-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, IJWVkuwzFJzVCRd/C8Lq+S1Z2YfEm525EDH/7GL7giOKNuK4EblL8+xUxcfOT2dH Qhy/Ko0Sg3Ji02HlHSLRJA== 0000081018-95-000010.txt : 19950608 0000081018-95-000010.hdr.sgml : 19950608 ACCESSION NUMBER: 0000081018-95-000010 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19941231 FILED AS OF DATE: 19950302 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: PUBLIC SERVICE CO OF COLORADO CENTRAL INDEX KEY: 0000081018 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 840296600 STATE OF INCORPORATION: CO FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03280 FILM NUMBER: 95518098 BUSINESS ADDRESS: STREET 1: 1225 17TH ST STE 300 CITY: DENVER STATE: CO ZIP: 80202 BUSINESS PHONE: 3035717511 MAIL ADDRESS: STREET 1: P O BOX 840 STE 300 CITY: DENVER STATE: CO ZIP: 80201 10-K 1 1994 10-K Form 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 [ x ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1994 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________________ to________________ Commission file number 1-3280 Public Service Company of Colorado (Exact name of registrant as specified in its charter) Colorado 84-0296600 (State or other jurisdiction of (IRS Employer incorporation or organization) Identification No.) 1225 17th Street, Denver, Colorado 80202 (Address of principal executive offices) (Zip Code) Registrant's Telephone Number, including area code: (303) 571-7511 Securities Registered Pursuant to Section 12(b) of the Act: Name of Each Exchange Title of Each Class on Which Registered Common Stock, par value $5 per share New York, Chicago and Pacific Rights to Purchase Common Stock New York, Chicago and Pacific Cumulative Preferred Stock, par value $100 per share 4 1/4% Series American 7.15% Series New York Cumulative Preferred Stock ($25), par value $25 per share 8.40% Series New York Securities Registered Pursuant to Section 12(g) of the Act: Cumulative Preferred Stock, par value $100 per share (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] The aggregate market value of the registrant's Common Stock, $5.00 par value (the only class of voting stock), held by non-affiliates was $1,888,210,116, based on the last sale price thereof reported on the consolidated tape for February 24, 1995. At February 24, 1995, 62,679,174 shares of the registrant's Common Stock, $5.00 par value (the only class of common stock), were outstanding. Documents Incorporated By Reference Portions of the registrant's 1995 Proxy Statement are incorporated by reference in Part II, Item 9 and Part III, Items 10, 11, 12 and 13 of this Form 10-K. Table of Contents PART I Item l. Business . . . . . . . . . . . . . . . . . . . . . . . . . . 1 The Company . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Electric Operations . . . . . . . . . . . . . . . . . . . . . . . 1 Peak Load . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Purchased Power . . . . . . . . . . . . . . . . . . . . . . . . 2 Construction Program . . . . . . . . . . . . . . . . . . . . . 5 Fort St. Vrain . . . . . . . . . . . . . . . . . . . . . . . . 5 Electric Fuel Supply . . . . . . . . . . . . . . . . . . . . . . . 5 Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Natural Gas and Fuel Oil . . . . . . . . . . . . . . . . . . . 7 Natural Gas Operations . . . . . . . . . . . . . . . . . . . . . . 7 Gas Supply . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Young Storage . . . . . . . . . . . . . . . . . . . . . . . . . 8 WGI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 WGT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 WGG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Fuelco . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Regulation and Rates . . . . . . . . . . . . . . . . . . . . . . . 9 State Regulation . . . . . . . . . . . . . . . . . . . . . . . 9 CPUC . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Electric and Gas Adjustment Clauses . . . . . . . . . . . . 9 Incentive Regulation and Demand Side Management . . . . . . 10 1993 Rate Case . . . . . . . . . . . . . . . . . . . . . . . 10 IRP - Electric . . . . . . . . . . . . . . . . . . . . . . 11 IRP - Gas . . . . . . . . . . . . . . . . . . . . . . . . . 11 WPSC . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Environmental Matters . . . . . . . . . . . . . . . . . . . . . . 12 Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Industry Outlook . . . . . . . . . . . . . . . . . . . . . . . 13 State Regulatory Environment . . . . . . . . . . . . . . . . . 13 Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Franchises . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Research and Development . . . . . . . . . . . . . . . . . . . . . 15 Consolidated Electric Operating Statistics . . . . . . . . . . . . 16 Consolidated Gas Operating Statistics . . . . . . . . . . . . . . 