ITEM 1. BUSINESS
GENERAL
The Company
Southwestern Public Service Company (the Company) was incorporated in New Mexico in 1921. The Company's principal business is the generation, transmission, distribution and sale of electric energy. Substantially all of its operating revenues were so derived during each of the fiscal years ended August 31, 1995, 1994 and 1993. The Company has two wholly owned subsidiaries, Utility Engineering Corporation (UE) and Quixx Corporation (Quixx). See NONUTILITY BUSINESSES and Note (1) of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
On August 22, 1995, the Company and Denver-based Public Service Company of Colorado (PSCo) entered into a definitive agreement providing for a "merger of equals" of the two companies. Under the agreement, a registered public utility holding company would be the parent company of the Company and PSCo. See Note (2) of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS for further information on this business combination. Reference is made to the Company's current report on Form 8-K filed with the Securities and Exchange Commission on August 23, 1995, including the Agreement and Plan of Reorganization and other documents filed as exhibits thereto. The information set forth in this Form 10-K (unless otherwise indicated) does not take into account changes that would result from the merger.
The Company has called for redemption on December 27, 1995, all of its outstanding Cumulative Preferred Stock which is redeemable by its terms. The Company will also purchase all 2,600 shares of its 14.50% Cumulative Preferred Stock (which is not redeemable by its terms). These 2,600 shares of preferred stock are held by Don Maddox, a director of the Company, as one of two co-personal representatives of the Estate of James M. Murray, Jr., in which Mr. Maddox shares voting and investment power. These shares were acquired by Mr. Murray in connection with the acquisition in 1982 by the Company of the electrical distribution system of Cochran Power and Light Company. This preferred stock purchase is being negotiated. As a consequence, upon the above redemptions and purchase, there will be no shares of Preferred Stock outstanding. However, the Company plans, subject to market conditions, to reissue Preferred Stock in 1996 subsequent to its Annual Meeting of Shareholders (scheduled to be held January 31, 1996) at which holders of its Common Stock will be requested to approve the amendment of the Company's Restated Articles of Incorporation (Articles) with respect to the Preferred Stock so as to modernize such provisions and eliminate covenants imposed thereby. The redemption and purchase of the outstanding Cumulative Preferred Stock is being undertaken for the purpose of facilitating obtaining shareholder approval of the merger of the Company and PSCo and modernizing the Preferred Stock provisions of the Articles. See MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Liquidity and Capital Resources.
Electric service is provided through an interconnected system to a population of about one million in a 52,000-square-mile area of the Panhandle and south plains of Texas, eastern and southeastern New Mexico, the Oklahoma Panhandle and southwestern Kansas. The Company provides electric energy to forty-six communities with a population of 2,000 or more, thirty-five in Texas, nine in New Mexico, and one each in Oklahoma and Kansas. Approximately 56% of the Company's operating revenues during fiscal 1995, excluding sales to other utilities, were derived from operations in Texas.
The Company's sales are made to retail and wholesale customers. Retail sales to ultimate consumers include residential, commercial and industrial customers. Wholesale sales include sales for resale to rural electric cooperatives, and firm and non-firm sales to other utilities. These non-firm, or economy, wholesale sales to other utilities also include sales of interruptible power made under Federal Energy Regulatory Commission (FERC) approved contracts. Firm sales are made under contract to other adjoining utilities while non-firm sales are negotiated on the spot market or sold under the Western Systems Power Pool (WSPP) agreement. See INTERCONNECTIONS. Non-firm sales are made to adjoining and other utilities.
The production, transportation and processing of oil and natural gas, and chemical, mineral and light manufacturing industries are of prime importance in the area served. Agriculture and the processing of agricultural products, including wheat, cotton, corn, sugar beets and vegetables, and livestock raising and meat processing are industries of economic significance. The area also contains many other diversified industries and commercial enterprises. See STATISTICAL SUMMARY-ELECTRIC REVENUES.
The Company's largest sales of electric energy are during the summer months when demand reaches a peak. The Company's 1995 maximum hourly net peak system demand of 3,952 megawatts (MW) occurred on July 28, 1995 and was an all-time high peak. The previous maximum net peak of 3,682 MW occurred on July 6, 1994. See PEAK LOAD AND CAPABILITY.
See REGULATION-Competition and Note (8) of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS for information on the changing utility environment.
CONSTRUCTION PROGRAM
Cash expenditures for the Company's construction program were $94.7 million in fiscal 1995. These expenditures did not include any amounts for the construction of new base load generating facilities.
The following general discussion of the Company's construction program and related expenditures are for a stand-alone company; that is, without consideration to the proposed merger with PSCo. On that basis, the Company's estimated construction expenditures for the next five years are as follows:
The estimates in 1997, 1998 and 1999 for generating facilities include costs for the construction of approximately 400 MW of additional capacity. Such construction plans include a 200 MW natural-gas-fired cogeneration facility to be completed in 1998 at a Phillips Petroleum Company complex near Borger, Texas, and a 198 MW natural-gas-fired combustion turbine to be completed in 1999 at an existing Company plant site. The Company was recently granted a Notice of Intent by the Public Utility Commission of Texas (PUCT) to construct approximately 300 MW of the 400 MW of new capacity.
PUCT regulations require that a solicitation be conducted before a utility seeks certification of a new generating unit. The goal of this solicitation process is to evaluate and select the most appropriate combination of resources. Pursuant to these regulations, on September 15, 1995, the Company issued a request for proposals (RFP) to seek alternatives to its proposed construction. The Company's solicitation encompasses alternative supply-side options, renewable resources, off-system transactions (primarily purchases), demand-side management programs, and existing customer interruptible load programs. Responses to this RFP are due to a third party evaluator in January 1996.
The estimates in 1998 and 1999 for transmission facilities include expenditures of $18 million for a 230 KV transmission line to be constructed from Amarillo, Texas to Clovis, New Mexico in order to improve the reliability of the Company's system. Expenditures are also planned to upgrade transmission and distribution lines and substations to preserve reliability and efficiency.
These estimated expenditures have been prepared for planning purposes as part of the Company's resource planning process (discussed below), and are subject to review and revision. Actual expenditures will vary from these estimates, as they have in the past, due to a number of factors, including regulatory requirements related to the planning and siting of facilities, changes in the rate of inflation, construction scheduling, environmental matters, the cost and availability of funds, the rate of kilowatt-hour (kwh) sales growth and other changes in business conditions, regulation and legislation. The completion of the merger with PSCo could significantly impact these estimates.
The Company's resource planning process is designed to determine the optimal mix of capacity resources that would reliably meet its load and reserve requirements at the least possible cost, while providing flexibility to respond to uncertainty in the forecasts of load, fuel prices, and financial and other conditions. The Company typically considers its load forecast, demand-side management programs, Southwest Power Pool (SPP) reserve requirements, and new generating unit alternatives, and after consideration of these and any other relevant factors, arrives at a capacity expansion plan which balances cost and system operations.
During the five fiscal years ended August 31, 1995, the Company had property additions (including work in progress) to utility plant of $437 million and retirements of $43 million. At August 31, 1995, net utility plant was approximately $1.5 billion.
See MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Liquidity and Capital Resources for information on the Company's estimated capital expenditures and financing program. Also see NONUTILITY BUSINESSES-QUIXX for information on Quixx's investment expenditures.
PEAK LOAD AND CAPABILITY
Plant capability, peak load, capacity margin and load factor were as follows for the last three fiscal years:
As a member of the SPP, the Company's policy is to maintain a net capacity margin in accordance with SPP criteria. For steam-based utilities, the SPP guideline is a minimum capacity margin of 13%. Because of the high peak load experienced in 1995, the Company's capacity margin was 4.4% for that year. However, through the expansion of an existing interruptible program for irrigation load, the initiation of a new interruptible program for industrial load, purchased power and the consideration of additional capacity on the system, the Company expects to be within the SPP guideline through the remainder of the decade. See CONSTRUCTION PROGRAM.
During the period 1996 through 2000, the Company currently estimates that its compound annual growth rates will be 2.5% for wholesale sales, excluding non-firm sales, and 2.0% for retail sales. Total kwh sales estimates show a compound annual growth rate of 1.3% for this forecast period. The Company periodically reviews expected growth patterns in its service area and these growth rate estimates are subject to change. See MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
INTERCONNECTIONS
The Company is connected with utilities west of its service territory through two high voltage direct current (HVDC) interconnections in New Mexico and has four interconnecting transmission lines with utilities of the SPP. These interconnections are described in the following table:
Transactions with the SPP are handled through interties near Elk City and Guymon, Oklahoma, and Shamrock and Oklaunion, Texas. These interties allow the Company to sell or to purchase energy from the eastern electrical grid. Sales through eastern interties accounted for 2.0% of fiscal 1995 total sales.
HVDC interconnections link the Company with the western electrical grid of the United States. The Company purchases and sells energy through HVDC interties near Artesia and Clovis, New Mexico. Sales through these interties accounted for 4.1% of fiscal 1995 total sales.
The Company participates in the bulk power market through the WSPP. In fiscal 1995, 2.0% of total sales were due to WSPP bulk power sales.
