-New Mexico Power Company J. L. Sears (19) Central Division C. N. Bundick (20) New Mexico Division D. L. Hudson (41) Northern Division D. H. Bryson (32) Southeast Division J. W. Garrison (38) Western Division Numerals indicate years of service) SHAREHOLDER INFORMATION Annual Meeting The annual meeting of TNP Enterprises, Inc. will be held Thursday, April 28, 1994 at 11:00 a.m., Central Time, at 4100 International Plaza, Fort Worth, Texas. In connection with this meeting, proxies will be solicited by the Board of Directors of the Company. A notice of the meeting, together with a proxy statement, a form of proxy and the Annual Report to Shareholders for 1993, were mailed on or about March 28, 1994 to shareholders of record as of March 9, 1994. Form 10-K Available TNP Enterprises, Inc. will file its annual report on Form 10-K with the Securities and Exchange Commission by March 30, 1994. Many of the SEC's 10-K information requirements are satisfied by this 1993 annual report. However, a copy of the Form 10-K, including the consolidated financial statements and schedules, will be available without charge after March 31, 1994 by writing to the Treasurer of TNP Enterprises, Inc., P.O. Box 2943, Fort Worth, Texas, 76113. The information contained in this report is given in response to general requests for information about the Company, and not in connection with any sale, offer of sale or solicitation of an offer to buy any securities. Registrar, Transfer Agent and Dividend Disbursing Agent for Preferred Stocks and Common Stock Society National Bank 3200 Renaissance Tower 1201 Elm Street Dallas, Texas 75270 1-800-527-7844 -----END PRIVACY-ENHANCED MESSAGE-----