17 Electric Transmission Map . . . . . . . . . . . . . . . . . . . . 18 Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . 19 Electric Property . . . . . . . . . . . . . . . . . . . . . . . . 19 Nuclear Property . . . . . . . . . . . . . . . . . . . . . . . . . 20 Transmission and Distribution Property . . . . . . . . . . . . . . 20 Gas Property . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Other Property . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Property of Subsidiaries . . . . . . . . . . . . . . . . . . . . . 21 Character of Ownership . . . . . . . . . . . . . . . . . . . 21 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . 21 Item 4. Submission of Matters to a Vote of Security Holders . . . . 21 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 i Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . 23 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . 24 Industry Outlook . . . . . . . . . . . . . . . . . . . . . . . . . 24 Corporate Overview . . . . . . . . . . . . . . . . . . . . . . . . 24 Earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Electric Operations . . . . . . . . . . . . . . . . . . . . . . . 25 Gas Operations . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Non-Fuel Operating Expenses . . . . . . . . . . . . . . . . . . . 27 Commitments and Contingencies . . . . . . . . . . . . . . . . . . 28 Liquidity and Capital Resources . . . . . . . . . . . . . . . . . 28 Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Prospective Capital Requirements and Sources . . . . . . . . . 29 Item 8. Financial Statements and Supplementary Data . . . . . . . . 32 Report of Independent Public Accountants . . . . . . . . . . . . . 32 Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . 33 Consolidated Statements of Income . . . . . . . . . . . . . . . . 35 Consolidated Statements of Shareholders' Equity . . . . . . . . . 36 Consolidated Statements of Cash Flows . . . . . . . . . . . . . . 37 Notes to Consolidated Financial Statements . . . . . . . . . . . . 38 Schedule II . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 Exhibit 12(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 Exhibit 12(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . 69 PART III Item 10. Directors and Executive Officers of the Registrant . . . . 69 Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . 71 Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 Item 13. Certain Relationships and Related Transactions . . . . . . 71 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 Experts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 Consent of Independent Public Accountants . . . . . . . . . . . . . . 74 Power of Attorney . . . . . . . . . . . . . . . . . . . . . . . . . . 74 Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 ii TERMS The abbreviations or acronyms used in the text and notes are defined below: Abbreviation or Acronym Term AFDC . . . . . . . . . . . . Allowance for Funds Used During Construction Amax . . . . . . . . . . . . . . . . . . . . . . . . . Amax Coal Company, a subsidiary of Cyprus/Amax Coal Company Arapahoe . . . . . . . . . . . Arapahoe Steam Electric Generating Station BCC . . . . . . . . . . . . . . . . . . . . . Bannock Center Corporation BLM . . . . . . . . . . . . . . . . . . . . . Bureau of Land Management Boulder District Court . District Court in and for the County of Boulder Cameo . . . . . . . . . . . . . Cameo Steam Electric Generating Station CCT3 . . . . . . . . . . . . . . . . . . . . . Clean Coal Technology III CERCLA Comprehensive Environmental Response, Compensation and Liability Act Cherokee . . . . . . . . . . Cherokee Steam Electric Generating Station Cheyenne . . . . . . . . . . . . . Cheyenne Light, Fuel and Power Company COLI . . . . . . . . . . . . . . . . . . . Corporate-owned life insurance Colorado Supreme Court . . . . . . Supreme Court of the State of Colorado Colorado-Ute . . . . . . . . . . Colorado-Ute Electric Association, Inc. Comanche . . . . . . . . . . . Comanche Steam Electric Generating Station Company . . . Public Service Company of Colorado (excluding subsidiaries) CPCN . . . . . . . . . . Certificate of Public Convenience and Necessity CPUC . . . . . . . . Public Utilities Commission of the State of Colorado Craig . . . . . . . . . . . . . . Craig Steam Electric Generating Station CWIP . . . . . . . . . . . . . . . . . . . Construction Work in Progress CWQCD . . . . . . . . . . . . . . Colorado Water Quality Control Division Denver District Court District Court in and for the City and County of Denver DOE . . . . . . . . . . . . . . . . . . . . . . U.S. Department of Energy DOJ . . . . . . . . . . . . . . . . . . . . . . U.S. Department of Justice DSM . . . . . . . . . . . . . . . . . . . . . . . . Demand Side Management DSMCA . . . . . . . . . . . . . . . Demand Side Management Cost