Under an agreement which expires in December 1996, the Company is selling 50 MW of firm power to El Paso Electric Company (EPE) through the HVDC interconnection near Artesia, New Mexico. The sale is scheduled to increase to 75 MW in January 1996. For the months of May through August 1995, EPE purchased an additional 70 MW to help meet increased weather-related demand. Additional firm power sales through this HVDC connection to Texas-New Mexico Power Company (TNP) are made under an agreement with an initial term that expires in 2004. TNP purchased 33 MW of service from September through December 1993, and 66 MW from January 1994 through December 1995. This sale is scheduled to decrease to 59 MW in January 1996. TNP may increase or decrease the contract amount by up to 10% with one year's notice.
The Company has an interconnection agreement with Public Service Company of New Mexico (PNM) to sell power through the HVDC interconnection near Clovis, New Mexico. Under this agreement PNM purchased 100 MW of interruptible power service through April 1995. Beginning in May 1995, PNM began purchasing 200 MW. The agreement provides that PNM will continue purchasing 200 MW annually thereafter through May 2011 except that they may reduce purchases by 25 MW increments upon written notice given at least three years in advance of each increment reduction. However, the purchase may not be reduced by more than one 25 MW increment in any twelve-month period. PNM has not provided any written notice of intent to reduce its purchases under this agreement.
Under a firm wholesale power agreement which expires in 2014, the Company has contracted to serve the full requirements load of Cap Rock Electric Cooperative (Cap Rock). Cap Rock began purchasing 15 MW of service on February 1, 1994, and increased to 100 MW in February 1995.
The Company has entered into an agreement with The Empire District Electric Company (EDE) to sell interruptible wholesale power through the interconnections near Elk City, Oklahoma and Oklaunion, Texas. Under this agreement, which expires in 2001, EDE may purchase available power through December 1995 and will purchase 35 MW in 1996 with such purchases to increase to 45 MW by 1999. Public Service Company of Oklahoma has agreed to wheel such service over its transmission system.
Interconnection sales for fiscal 1995 through the eastern electrical grid totaled 395,490 MWH, including 303,037 MWH of WSPP sales. Sales through the western electrical grid totaled 820,445 MWH, consisting of 46,595 MWH of firm sales and 773,850 MWH of non-firm sales, including 90,807 MWH of WSPP sales.
FUEL SUPPLY AND PURCHASED POWER
Fuel Supply
Approximately 53% of the Company's present generating capacity is fueled by coal, 46% by gas and 1% by inert by-product gases, purchased steam and oil. See PROPERTIES for information about generating plants.
The Company's actual and anticipated fuel use, as reported in the table below, is based on MMBtu use for generation of electricity excluding non-firm sales. The unpredictability of the non-firm sales market precludes its inclusion as a factor in determining these fuel use projections. These projections do not consider the proposed merger with PSCo.
Fiscal Estimated for fiscal years ending August 31, Fuel 1995 1996 1997 1998 1999 2000 Coal 64.4% 65.4% 65.6% 63.0% 62.1% 61.3% Gas 34.8 33.8 33.6 36.2 37.2 37.9 Other 0.8 0.8 0.8 0.8 0.7 0.8
Anticipated fuel use is based upon numerous assumptions with respect to, among other things, regulatory requirements relating to cogeneration and environmental protection, load growth, cost and availability of boiler fuels and the extent to which the Company receives and can utilize contracted-for gas, renegotiates present gas contracts and enters into new agreements. Actual fuel mix in future years may vary substantially from these estimates because these assumptions may not be realized.
Coal
The Company purchases all of its coal requirements for Harrington and Tolk Stations from TUCO, Inc. (TUCO), a wholly owned subsidiary of Cabot Corporation, in the form of crushed, ready-to-burn coal delivered by coal-handling facilities owned by Wheelabrator Coal Services Co. to the Company's boiler bunkers located within the Company's coal-fueled stations where it is processed for burning. The coal is transported for TUCO by rail, primarily from mines located in Wyoming, to TUCO's stockpiles which are adjacent to the Company's coal-burning generating stations. At August 31, 1995, TUCO's coal inventories at the Harrington and Tolk sites were 723,091 tons and 652,978 tons (approximately 60 days supply), respectively. The Company has agreed to purchase all of the outstanding stock of TUCO from Cabot Corporation for $77 million, subject to certain regulatory approvals. This acquisition is scheduled to be completed in fiscal 1996. See Note (2) of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
TUCO has long-term contracts with Atlantic Richfield Company (ARCO) for a supply of coal in sufficient quantities to meet all of the Company's needs for Harrington and Tolk Stations. See ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
The Company has been named as a defendant in a case entitled Thunder Basin Coal Co. v. Southwestern Public Service Co., No. 93-CV-304B (D. Wyo.). The action was served on the Company on February 14, 1994 and it involves a dispute over the interpretation of a clause in a contract between Thunder Basin and TUCO for the supply of coal for use by the Company. The suit sought a determination that there has been a partial repudiation of the agreement by TUCO which has damaged Thunder Basin, and that the Company is liable for that damage as a result of its guarantee of TUCO's performance. Thunder Basin also claimed that the Company interfered with the contract between Thunder Basin and TUCO, causing Thunder Basin damage. The total alleged damages sought by Thunder Basin was in excess of $20 million. The Company denied any liability, and asked the court to determine that its interpretation of the contract was correct.
Thunder Basin's Wyoming lawsuit in federal court went to trial in late October 1994. On November 1, 1994 the jury returned a verdict in favor of Thunder Basin and against the Company finding that there had been a partial repudiation of the contract and that the Company had interfered with Thunder Basin's contract with TUCO. The jury awarded damages to Thunder Basin of approximately $18.8 million. The Company has appealed the judgement to the Tenth Circuit Court of Appeals and the appeal is progressing.
The Company, in conjunction with TUCO, has commenced a related case against Thunder Basin and its parent ARCO in state court in Amarillo, Texas (No. 80,280-E, TUCO, Inc. v. Thunder Basin Coal Company). This suit involves some of the same issues of contract interpretation raised in the Thunder Basin Wyoming suit, as well as the Company's claims that it has been overcharged approximately $40 million for coal during the course of the contract. This litigation is proceeding.
TUCO requested an audit of Thunder Basin's and ARCO's costs and expenses used to calculate the cost escalation under the contracts which supply coal for the Company. Thunder Basin and ARCO filed suit in Wyoming state court (No. 20041, Thunder Basin Coal Company v. TUCO, Inc. and Southwestern Public Service Company) on June 26, 1995, seeking a declaratory judgment of the extent of the information which must be revealed to TUCO under the coal supply contracts. That suit was amended in September 1995 to request a declaratory judgment of the issues pending in the Texas state court litigation.
Management believes that if a payment must ultimately be made to Thunder Basin it would be recoverable from ratepayers, although any such recovery would be subject to regulatory review. The Company has applied to the FERC for approval to recover, subject to refund, the $18.8 million in potential damages. Intervention has been filed and the matter is pending before the FERC. Management believes that ultimate resolution will not have a material adverse effect on the Company's consolidated financial statements.
The Company is involved in ordinary routine litigation incidental to the business which litigation is not considered material. See REGULATION, ENVIRONMENTAL MATTERS and Notes (6), (8) and (9) of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS for information on regulation, environmental and rate matters.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matter was submitted during the fourth quarter of the Company's 1995 fiscal year to a vote of its security holders.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The principal markets on which the Company's common stock is traded are the New York, Chicago and Pacific Stock Exchanges. The common stock has unlisted trading privileges on the Boston and Philadelphia Stock Exchanges. The table below presents the high and low market prices as reported by the National Quotations Bureau, Inc., and dividend information for the Company's common stock.
Market Price Dividends High Low Declared 1995 - Fiscal Quarter Ended: November 30, 1994 $27 $25-1/8 $0.55 February 28, 1995 29-3/8 25-7/8 0.55 May 31, 1995 29 27-1/4 0.55 August 31, 1995 30-3/4 28-5/8 0.55 1994 - Fiscal Quarter Ended: November 30, 1993 $32-1/2 $29-3/4 $0.55 February 28, 1994 31-1/8 27-5/8 0.55 May 31, 1994 29-1/4 23-3/4 0.55 August 31, 1994 27-1/4 24-1/8 0.55
The Company declared dividends on its common stock of $2.20 in 1995 and 1994. The Company has agreed with PSCo in the merger agreement that it will not raise its common stock dividend rate without the consent of PSCo. The Company's dividend payout on its common stock was 79% in 1995 and 93% in 1994. At August 31, 1995, the number of holders of record of the Company's common stock was 30,496.
The Company's Restated Articles of Incorporation (Articles) provide that the Company may not, without the consent of two-thirds in aggregate par value of the preferred stock outstanding, (1) declare any dividends (other than dividends payable in stock junior to the preferred stock) on, or acquire shares of such junior stock unless, after giving effect thereto, the common stock equity, as defined, is at least equal to the involuntary liquidation value of the preferred stock and any stock ranking on a parity therewith or prior thereto; or (2) make any distribution out of capital or capital surplus (other than dividends payable in junior stock) to holders of junior stock, or purchase any junior stock, if thereupon the common stock equity would be below 22% of total capitalization, as defined. If the common stock equity at the end of any fiscal year is less than 25% of total capitalization, the Company must, during the ensuing fiscal year, redeem shares of preferred stock of certain series having an aggregate par value equal to one-quarter of the amount of such deficiency. Dividends on and acquisition of common stock are prohibited during a failure to comply with such obligation. At August 31, 1995, the common stock equity represented approximately 52% of total capitalization.