Adjustment e prime . . . . . . . . . . . . . . . . . . . . . . . . . . e prime, inc. ECA . . . . . . . . . . . . . . . . . . . . . . . Electric Cost Adjustment EIS . . . . . . . . . . . . . . . . . . . . Environmental Impact Statement EPAct . . . . . . . . . . . . . . . . . National Energy Policy Act of 1992 EPA . . . . . . . . . . . . . . . . . U.S. Environmental Protection Agency EWG . . . . . . . . . . . . . . . . . . . . . . Exempt Wholesale Generator FERC . . . . . . . . . . . . . . . . Federal Energy Regulatory Commission FERC Order 636 . . . . . . . . . . . . . FERC Order Nos. 636-A and 636-B Fort St. Vrain . . . . Fort St. Vrain Nuclear Electric Generating Station Fuelco . . . . . . . . . . . . . . . . . . Fuel Resources Development Co. GCA . . . . . . . . . . . . . . . . . . . . . . . . Gas Cost Adjustment Hayden . . . . . . . . . . . . . Hayden Steam Electric Generating Station IBM . . . . . . . . . . . . . . . . . . . . . . . . . . IBM Corporation Interstate . . . . . . . . . . . . . . . Colorado Interstate Gas Company IPPF . . . . . . . . . . . . . . . Independent Power Production Facility IRP . . . . . . . . . . . . . . . . . . . . . . Integrated Resource Plan IRS . . . . . . . . . . . . . . . . . . . . . . . Internal Revenue Service ISFSI . . . . . . . . . . . . Independent Spent Fuel Storage Installation ISSC . . . . . . . . . . . . . . Integrated Systems Solutions Corporation KN Energy . . . . . . . . . . . . . . . . . . . . . . . . KN Energy, Inc. Natural Fuels . . . . . . . . . . . . . . . . Natural Fuels Corporation NOx . . . . . . . . . . . . . . . . . . . . . . . . . . . . Nitrogen Oxide NPDES . . . . . . . . . National Pollution Discharge Elimination System NRC . . . . . . . . . . . . . . . . . . . Nuclear Regulatory Commission OCC . . . . . . . . . . . . . . . . Colorado Office of Consumer Counsel OPEB . . . . . . . . . . . . . . . Other Postretirement Employee Benefits PCB . . . . . . . . . . . . . . . . . . . . . . . Polychlorinated biphenyl iii Pawnee . . . . . . . . . . . . . Pawnee Steam Electric Generating Station Pawnee 2 . . Pawnee Steam Electric Generating Station, Unit 2 (proposed) Pool . . . . . . . . . . . . . . . . . . . . . . . . . Inland Power Pool PRPs . . . . . . . . . . . . . . . . . . Potentially Responsible Parties PSCCC . . . . . . . . . . . . . . . . . . . PS Colorado Credit Corporation PSCO Gas Companies . Gas Operations of Public Service Company of Colorado (excluding subsidiaries) and Cheyenne Light, Fuel and Power Company PSRI . . . . . . . . . . . . . . . . . . . . . . . PSR Investments, Inc. PUHCA . . . . . . . . . . . . Public Utility Holding Company Act of 1935 QF . . . . . . . . . . . . . . . . . . . . . . . . . Qualifying Facility QFCCA . . . . . . . . . . . Qualifying Facilities Capacity Cost Adjustment SEC . . . . . . . . . . . . . . . . . . Securities and Exchange Commission SFAS 71 . . . . . . . Statement of Financial Accounting Standards No. 71 - "Accounting for the Effects of Certain Types of Regulation" SFAS 106 . . . . . Statement of Financial Accounting Standards No. 106 - "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 107 . . . . . Statement of Financial Accounting Standards No. 107 - "Disclosures about Fair Value of Financial Instruments" SFAS 109 . . . . . Statement of Financial Accounting Standards No. 109 - "Accounting for Income Taxes" SFAS 112 . . . . . Statement of Financial Accounting Standards No. 112 - "Employers' Accounting for Postemployment Benefits" SO2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sulfur Dioxide Synhytech . . . . . . . . . . . . . . . . . . . . . . . . Synhytech, Inc. Tri-State . . . . Tri-State Generation and Transmission Association, Inc. Valmont . . . . . . . . . . . Valmont Steam Electric Generating Station WGG . . . . . . . . . . . . . . . . . . . . . . WestGas Gathering, Inc. WGI . . . . . . . . . . . . . . . . . . . . . . WestGas InterState, Inc. WGT . . . . . . . . . . . . . . . . . . . . WestGas TransColorado, Inc. WPSC . . . . . . . . . . . . . . . . Public Service Commission of Wyoming WSCC . . . . . . . . . . . . . . . . Western Systems Coordinating Council Young Storage . . . . . . . . . . . . . . Young Gas Storage Company, Ltd. Zuni . . . . . . . . . . . . . . . Zuni Steam Electric Generating Station iv PART I Item l. Business The Company The Company, incorporated through merger of predecessors under the laws of the State of Colorado in 1924, is an operating public utility engaged, together with its subsidiaries, principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transmission, distribution, sale and transportation of natural gas. The Company provides electricity or gas or both in an area having an estimated population of 2.8 million people of which approximately 2.1 million are in the Denver metropolitan area. The Company's operations are wholly within the State