The Company has called for redemption and is purchasing all of its currently outstanding Preferred Stock. The Company will seek approval of its Common Shareholders at the Annual Meeting scheduled for January 31, 1996, to amend its Articles to eliminate the current provisions with respect to Preferred Stock, including those described above, and adopt modern, flexible provisions pursuant to which new series would be issued. See MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Liquidity and Capital Resources.
The Company covenants, in the Mortgage pursuant to which First Mortgage Bonds are issued, that it will not declare any dividends (other than dividends payable in its stock) upon its common stock, or make any payment on account of the purchase, redemption or other retirement of, or make any distribution in respect of, any shares of its stock except to the extent that the sum of (1) $1,278,243.59, (2) net income of the Company, as defined, since June 1, 1946, and (3) net proceeds received by the Company from the issue since such date of any shares of its stock (but only up to an amount equal to the aggregate amount of all payments since such date on account of the acquisition of any shares of its stock) shall be (after giving effect to such dividends or distributions) greater than the aggregate amount of dividends declared on all classes of the Company's stock and of all payments made on account of the acquisition of, or distribution in respect of, any shares of its stock since such date. See Note (4) of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
In 1991 the Company adopted a Shareholder Rights Plan, which has been amended so that it is not applicable to the merger with PSCo. See Note (1) of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
References to "years" in this discussion pertain to the Company's fiscal years which begin September 1 and end August 31. References to "Notes" pertain to the Notes to Consolidated Financial Statements.
RESULTS OF OPERATIONS
Operating Revenues and Kilowatt-Hour Sales
Substantially all of the Company's operating revenues result from the sale of electric energy. The principal factors determining revenues are the amount and price per unit of energy sold. The following table describes the principal components of changes in revenues.
Variations in Kwh Sales. The revenue increases in 1995 were due primarily to increased kwh sales to rural electric cooperatives (RECs) and retail (ultimate) customers. The increase in REC sales was due primarily to Cap Rock Electric Cooperative (Cap Rock). Sales began in February 1994 and increased to 100% of Cap Rock's West Texas requirements in February 1995. Accounting adjustments to the estimate of delivered not billed kwh sales also increased kwh revenues by approximately $8.3 million. These estimated kwh sales relate to energy used by customers but not billed until the subsequent month. Increases in 1994 were due largely to increased sales to all classes of customers, but principally RECs. These increases were due in large part to dry, hot weather that favorably impacted agriculture-related sales. The Company expects modest growth in kwh sales (excluding non-firm sales) in 1996, given normal weather conditions. Current estimates of the compound annual growth rates in kwh sales for the five-year period 1996-2000 are 2.5% for wholesale sales (excluding non-firm sales) and 2.0% for retail sales. Last year the Company estimated for the period 1995-1999 that its wholesale sales growth rate would be 3.9% and the retail sales growth rate would be 1.6%. Last year's wholesale growth rate estimate was higher because it included the increase in the Cap Rock load.
Actual kwh sales by class of customer are shown in the following table:
Variations in Rates. Increased revenues for 1995 resulted primarily from additional demand charge revenues paid by certain wholesale customers. Additionally, a settlement of the 1985 Federal Energy Regulatory Commission (FERC) rate case with the Company's New Mexico wholesale REC customers contributed increased revenues of approximately $4.0 million (and interest of $3.0 million which is included in other income) (see Note 9). Revenues attributable to rate changes decreased for 1994 because of the effects of the retail rate reductions in Texas and New Mexico. In Texas reduced rates totaling approximately $13 million annually were implemented October 15, 1993. In New Mexico an approximate $4 million annual reduction, approved in September 1994, became effective April 1, 1994.
Variations in Fuel and Purchased Power Cost Recovery. Revenues decreased in 1995 due to substantially lower natural gas prices. These revenues increased in 1994 due to greater per unit fuel cost as a result of higher coal costs.
Fuel and purchased power costs are recoverable in Texas under a Public Utility Commission of Texas (PUCT) rule that provides for a fixed factor (based on known or reasonably measurable fuel costs) to be used for fuel cost collection with final approval of the amount of recoverable fuel cost being determined at the time of a utility's fuel reconciliation proceeding. If reasonably unforeseeable circumstances result in a material under-recovery of fuel costs, the utility may file a petition with PUCT requesting an emergency interim fuel factor. The Company's current fixed factor, set by the PUCT in April 1990, is based on then reasonably predictable fuel and purchased power costs. In all other jurisdictions, the Company currently recovers substantially all increases and refunds substantially all decreases in fuel and purchased power costs pursuant to monthly adjustment clauses. Currently the Company has $5.5 million in total overrecovered costs that are comprised of fuel costs totaling $3.7 million and off-system sales margin credits totaling $1.8 million. The Company refunded to its Texas retail customers margin credits on non-firm sales totaling $4.6 million in 1995. The Company is currently in a fuel reconciliation with the PUCT (see Note 9).
Variations in Non-Firm Kwh Sales. The amount of revenues arising from non-firm sales is dependent, in large part, upon the amount and cost of power available to the Company for sale, the demand for power, the availability of competing hydro-electric power from the Northwest and generation from major plants in the West. The decline in non-firm sales in 1995 was due primarily to available power from major western plants and excess hydroelectric power in the Northwest. Mild weather throughout the region, particularly in the winter, also contributed to the decline for the year. Greater non-firm sales in 1994 were due primarily to increased sales to other regional utilities. These sales were curtailed somewhat in the last quarter of 1994 and 1995 because hot weather in the Company's service territory limited the amount of power the Company had available for such sales.
Operating Expenses and Other Income
Operating Expenses. Fuel and purchased power expense comprised 55.2% of total operating expenses in 1995 and 58.0% in 1994. Such expenses, when compared to prior years, decreased 8.0% in 1995 and increased 6.5% in 1994. The decrease in 1995 is due primarily to decreased natural gas prices and decreased kwh generation. The primary reason for the rise in 1994 was increased kwh generation. The fuel cost per net kwh generated was 1.75 cents, 1.87 cents and 1.85 cents in 1995, 1994 and 1993, respectively. The decline in 1995 was due to decreased natural gas prices. The increase in 1994 was due to increased coal costs. Although fuel costs are expected to rise marginally throughout 1996, the Company plans to mitigate any such increases through the purchase of lower-priced gas on the open market and under short-term contracts, as well as using low-priced coal purchased on the spot market for generation of off-system sales.
Operating expenses, excluding fuel and purchased power, increased 2.9% in 1995 and 3.4% in 1994. The increase in 1995 was due primarily to increased federal income taxes as a result of larger taxable income. The increase in 1994 was due primarily to the adoption of Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (see Note 7). Additionally, "Taxes other than property and income taxes" were higher in 1994 because a one-time Texas franchise tax refund lowered such taxes in 1993. This refund was a result of the Company amending its returns for 1988 through 1991 to utilize accelerated instead of straight-line depreciation to determine taxable capital. In 1995 and 1994 cost-reduction and cost-control measures were implemented throughout the Company in an effort to mitigate the financial impact of retail rate reductions that resulted in lowering the level of increases in certain operating expenses. Additionally, lower depreciation rates, approved in Texas and New Mexico retail jurisdictions in conjunction with the rate cases to lower base rates, caused depreciation expense to be approximately $2.9 million lower in 1994 than it would have been under the previous rates. Property additions caused increased property taxes in 1995 and school finance reform in Texas resulted in property tax increases in 1994. Although property taxes are expected to continue to increase in 1996, the rate of increase is expected to decline. The Company has a hiring freeze in effect during the merger process (see Note 2). The Company's expenses in 1995 and 1994 were not significantly impacted by inflation.
Other Income. Other income increased 150.7% in 1995 and decreased 45.1% in 1994. The $4.3 million increase in 1995 is due primarily to approximately $3.0 million of interest on the rate case settlement with New Mexico wholesale customers and greater subsidiary earnings. The write-off in 1994 of nonrecurring items caused the decline in such income in 1994. These nonrecurring items included $2.8 million of engineering and design costs of a previously planned generating facility and contractual costs associated with other generation studies. Also included was $0.6 million of business development costs related to a generation project in the state of Missouri. Also contributing to the decrease in 1994 was a $1.4 million reduction in the equity portion of allowance for funds used during construction (AFUDC) due to reduced rates. Somewhat offsetting the effects of the nonrecurring expenses and lower AFUDC was a $1.5 million increase in subsidiary income. Subsidiary operations contributed approximately 13 cents per share to earnings in 1995 and 8 cents in 1994.
Earnings
Operating income and earnings applicable to common stock increased in 1995 due primarily to greater sales to RECs, the change in estimate of delivered not billed kwh ($5.4 million or 13 cents per share) and the rate settlement with wholesale customers in New Mexico ($4.5 million or 11 cents per share). Operating income and earnings declined in 1994 due to increased operating expenses. In 1994 the favorable effects of increased kwh sales and lower preferred stock dividends were mitigated by retail rate reductions, nonrecurring expenses, and lower AFUDC. Assuming normal weather conditions, earnings for the 1996 fiscal year are expected to remain relatively level. A favorable resolution of the 1985 FERC rate case with Texas wholesale REC customers could materially improve 1996 earnings. Quixx has entered into an agreement to sell certain water rights to the Canadian River Municipal Water Authority for $14.5 million which would result in an after-tax gain of approximately $7.6 million. The Company expects, but can give no assurance, that this sale would be completed in fiscal 1996.
The Company's average common equity for the years 1995, 1994 and 1993 was $708.5 million, $692.5 million and $684.2 million, respectively. The rate of return on average common equity for these years was 16.2%, 14.1% and 14.5%, respectively. The components of such return are presented as follows:
LIQUIDITY AND CAPITAL RESOURCES
The Company's demand for capital is normally related to the construction of utility plant and equipment. Cash construction expenditures excluding AFUDC were $94.7 million, $91.8 million and $92.3 million in 1995, 1994 and 1993, respectively. During 1995 the Company generated substantially all of its capital requirements for such purposes internally. Also in 1995, Quixx invested $28.3 million in independent power projects and expects to continue to make such investments in the future dependent upon suitable investment opportunities and the availability of capital. Estimated construction expenditures excluding AFUDC are $112.9 million for 1996 and $665 million for the five-year period 1996-2000. In 1996 the anticipated purchase of TUCO, Inc. (TUCO) from Cabot Corporation and certain Texas properties purchased from Texas New Mexico Power Company (TNP) will result in additional cash requirements of approximately $106 million (see Note 2). The portion of cash requirements to be provided by internally generated funds cannot be accurately forecast, but the Company expects that it will be approximately 40% in 1996 (including TNP and TUCO), and approximately 55% for the five-year period 1996-2000. The Company's estimates of capital needs, particularly those related to construction, and generation of internal funds are subject to review and revision, and may vary substantially from the foregoing. During the period 1996-2000, the Company will be required to retire $105 million of long-term debt, comprised of $15 million First Mortgage Bonds (Bonds), 5.70% Series due 1997 and $90 million Bonds 6.875% Series due 1999.
In addition, as discussed under BUSINESS-General, the Company has called for redemption as of December 27, 1995, all of its outstanding Preferred Stock which is redeemable by its terms and will purchase all of the outstanding 2,600 shares of its 14.50% Cumulative Preferred Stock which is not redeemable by its terms. As a consequence, following the redemptions and purchase, there will be no shares of Preferred Stock outstanding. The Company will seek approval of the holders of its Common Stock at its Annual Meeting to be held on January 31, 1996, to amend its Articles relating to the Preferred Stock in order to provide for updated provisions and eliminate covenants imposed by the current provisions. The aggregate redemption price of the outstanding shares of stock which are to be redeemed is approximately $75 million, including accrued dividends. The purchase price of the non-redeemable 14.50% Cumulative Preferred Stock is being negotiated. The Company plans to finance the redemption and purchase of the Preferred Stock with the use of short-term borrowings, which would be repaid subject to market conditions with the issuance of new Preferred Stock following the Annual Meeting in January 1996 or with the issuance of Bonds during 1996. The estimates set forth in the preceding paragraph do not include the issuance of securities to obtain the funds required for the Preferred Stock redemptions and purchase. The Company currently contemplates the sale of other Preferred Stock, Common Stock and Bonds during the five-year period 1996-2000 in connection with the financing of its construction program and retirement of Bonds.
In August 1994 the Company entered into a forward interest rate swap agreement in anticipation of redeeming its $25 million principal amount of 13-1/2% pollution control revenue bonds with a new issuance of variable rate pollution control revenue bonds. Such bonds are not redeemable until October 1, 1996 (see Note 4).
The Company has effective a shelf registration under which a remaining aggregate of $130 million of First Mortgage Bonds and Cumulative Preferred Stock may be issued (a maximum of $40 million of Preferred Stock is issuable thereunder). At August 31, 1995, the Company maintained committed bank lines of credit aggregating $128 million, of which the Company had no borrowings outstanding at fiscal year-end.
OTHER MATTERS
Electric utilities have historically operated in a highly regulated environment in which they have an obligation to provide electric service to their customers in return for an exclusive franchise within their service territory with an opportunity to earn a regulated rate of return. This regulatory environment is changing. The generation sector has experienced competition from nonutility power producers, and the FERC is requiring utilities, including the Company, to provide wholesale transmission service to others and may order electric utilities to enlarge their transmission systems to facilitate transmission services. Some state regulatory authorities are in the process of changing utility regulations in response to federal and state statutory changes and evolving markets (see Note 8). In partial response to these changing conditions, the Company has entered into a definitive merger agreement with Public Service Company of Colorado (the Merger). Consummation of the Merger is subject to customary conditions including receiving shareholder and regulatory authority approvals. The two utilities are working toward a completion date in the fall of 1996 (see Item 1. BUSINESS-General and Note 2). The foregoing discussions of the Company's results of operations and liquidity and capital resources do not take into account any changes that could arise as a result of the Merger.
The foregoing discussion and analysis by management is intended to provide a summary of information relevant to an assessment of the financial condition and results of operations of the Company and should be read together with the Consolidated Financial Statements and Notes to Consolidated Financial Statements in order to arrive at a more complete understanding of such matters.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders Southwestern Public Service Company:
We have audited the accompanying consolidated balance sheets and statements of capitalization of Southwestern Public Service Company and subsidiaries as of August 31, 1995 and 1994, and the related consolidated statements of earnings, common shareholders' equity and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Public Service Company and subsidiaries as of August 31, 1995 and 1994, and the results of their operations and their cash flows for the years then ended, in conformity with generally accepted accounting principles.
As discussed in Notes 1 and 7 to the consolidated financial statements, in 1994, the Company changed its method of accounting for income taxes and postretirement benefits other than pensions to conform with Statements of Financial Accounting Standards No. 109 and No. 106, respectively.
DELOITTE & TOUCHE LLP
Dallas, Texas October 10, 1995
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders Southwestern Public Service Company:
We have audited the accompanying consolidated statements of earnings, common shareholders' equity and cash flows of Southwestern Public Service Company and subsidiaries for the year ended August 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 audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Southwestern Public Service Company and subsidiaries for the year ended August 31, 1993, in conformity with generally accepted accounting principles.
KPMG Peat Marwick LLP
Amarillo, Texas October 8, 1993
SOUTHWESTERN PUBLIC SERVICE COMPANY
Notes To Consolidated Financial Statements August 31, 1995
(1) Nature of Operations and Summary of Significant Accounting Policies
GENERAL
Southwestern Public Service Company (the Company) is principally engaged in the generation, transmission, distribution and sale of electric energy. The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and as adopted by the Public Utility Commission of Texas (PUCT), the New Mexico Public Utility Commission (NMPUC), the Oklahoma Corporation Commission and the Kansas Corporation Commission.
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, Utility Engineering Corporation (UE) and Quixx Corporation and subsidiaries (Quixx). UE is primarily engaged in engineering, design and construction management. Quixx invests in cogeneration projects and holds water rights and certain other nonutility assets. The aggregate net earnings of UE and Quixx of $5,216,000, $3,335,000 and $1,868,000 in 1995, 1994 and 1993, respectively, are included in net other income in the Consolidated Statements of Earnings. All significant intercompany transactions and balances are eliminated in consolidation.
UTILITY PLANT
Utility plant is stated at the historical cost of construction, which includes labor, materials, an allowance for funds used during construction and indirect charges for such items as engineering, supervision and general administrative costs. Maintenance, repairs and minor replacements are charged to operating expense; major replacements and betterments are capitalized.
The cost of depreciable units of utility plant retired or disposed of in the normal course of business is eliminated from utility plant accounts and such cost plus removal expenses and less salvage value 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.
The provision for depreciation is computed on a straight-line method at rates based on the estimated service lives and salvage values of the several classes of depreciable property as indicated by periodic depreciation studies. Depreciation as a percentage of average depreciable cost was 2.86% in 1995, 2.83% in 1994 and 2.96% in 1993.
OPERATING REVENUES
Electric rates include estimates of fuel costs incurred by the Company in the generation or purchase of electricity. Differences between amounts collected and allowable costs are recorded as over/underrecovered fuel and purchased power costs in accordance with ratemaking policies of regulatory authorities. Such overrecovered fuel and purchased power costs are reflected as liability for refunds to customers in the accompanying consolidated financial statements.
Included in operating revenues is an estimate of revenues for electric services provided but not billed. In 1995 the Company made accounting adjustments to the estimate of delivered not billed kwh sales which increased operating revenues by approximately $8,300,000 and net income by approximately $5,400,000, or 13 cents per share.
DEFERRED DEBITS
Losses on Early Retirements of Debt
Losses on early retirements of debt refinanced by new lower coupon debt issues are amortized on a straight-line basis over the lives of the new issues. Losses on early debt retirements not refinanced by new issues are amortized on a straight-line basis over the remaining original lives of the retired debt. Amortization of such amounts is included in other interest charges in the Consolidated Statements of Earnings. The unamortized balances of losses on early retirements of debt are approximately $21,262,000 and $22,766,000 as of August 31, 1995 and 1994, respectively (see Note 4).