of Colorado. As of December 31, 1994, the Company owned all of the outstanding capital stock of Cheyenne, WGI, WGT, Fuelco, 1480 Welton, Inc., PSRI, PSCCC and Green and Clear Lakes Company. In addition, the Company owned 80% of the capital stock of Natural Fuels. These subsidiaries and the results of operations and cash flows of WGG, which was sold in August 1994, are included in the Company's consolidated financial statements. Cheyenne is an electric and gas utility operating principally in Cheyenne, Wyoming; WGI is a natural gas transmission company operating in Colorado and Wyoming; WGT holds a one-third interest in a natural gas transmission company which will operate in Colorado; Fuelco has been engaged in the exploration for, and the development and production of, natural gas and oil principally in Colorado; 1480 Welton, Inc. is a real estate company which owns certain of the Company's real estate interests; PSRI owns and manages permanent life insurance policies on certain past and present employees, the benefits from which are to provide future funding for general corporate purposes; PSCCC is a finance company that finances certain of the Company's current assets; Green and Clear Lakes Company owns water rights and storage facilities for water used at the Company's Georgetown Hydroelectric Station; and Natural Fuels sells compressed natural gas as a transportation fuel to retail markets, converts vehicles for natural gas usage, constructs fueling facilities and sells miscellaneous fueling facility equipment. The Company also holds a controlling interest in several other relatively small ditch and water companies whose capital requirements are not significant and which are not consolidated in the Company's financial statements or statistical data. On January 30, 1995, the Company's wholly-owned subsidiary, e prime, was incorporated. e prime will offer energy related products and services to energy-using customers and to selected segments of the utility industry. Information regarding industry segments is set forth in Note 13. Segments of Business in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Electric Operations In the Company's IRP, which was approved by the CPUC in 1994 (see 1 "Regulation and Rates-State Regulation-IRP-Electric"), and its IRP Annual Progress Report filed with the CPUC in October 1994, the Company proposes to use the following resources to meet its net dependable system capacity: 1) the Company's electric generating stations (see Electric Property in Item 2. PROPERTIES); 2) purchases from other utilities and from QFs and IPPFs; 3) demand-side options; and 4) new generation alternatives, including repowering Fort St. Vrain. Peak Load During 1995, net firm system peak demand for the Company and Cheyenne is estimated to be 4,112 Mw, assuming normal weather conditions. Net dependable system capacity is projected to be, after accounting for 53 Mw of demand-side options, 4,912 Mw (generating capacity of 3,186 Mw and firm purchases of 1,726 Mw) at the time of the anticipated 1995 system peak (summer season), resulting in a reserve margin of approximately 19%. The net firm system peak demand for the Company and Cheyenne for each of the last five years was as follows: 1990 1991 1992 1993 1994 Net Firm System Peak Demand* (Mw) 3,606 3,568 3,757 3,869 3,972 ______________ * Excludes station housepower, nonfirm electric furnace load and controlled interruptible loads (of which approximately 145 Mw, 162 Mw, 156 Mw, 164 Mw and 160 Mw in the years 1990-1994, respectively, was not interrupted at the time of the system peak). The net firm system peak demand for the Company and Cheyenne for the years 1991, 1992, 1993 and 1994 occurred in the summer. The net firm system peak demand for 1990 occurred in the winter. The net firm system peak demand for 1994, which occurred on August 26, 1994, was 3,972 Mw. At that time, the net dependable system capacity totaled 4,980 Mw (generating capacity of 3,186 Mw, together with firm purchases of 1,794 Mw), which represented a reserve margin of approximately 25%. Net dependable system capacity is the maximum net capacity available from both Company-owned generating units and purchase power contracts to meet the net firm system peak demand. Purchased Power The Company purchases capacity and energy from various regional utilities as well as QFs and an IPPF in order to meet the energy needs of its customers. Capacity, typically measured in Kws or Mws, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in Kwhs or Mwhs, is a measure of the amount of electricity produced from a particular generating source over a period of time. Purchase power contracts typically provide for a charge for the capacity from a particular generating source, together with a charge for the associated energy actually purchased from such generating source. The Company and Cheyenne have contracted with the following sources for the firm purchase of capacity and energy at the time of the anticipated summer 1995 net firm system peak demand through the expiration of the contracts: 2