Debt Premium, Discount and Expense
Expenses incurred in connection with the issuance of long-term debt, and premiums and discounts relating to such debt, are being amortized or accreted on a straight-line basis over the lives of the respective issues.
Other Assets
Included in deferred debits are other assets that are expected to benefit future periods and certain costs that, for rate making purposes, are recorded as deferred charges and amortized over periods allowed by regulatory authorities.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The allowance for funds used during construction (AFUDC) is designed to allow the Company to capitalize the net composite interest and equity costs of capital funds used to finance plant additions during construction periods and does not represent current cash income. Established regulatory rate practices permit the Company to recover these costs in future periods by fixing rates to include a fair return on, and a recovery of, these capital costs through their inclusion in the rate base and cost of service. The composite rates used for AFUDC were 6.5% in 1995, 6.2% in 1994 and 9.9% in 1993. Such rates reflect semiannual compounding.
INCOME TAXES
On September 1, 1993, the Company adopted, on a prospective basis, as required by the FERC, Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (Statement 109). Statement 109 requires a change from the deferred method to the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized for the tax consequences of "temporary differences" by applying enacted tax rates applicable to the differences between the financial statement amounts and the tax bases of existing assets and liabilities.
Statement 109 requires the Company to recognize deferred income tax liabilities for the temporary differences including cumulative unrecognized timing differences as well as certain new items such as the equity portion of AFUDC and unamortized investment tax credits. Certain provisions of Statement 109 provide that regulated enterprises are permitted to recognize adjustments resulting from the adoption of Statement 109 as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers through future rates. Accordingly, the Company recorded additional deferred income tax liabilities and corresponding regulatory assets of approximately $78,000,000 in 1994. The adoption of Statement 109 did not have a material effect on results of operations.
Investment tax credits have been deferred and are being amortized to income over the life of the related property.
CASH FLOWS
The Company uses the direct method of presentation for cash flows from operating activities. For purposes of the Consolidated Statements of Cash Flows, the Company considers all highly liquid investments purchased with a maturity of three months or less to be cash equivalents. The Company records such investments at cost which approximates market value.
EARNINGS PER COMMON SHARE
Earnings per share of common stock is computed for each year based upon the weighted average number of common shares outstanding. The effect of stock awards and options outstanding under the Company's 1989 Stock Incentive Plan is not significant (see Note 7).
The Company has a Shareholder Rights Plan (the Rights Plan) designed to ensure that all shareholders receive fair and equal treatment in the event of any proposal to acquire control of the Company. Under the Rights Plan, each shareholder holds one right for each share of the Company's common stock held of record. Each right entitles the holder to purchase one share of the Company's common stock for $70 in the event a person or group acquires 10% or more of the Company's common stock. Under certain circumstances, the holders of the rights will be entitled to purchase common shares of the Company at one half of the current market price. In addition, any time after a person or group acquires 10% or more of the Company's outstanding common shares, the board of directors may, at its option, exchange part or all of the rights for shares of common stock of the Company. The Company will be entitled to redeem the rights for $0.01 per right at any time until the tenth day following a public announcement of the acquisition of 10% of its common shares. The rights expire in 2001, unless earlier redeemed or exchanged by the Company, and have no effect on operating results or earnings per share. This Rights Plan has been amended to provide that the merger agreement with Public Service Company of Colorado (PSCo) will not trigger the provisions of the Rights Plan.
FAIR VALUES OF FINANCIAL INSTRUMENTS
The fair value amounts of certain financial instruments included in the accompanying Consolidated Balance Sheets as of August 31, 1995 and 1994 are as follows:
The fair values of cash and temporary investments approximate the carrying amount because of the short maturity of those instruments.
The estimated fair values of long-term debt and preferred stock are based on quoted market prices of the same or similar issues. The estimated fair values of long-term debt and preferred stock are as follows:
The fair values of other financial instruments for which estimated fair values have not been presented are not materially different than the related book values.
The fair value estimates presented herein are based on pertinent information available to management as of August 31, 1995 and 1994. These fair value estimates have not been comprehensively revalued for purposes of these financial statements since that date, and current estimates of fair values may differ significantly from the amounts presented herein.
NEW ACCOUNTING STANDARDS
In March 1995 the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (Statement 121). Statement 121 requires that long lived assets and certain identifiable intangibles to be held and used by an entity be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The statement also requires that rate-regulated enterprises recognize an impairment for the amount of costs excluded when a regulator excludes all or part of a cost from the enterprise's rate base. The adoption of Statement 121, which will be required in 1997, is not expected to have a material effect on the Company's consolidated financial position or results of operations.
(2) Merger and Acquisitions
MERGER WITH PUBLIC SERVICE COMPANY OF COLORADO
The Company and Denver-based PSCo entered into a definitive merger agreement (the Merger) on August 22, 1995, to form a registered public utility holding company, which will be the parent company for the Company and PSCo. The transaction is subject to various conditions, including receipt of the approval of the shareholders of the Company and PSCo, as well as the approval of or the taking of other action by the Securities and Exchange Commission, the Federal Trade Commission, the Department of Justice, the Nuclear Regulatory Commission, the Federal Energy Regulatory Commission, and the state public utility commissions in Texas, Colorado, New Mexico, Wyoming, and Kansas.
The Merger, with a targeted completion date in the fall of 1996, is conditioned on qualifying as a tax-free reorganization and being accounted for as a pooling of interests.
Upon completion of the Merger, holders of the Company and PSCo common stock will receive 0.95 of one share and one share of the new holding company common stock, respectively, for each share of stock held. As of August 4, 1995, the Company and PSCo had 40,917,908 and 63,109,140 shares, respectively, of common stock outstanding. Based on that number of shares outstanding and the conversion ratios, the Company and PSCo shareholders would own 38.1 percent and 61.9 percent, respectively, of the common equity of the new holding company. The debt (including mortgage bonds) and preferred stock outstanding at the time of the effectiveness of the Merger will remain outstanding debt and preferred stock of the Company.
The board of directors of the new holding company will consist of six and eight current directors of the Company and PSCo, respectively.
ACQUISITION OF TNP PROPERTIES
On December 6, 1994, the Company signed a definitive agreement with Texas-New Mexico Power Company (TNP) for the purchase of certain Texas properties located in the Panhandle area for $29.2 million. These Panhandle area properties are located in the cities of Spearman, Perryton, Booker, Follett, Higgins and Darrouzett located in Hansford, Ochiltree and Lipscomb counties. The purchase was completed September 15, 1995, and added approximately 7,300 customers. Rates in the affected communities were immediately reduced by 10% and other rate decreases will follow over a ten-year period until the new customers are at the same rates as the Company's other customers in its Texas service area. In June 1995 the Company received approval from the PUCT to commence retail electric service to the Panhandle area properties. Cost recovery of the purchase amount in excess of book value of approximately $14,000,000 was allowed by FERC and the PUCT through a rate surcharge over a ten-year period. This purchase will not have a significant impact on results of operations of the Company.
ACQUISITION OF TUCO, INC.
The Company has agreed to purchase TUCO, Inc. (TUCO), a wholly owned subsidiary of Cabot Corporation, for $77,000,000 subject to regulatory approval and other conditions. TUCO owns the coal inventory maintained at the Company's Harrington and Tolk generating stations. It also administers contracts with coal mines, railroads and the coal-handling operator at the two coal-fueled power plants. This purchase is expected to lower fuel costs. Regulatory approval is expected in 1996.
(3) Short-Term Debt
Unsecured borrowings permitted under bank lines of credit were $128,000,000 in 1995 and $70,000,000 in 1994.
(4) Capitalization
CUMULATIVE PREFERRED STOCK
The Company is limited in the amount of preferred stock that it can issue by certain restrictions contained in the Restated Articles of Incorporation (Articles). As a condition to the issuance of additional shares of preferred stock, the Articles require that net earnings, as defined, for 12 consecutive calendar months within the 15 immediately preceding calendar months, must be at least 1.5 times the annual interest requirements on funded debt, as defined, plus annual dividend requirements on preferred stock (or any stock ranking on a parity). Such ratio for the year ended August 31, 1995, was 3.34. The Articles also limit the amount of restricted indebtedness, as defined, that may be issued or assumed by the Company without the consent of the holders of two-thirds of the aggregate par value of the preferred stock outstanding. Under this limitation approximately $379,000,000 of additional restricted indebtedness could have been issued or assumed as of August 31, 1995. Such limitation would also prevent the issuance of bonds against property additions unless, after giving effect to the use of the proceeds from such issuance, such restricted indebtedness limitation is met.
In the event of voluntary liquidation of the Company, holders of the cumulative preferred stock have a preference to the extent of amounts payable on redemption plus accrued dividends, and in the event of involuntary liquidation, to the extent of par value plus accrued dividends.
The 7-5/8% and 9.68% series cumulative preferred stock were redeemed from the proceeds of the December 1992 issuance of First Mortgage Bonds (see LONG-TERM DEBT below).
LONG-TERM DEBT
First Mortgage Bonds (Bonds) issued under the Indenture of Mortgage and Deed of Trust dated August 1, 1946, as supplemented and amended (Mortgage), are secured by substantially all of the Company's utility plant. The Mortgage limits the maximum principal amount of Bonds that may be outstanding thereunder to $3,000,000,000 and contains provisions relating to the restriction of the payment of dividends on common stock. At August 31, 1995, approximately $949,000 of total retained earnings of $373,458,000 was so restricted.
The Company is limited in the amount of Bonds that it can issue by certain restrictions contained in the Mortgage. The Mortgage permits the issuance of Bonds against 60% of certain property additions, against certain retired Bonds or against deposited cash. Property additions and retired Bonds available for the issuance of Bonds were approximately $335,000,000 and $115,300,000, respectively, at August 31, 1995, which would permit issuance of $316,300,000 of additional Bonds. Substantial amounts of property additions are used by the Company to satisfy a maintenance fund covenant and improvement fund obligations under the Mortgage. The Mortgage also provides that, with certain exceptions, additional Bonds may not be issued unless net earnings, as defined, are at least twice the annual interest requirements on all Bonds outstanding and then to be issued and on all prior lien indebtedness. Such ratio for the year ended August 31, 1995, was 5.53.
In February 1995 the Company retired $16,000,000 of Bonds, 4-5/8% Series due 1995 and in February 1994 retired $25,000,000 of Bonds, 4-1/2% Series due 1994.
In February 1995 the Company issued $70,000,000 of additional Bonds of 8.50% Series due 2025. The proceeds from these Bonds were applied primarily to the retirement of short-term debt.
In December 1992 the Company issued $190,000,000 of additional Bonds consisting of $90,000,000 of 6.875% Series due 1999 and $100,000,000 of 8.20% Series due 2022. The proceeds from these Bonds were applied to the redemption of outstanding Bonds as follows: (i) 8.45% Series due 2001, (ii) 7-5/8% Series due 2002, (iii) 8-3/8% Series due 2007, and (iv) 9-1/8% Series due 2016, and also cumulative preferred stock as follows: (i) 82,960 shares of 7-5/8% preferred stock and (ii) 170,000 shares of 9.68% preferred stock. In connection with this redemption, the Company incurred a loss of approximately $10,575,000, including redemption premiums of $9,315,000; $10,192,000 of such loss was deferred and is being amortized over the lives of the new issues and $383,000 relating to the preferred stock was charged to retained earnings (see Note 1).
The Red River Authority of Texas has issued certain obligations, based on long-term installment sale agreements executed by the Company, that relate to the pollution control facilities installed at the Company's coal-fueled generating units. The Company's payments under the pollution control obligations are pledged to secure the Red River Authority Pollution Control Revenue Bonds.
In August 1994 the Company entered into a forward interest rate swap agreement in anticipation of redeeming its $25,000,000 principal amount of 13-1/2% pollution control revenue bonds with a new issuance of variable rate pollution control revenue bonds. The 13-1/2% bonds are not redeemable until October 1, 1996. The interest rate swap will commence in September 1996 on a $25,000,000 notional amount which, in effect, fixes the interest rate on the bonds to be issued at 6.435%. The swap agreement may be terminated by the Company at any time or by the other party, upon the occurrence of specified events. If terminated, the Company may be required to make a payment or may receive a payment to settle any gains or losses resulting from the termination. The amount of any settlement, which could be substantial, is dependent upon market interest rates at the time of settlement. If the forward interest rate agreement had been terminated at August 31, 1995, the Company would have been required to pay approximately $3,765,000; however, the Company would then have received the benefit of an interest rate lower than 6.435% on the bonds to be issued. The Company is exposed to interest rate risk in the event of nonperformance by the other party to the swap agreement; however, the Company does not anticipate nonperformance by the counter party.
The trust indenture for the 1991 Series of pollution control obligations permits the Company to choose between various interest rate options, including the option to convert to a fixed rate. Currently, the interest rate is adjusted weekly and as of August 31, 1995 and 1994, the interest rate was 3.45% and 3.15%, respectively.
The 1991 Series may be subject to tender for purchase at the option of the holder and will be subject to mandatory tender at certain times. The Company entered into a credit agreement with a bank to provide liquidity support in connection with the optional and mandatory tenders. The Company has also entered into a remarketing agreement to provide for the remarketing of any tendered bonds. The credit agreement is scheduled to expire on July 1, 1997. Based upon the Company's intent and ability to remarket such obligations, the 1991 Series obligations have been classified as long-term debt.
Aggregate maturities of long-term debt for each of the years in the five-year period subsequent to August 31, 1995, are as follows: 1996, $276,000; 1997, $15,176,000; 1998, $229,000; 1999, $0; and 2000, $90,000,000. Sinking fund and improvement fund requirements are not significant.
(5) Income Taxes
The components of income tax expense (benefit) for the years ended August 31, 1995, 1994 and 1993 are as follows:
The provisions (credits) for deferred income taxes that arise from temporary differences between financial and tax reporting for the years ended August 31, 1995, 1994 and 1993, are as follows:
Total income tax expense for the years ended August 31, 1995, 1994, and 1993 differs from the amounts computed by applying the statutory federal tax rates (35% in 1995 and 1994, 34.67% in 1993) to earnings before income taxes for the following reasons:
Property-related differences increase income tax expense due primarily to the reversal of depreciation and basis differences.
The significant components of the Company's deferred tax assets and liabilities, which are reflected net in the accompanying Consolidated Balance Sheets at August 31, 1995 and 1994, are as follows:
(6) Commitments, Contingencies and Financial Guarantees
SYSTEM PURCHASE OPTION
The Company and the City of Las Cruces, New Mexico (the City) entered into a System Purchase Option and Rate Agreement in August 1994, which grants the City the option to sell to the Company the electric utility system serving the City (including distribution, subtransmission, and transmission facilities), which the City plans to acquire from El Paso Electric Company (EPE) by purchase or through condemnation proceedings. The agreement has a three-year term beginning at the time the City acquires the facilities and ending no later than January 1, 2002. The purchase price which would be paid by the Company would be equal to the amount required to retire all outstanding debt incurred by the City in acquiring the facilities plus the city's reasonable costs in acquiring the facilities. The Company has the right to terminate the agreement if, in the Company's sole discretion, it determines that any proposed condemnation award is excessive or upon the occurrence of certain other events. The agreement also provides that, if the City abandons or dismisses condemnation proceedings as a consequence of the Company's termination of the agreement, the Company will reimburse the City for one-half of its reasonable litigation expenses and for any of EPE's damages and litigation expenses that the City is obligated to pay by final court order.
FUEL PURCHASE COMMITMENTS
In the ordinary course of business, the Company has made substantial commitments with respect to the purchase of coal and natural gas for use as fuel in its generating units. To provide fuel for its coal-fueled generating units, the Company has various long-term commitments with TUCO for the purchasing and processing of coal which is delivered to the Company's coal bunkers in the form of crushed, ready-to-burn coal. The commitments include the use of rail coal cars, unloading facilities and related services. Such commitments in 1995 dollars for the remaining term of the contract are approximately $1,756,000,000. The contracts for coal supply, transportation and other services expire in 2001, 2002 and 2016, respectively.
In May 1995 the Company agreed to purchase TUCO from Cabot Corporation for $77,000,000 (see Note 2).
FINANCIAL GUARANTEES
In connection with an agreement for the sale of electric power, the Company guaranteed certain obligations of a customer totaling $48,000,000. These obligations relate to the construction of certain utility property, that in the event of default by the customer, would revert to the Company. In connection with a Quixx investment, Quixx has provided a financial guarantee totaling $8,900,000 to fund any construction cost overruns and other project contingencies. Should additional funds be provided, Quixx's ownership position in that project may be altered.
ENVIRONMENTAL MATTERS
The Company's facilities 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 Company has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Company facilities have been designed and constructed to operate in compliance with environmental standards.
Beginning in the year 2000, the Clean Air Act Amendments of 1990 (CAAA) Phase II will require more stringent limits on SO2 emissions at the Company's existing fossil-fueled plants. However, current regulations permit compliance with sulfur emissions limitations in the year 2000 by using SO2 allowances allocated to plants by the Environmental Protection Agency (EPA), using allowances generated by reducing emissions at existing plants and by using allowances purchased from other companies. Based upon information from the Company's fuel suppliers, the SO2 allowances issued by the EPA approximate the Company's projected SO2 emissions. The Company monitors options to ensure that allowances will be sufficient to economically operate the Company's existing plants without significant emission reductions. The CAAA also requires the EPA to develop new oxides of nitrogen (NOx) emission standards for existing and new plants which may be more stringent than the current standards. The Company anticipates being able to comply with Phase II NOx emission standards with no additional material capital cost. The Company continues to monitor the impact that the CAAA may have on the Company.
Capital expenditures for environmental protection facilities aggregated approximately $4,100,000, $11,600,000, and $4,500,000 for 1995, 1994 and 1993, respectively. Estimates of future capital expenditures for environmental protection facilities are subject to change but the Company has included approximately $11,700,000 in its construction program for these expenditures during the five years ending August 31, 2000, of which approximately $2,300,000 is for 1996.
The Company has not developed any specific site removal and exit plans for its fossil fuel plants or substation sites. Plant removal and exit plans are under development, and when such plans are developed in the future, the Company intends to treat removal and exit costs as a cost of retirement in utility plant and include them in depreciation accruals. An estimated removal cost (based on historical experience) is currently included in depreciation expense.
THUNDER BASIN LAWSUIT
The Company was named as a defendant in a case entitled Thunder Basin Coal Co. v. Southwestern Public Service Co., No. 93-CV-304B (D. Wyo.). Thunder Basin's Wyoming lawsuit in federal court went to trial in late October 1994. On November 1, 1994 the jury returned a verdict in favor of Thunder Basin and against the Company finding that there had been a partial repudiation of the contract and that the Company had interfered with Thunder Basin's contract with TUCO. The jury awarded damages to Thunder Basin of approximately $18,800,000. The Company has appealed the judgment to the Tenth Circuit Court of Appeals and the appeal is progressing.
Management believes that in the event a payment is ultimately required to be made to Thunder Basin it would be recoverable from ratepayers, although any such recovery would be subject to regulatory review. Management believes that the ultimate resolution will not have a material adverse effect on the Company's consolidated financial statements.
OTHER
The Company is a defendant in various claims and legal actions, primarily workers' compensation, contractual matters and general liability lawsuits, all arising in the normal course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company's consolidated financial statements.
(7) Employee Benefit Plans
DEFINED BENEFIT PLANS
The Company has a noncontributory defined benefit retirement plan (the Retirement Plan) which provides retirement and certain other benefits to its officers and employees. The Company's policy is to fund the accrued costs of the Retirement Plan. Assets of the Retirement Plan consist primarily of U.S. government and agency obligations, bonds and common stocks (including 586,236 shares of common stock of the Company with an estimated fair market value of $17,587,080 as of August 31, 1995).
Additionally, the Company has a noncontributory defined benefit supplemental retirement income plan (the Supplemental Plan) for qualifying executive personnel. The Supplemental Plan is unfunded, and benefits due under the plan are paid out of the Company's general funds.
Net periodic pension cost for the Retirement and Supplemental Plans, as determined using the projected unit credit actuarial cost method for the years ended August 31, 1995, 1994 and 1993, is presented below:
The funded status of the Retirement and Supplemental Plans and amounts recognized in the Company's Consolidated Balance Sheets as of August 31, 1995 and 1994 is presented below:
The current and noncurrent portions of the accrued pension liability are included in other current liabilities and other deferred credits, respectively, in the accompanying Consolidated Balance Sheets.
The assumed discount rate and the rate of increase in compensation levels used in determining the actuarial present value of the projected benefit obligations were 8% and 6%, respectively. The expected long-term rate of return on plan assets was 8%. Plan assets and liabilities are valued each year using a measurement date of June 30.
HEALTH AND WELFARE BENEFIT PLANS
The Company provides health care and life insurance benefits to its active and retired employees through various health and welfare benefit plans. In 1994 the Company adopted Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (Statement 106). Statement 106 requires accrual of postretirement benefits other than pensions (primarily group term life insurance, medical and dental benefits provided to retired employees) during the years an employee provides services. Statement 106 also requires employers to recognize the costs of benefits already earned by active employees as of the date of adoption of Statement 106 (the Transition Obligation).
The accrual of postretirement costs was comprised of: (1) the portion of the expected postretirement benefit obligation attributable to employee service during the period, (2) amortization of the Transition Obligation and (3) interest costs associated with the unfunded accumulated obligation for future benefits. An assumed discount rate of 8% was used to develop the associated interest costs. The assumed health care cost trend rate used to measure the expected cost of benefits was 12% for 1995 and was assumed to diminish to a level of 5.5% in 2007 and thereafter. The Transition Obligation of approximately $58,000,000 is being amortized over a 20-year period. A one percentage point increase in the assumed health care cost trend rate in each future year would increase the accumulated postretirement benefit obligation (APBO) at August 31, 1995, by approximately $8,000,000 and other postretirement benefits cost for 1995 by approximately $900,000.
These postretirement costs have historically been included in rates when paid. Federal and state agencies that regulate the Company have issued guidelines permitting recovery of such additional costs on an accrual basis. In Texas and New Mexico, which represent approximately 72% of the Company's revenues, the Company was permitted in its rate settlements to recover the additional costs. The Company is required to deposit the amounts included in Texas and New Mexico rates in an irrevocable external trust dedicated to the payment of these postretirement benefits. In remaining jurisdictions, the Company is permitted to recognize regulatory assets for the difference between any amounts recorded currently and those required under Statement 106. At August 31, 1995 and 1994, deferred debits in the Consolidated Balance Sheets include $2,500,000 and $1,700,000, respectively, that represent the future revenues expected to be realized at the time the additional postretirement benefits are included in the Company's rates.
The Company's net periodic postretirement benefits cost other than pensions for the years ended August 31, 1995 and 1994, including amounts capitalized, were comprised of the following components:
The funded status for other postretirement benefits and amounts recognized by the Company at August 31, 1995 and 1994, is presented below:
The Company's cost of providing other postretirement benefits in 1993, which was recognized on a "pay-as-you-go" basis, was approximately $2,280,000.
DEFINED CONTRIBUTION PLANS
The Company has an Employee Stock Ownership Plan and a 401(k) plan. Total contributions to the plans by the Company for the years ended August 31, 1995, 1994 and 1993 were approximately $1,469,000, $983,000 and $993,000, respectively. Effective March 1, 1995, the plan assets of the Employee Stock Ownership Plan and 401(k) plan were combined into one plan called the Employee Investment Plan.
OTHER BENEFIT PLANS
The Company's 1989 Stock Incentive Plan provides for awards of share options and restricted shares, and delivery of shares in certain cases. The number of shares of common stock of the Company registered in connection with this plan is 800,000, the maximum amount that may be awarded prior to July 25, 1998.
Stock options have been awarded to key employees under the 1989 Stock Incentive Plan. Options granted under the plan have an exercise price equal to the fair market value of the common stock on its award date. At August 31, 1995, there were 22 participants in the plan. Options generally become exercisable evenly over nine years and expire ten years after the date of the grant.
At August 31, 1995, approximately 81,200 restricted shares of common stock have been awarded to employees, generally subject to a ten-year vesting requirement. The cost of shares awarded are charged to expense over a ten-year period based on the fair market value at date of award.
The Company has a Directors' Deferred Compensation Plan under which directors of the Company or its subsidiaries may elect to defer the distribution of all or a percentage of the annual retainer or meeting fees, or both, otherwise currently payable to such directors.
(8) Competitive Environment and Regulatory Assets and Liabilities
Electric utilities have historically operated in a highly regulated environment in which they have an obligation to provide electric service to their customers in return for an exclusive franchise within their service territory with an opportunity to earn a regulated rate of return. This regulatory environment is changing. The generation sector has experienced competition from nonutility power producers, and the FERC is requiring utilities, including the Company, to provide wholesale transmission service to others and may order electric utilities to enlarge their transmission systems to facilitate transmission services.
The changing regulatory environment has stimulated competition in the wholesale electric markets by creating a new class of independent power producers. Revisions to the Public Utility Holding Company Act of 1935 (PUHCA) have allowed both utilities and non-utilities to form independent power production companies called exempt wholesale generators (EWGs), which operate without the restrictions of the PUHCA. EWGs offer alternative sources of power supply to electric utilities across the country. Utilities are often required by state regulation to solicit to purchase power from nonutility power producers and other utilities before seeking approval to construct new generation of their own.
Some state regulatory authorities are in the process of changing utility regulations in response to federal and state statutory changes and evolving markets. Texas legislation enacted in 1995 recognizes the movement to a more competitive marketplace by requiring the PUCT to issue new regulations including: allowance of less than fully costed rates in wholesale and retail markets; recognition of and essentially waiving all Texas utility regulation of EWGs and power marketers; and implementation of transmission access comparable to the owning utility's use of its transmission system for non-FERC regulated utilities. The Company believes that these statutory and conforming regulations may result in increased wholesale competition. However, due to the Company's low cost structure, increased wholesale competition is not expected to adversely affect it in the near term and may favorably impact it in the long term.
The New Mexico legislature rejected retail wheeling proposals; however, it continued post-session committee investigation of the matter. All of the Company's jurisdictions continue to evaluate utility regulations with respect to competition.
The Company currently applies accounting standards that recognize the economic effects of rate regulation. Regulatory assets represent probable future revenue associated with certain costs which will be recovered from customers through the ratemaking process. Regulatory liabilities represent costs previously collected that are refundable in future rates. If rate recovery of generation-related and other costs becomes unlikely or uncertain, whether due to competition or regulatory action, these accounting standards may no longer apply to the Company.
Regulatory assets and liabilities reflected in the Consolidated Balance Sheets as of August 31, 1995 and 1994, are as follows:
As of August 31, 1995, the Company's regulatory assets are being recovered through rates charged to customers over periods ranging from ten to thirty years. Under current rates, the Company is recovering approximately $8,000,000 of regulatory costs per year. Based on prior and current rate treatment of such costs, management believes it is probable that the Company will continue to recover from ratepayers the regulatory assets described above.
In July 1995 the Company negotiated a settlement with the PUCT and various intervenors. As part of this agreement, the Company is required to perform certain demand side management activities and is allowed to defer the costs of these activities and include them in rate base and cost of service in future PUCT proceedings.
(9) Rate Matters
The Company may effect changes in its rates only as approved by the regulatory authorities governing its jurisdictions. Amounts ultimately realized will differ from amounts approved because kilowatt-hour sales and other factors will vary from those approved in the rate proceedings.
A PUCT substantive rule requires periodic examination of the Company's fuel and purchased power costs, the efficiency of the use of such fuel and purchased power, fuel acquisition and management policies and purchase power commitments (see Item 1. Business Fuel Supply and Purchased Power). On May 1, 1995, the Company filed with the PUCT a petition for a fuel reconciliation for the months of January 1992 through December 1994. A hearing was held in September 1995 and the Commission staff has recommended some disallowances which the Company opposes and which are subject to final ruling by the PUCT. The Company's management is unable to predict the ultimate outcome; however, they believe the final determination of this matter will not significantly affect consolidated financial results.
On December 19, 1989, the FERC issued its final order regarding the 1985 rate case. The Company appealed certain portions of the order that related to recognition in rates of the reduction of the federal income tax rate from 46% to 34%. The United States Court of Appeals for the District of Columbia Circuit remanded the case, directing the FERC to reconsider the Company's claim of an offsetting cost and limiting the FERC's actions. The FERC issued its Order on Remand in July 1992, required filings were made and a hearing was completed in February 1994. In October 1994 the administrative law judge issued a favorable initial decision that, if approved by the FERC, would result in a substantial recovery by the Company. Negotiated settlements with the Company's partial requirements customers and Texas- New Mexico Power Company were approved by the FERC in July 1993 and September 1993, respectively, and the Company received approximately $2,800,000. In a settlement with the Company's New Mexico cooperative customers the Company received approximately $7,000,000, including interest. The FERC approved this settlement in July 1995. Resolutions with the remaining wholesale customers, Golden Spread member cooperatives and Lyntegar Electric Cooperative have not been reached. The Company cannot reasonably estimate the remaining amount recoverable from these proceedings; however, a favorable resolution could materially improve 1996 consolidated earnings.
10) Quarterly Operating Results (Unaudited)
The following quarterly operating results are unaudited, but, in the opinion of management, include all adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the Company's operating results for the periods indicated.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
As previously reported on Form 8-K dated April 27, 1993, the Company notified its certifying accountants, KPMG Peat Marwick LLP (KPMG), that the client-auditor relationship between the Company and KPMG was terminated effective with the completion of the 1993 financial audit. Additionally, the Company announced its new certifying accountants, DELOITTE & TOUCHE LLP, to serve as independent accountants for the fiscal year 1994 and 1995. The decision to change accountants was recommended by the Audit Committee and approved by the Board of Directors.
KPMG's report on the Company's financial statements for the 1993 fiscal year contained no adverse opinion or disclaimer of opinion, and was not qualified or modified as to uncertainty, audit scope, or accounting principles.
During the 1993 fiscal year and up to the audit completion date, there were no disagreements between the Company and KPMG on any matters of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of KPMG, would have caused KPMG to make a reference to the subject matter of the disagreements in connection with its reports.
None of the "reportable events" described under Regulation S-K, Item 304(a)(1)(v), occurred within the Company's two most recent fiscal years.
During the 1993 fiscal year, prior to their appointment as certifying accountants, the Company did not consult DELOITTE & TOUCHE LLP regarding any of the matters or events set forth in Item 304(a)(2)(i) and (ii) of Regulation S-K.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.*
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.*
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.*
To the knowledge of the Company, no person is the beneficial owner of more than 5% of any class of the Company's voting securities.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.*
*The information required by Items 10, 11, 12 and 13 with respect to directors and officers to the extent not set forth under Item 1 of Part I in this Form 10-K (pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K) under "Executive Officers of the Registrant," is set forth in the Company's proxy statement for its Annual Meeting of Shareholders to be held January 31, 1996, which is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
FINANCIAL STATEMENTS Independent Auditors' Reports Consolidated Balance Sheets as of August 31, 1995 and 1994 Consolidated Statements of Capitalization as of August 31, 1995 and 1994 Consolidated Statements of Earnings for the years ended August 31, 1995, 1994 and 1993 Consolidated Statements of Common Shareholders' Equity for the years ended August 31, 1995, 1994 and 1993 Consolidated Statements of Cash Flows for the years ended August 31, 1995, 1994 and 1993 Notes to Consolidated Financial Statements FINANCIAL STATEMENT SCHEDULES
All schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the Consolidated Financial Statements or notes thereto.
REPORTS ON FORM 8-K
Items reported - Item 5. Other Events Financial Statements filed - None Dates of reports filed - August 22, 1995 and August 30, 1995
EXHIBITS
Filed with this Form 10-K:
10a Form of Executive Employment Agreement, as amended 10b System Purchase Option and Rate Agreement with the City of Las Cruces 12 Statements re computation of ratio of earnings 21 Subsidiaries of the registrant 23a Consent of DELOITTE & TOUCHE LLP 23b Consent of KPMG Peat Marwick LLP 24 Power of attorney 27 Financial Data Schedule
Incorporated in this Form 10-K by reference:
2 Agreement and Plan of Reorganization dated as of August 22, 1995, among Southwestern Public Service Company, M-P New Co. and Public Service Company of Colorado, filed as exhibit 2, Form 8-K dated August 22, 1995.
3(a) Restated Articles of Incorporation as amended through April 27, 1990, filed as exhibit 3, Form 10-Q for the quarter ended May 31, 1990.
(b) Restated Bylaws as amended through July 23, 1991, filed as exhibit 3, Form 10-K for the fiscal year ended August 31,1991.
4(a) First Mortgage Indenture dated August 1, 1946, filed as exhibit 7-A, Registration No. 2-6910.
(b) Supplemental Indentures to the First Mortgage Indenture:
Dated File Reference Exhibit February 1, 1967 2-25983 2-S October 1, 1970 2-38566 2-T February 9, 1977 2-58209 2-Y March 1, 1979 2-64022 b(28) April 1, 1983 (two) Form 10-Q, May 1983 4(a) February 1, 1985 Form 10-K, August 1985 4(c) July 15, 1992 (two) Form 10-K, August 1992 4(a) December 1, 1992 (two) Form 10-Q, February 1993 4 February 15, 1995 Form 10-Q, May 1995 4
(c) Standby Credit Agreement with Union Bank of Switzerland (Houston Agency) dated July 1, 1991, filed as exhibit 4(a), Form 10-K for the fiscal year ended August 31, 1991.
(d) Red River Authority for Texas Indenture of Trust dated July 1, 1991, filed as exhibit 4(b), Form 10-K for the fiscal year ended August 31, 1991.
(e) Rights Agreement between the Company and Society National Bank, dated July 23, 1991, filed as exhibit 2, Form 8-A dated July 23, 1991.
(f) Amendment No. 1 dated August 22, 1995, to the Rights Agreement between the Company and Society National Bank, filed as exhibit 4, Form 8-K dated August 30, 1995.
10(a) Coal Supply Agreement (Harrington Station) between Southwestern Public Service Company and TUCO, Inc., dated May 1, 1979, filed as exhibit 3, Form 8-K dated May 14, 1979.
(b) Master Coal Service Agreement between Swindell-Dressler Energy Supply Company and TUCO, Inc., dated July 1, 1978, filed as exhibit 5A, Form 8-K dated May 14, 1979.
(c) Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Company and TUCO, Inc., filed as exhibit 5B, Form 8-K dated May 14, 1979.
(d) Coal Supply Agreement (Tolk Station) between Southwestern Public Service Company and TUCO, Inc., dated April 30, 1979, as amended November 1, 1979 and December 30, 1981, filed as exhibit 10(b), Form 10-Q for the quarter ended February 28, 1982.
(e) Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO, Inc., dated December 30, 1981, filed as exhibit 10(c), Form 10-Q for the quarter ended February 28, 1982.
(f) 1989 Stock Incentive Plan for Executive Management, filed as Exhibit A to the Company's Proxy Statement dated December 1,1988.
(g) Directors' Plan for members of the Company's Board of Directors, filed as Exhibit B to the Company's Proxy Statement dated December 1, 1988.
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.
SOUTHWESTERN PUBLIC SERVICE COMPANY
By Bill D. Helton Chairman and Chief Executive Officer
DATE: November 20, 1995
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 on the date indicated:
Signature Title Date
Bill D. Helton Chairman and Chief November 20, 1995 Executive Officer (Principal Executive & Financial Officer & Director)
Doyle R. Bunch II Executive Vice President, Accounting & Corporate Development (Principal Accounting Officer)
C. Coney Burgess* Directors J. C. Chambers* Danny H. Conklin* Giles M. Forbess* Shirley Bird Perry* David M. Wilks*
By Doyle R. Bunch II* (Attorney-in-fact)