Mw Contracted For at the Time of the Generating Summer 1995 Net Firm Contract Company Source System Peak Demand Expiration Basin Electric Power Cooperative, Laramie River Station Agreements 1 and 2 (a) (b) Units 2 and 3 175 2016 PacifiCorp (c) PacifiCorp System 133 1997 PacifiCorp PacifiCorp Resource 176 2022 Pool Platte River Power Authority (a) (d) Craig Units 1 and 2; 224 2004 Rawhide Unit 1 Tri-State 425 (e) Agreements 1, 2, 3 and 4 (a) (e) Laramie River Station Units 2 and 3; Craig Units 1, 2 and 3 Agreement 5 (a) (e) Laramie River Station Units 2 and 3; Craig Units 1, 2 and 3; Nucla Units 1, 2, 3 and 4 Various Owners (a) QFs & IPPF 593 Various dates 1,726 ____________ (a) These contracts are contingent upon the availability of the units listed as the generating source. These contracts are take and pay contracts. Based upon the terms of these agreements, if the capacity is available from these units, the Company is obligated to pay for capacity whether or not it takes any energy. However, the Company has historically met the minimum energy requirements associated with these agreements and anticipates doing so in the future. Additionally, if these units are unavailable, the supplying company has no obligation to furnish capacity or energy and the capacity charge to the Company is reduced accordingly. (b) The Company has entered into two agreements with Basin Electric Power Cooperative. The first agreement is for 100 Mw of capacity through March 31, 2016. The second agreement is for 75 Mw summer season capacity through March 31, 2016 and 25 Mw winter season capacity through March 31, 2010. (c) This contract calls for PacifiCorp to sell to Cheyenne the total electric capacity and energy requirements associated with the operation of Cheyenne's service area. (d) The amount of capacity to be made available for each summer and winter season is agreed upon prior to such season to the extent that Platte River Power Authority has excess capacity for such season. (e) The Company has entered into five agreements with Tri-State. Agreements 1, 2, 4 and 5 are contracts for 100 Mw each of capacity 3 and expire in 2001, 2017, 2018 and 2011, respectively. Agreement 3 is a contract for 25 Mw of summer season capacity and 75 Mw of winter season capacity and expires in 2016. The capacity associated with Agreement 4 escalates to the following amounts in the future: 1996 - 150 Mw, 1997 through 2000 - 200 Mw and 2001 through 2018 - 250 Mw; however, either party may elect to reduce the Agreement 4 capacity by up to 50 Mw each year, except for 2001, effective in the year 1999. If the full 50 Mw reduction is taken each year, the capacity associated with Agreement 4 would be as follows from 1999: 1999 - 150 Mw, 2000 -100 Mw, 2001 - 100 Mw, 2002 - 50 Mw and 2003 through 2018 - 0 Mw.
See Note 8. Commitments and Contingencies-Purchase Requirements in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for information regarding the Company's financial commitments under these contracts. See Transmission and Distribution Property in Item 2. PROPERTIES for a discussion of the Company's interconnections with these sources. Based on present estimates, the Company and Cheyenne will purchase approximately 34% of the total electric system energy input for 1995, compared to approximately 37% in 1994. In addition, based on the capacity associated with the purchase power contracts described above, approximately 35% of the total net dependable system capacity for the summer 1995 net firm system peak demand for the Company and Cheyenne will be provided by purchased power, compared to approximately 36% in 1994. This decrease is due to the expiration of a short-term purchase contract with Public Service Company of New Mexico for 75 Mw. This capacity is no longer required due to the additional 340 Mw of capacity provided by new QFs in 1994. In accordance with the Public Utility Regulatory Policies Act of 1978 ("PURPA"), the Company is obligated to purchase at "avoided cost" capacity and energy from QFs. The Company has had tariffs in effect since 1984 for these purchases. In December 1987, the CPUC issued an order imposing a moratorium during which the Company was no longer required to continue to execute additional QF contracts due to the fact that excess generating capacity would be created if additional contracts were executed. Although a comprehensive QF bidding procedure was adopted in 1988 which allowed the Company to purchase the most competitively priced QF power, all of the QF capacity purchased by the Company, including approximately 37 Mw of additional capacity scheduled to come on line in the future, is being purchased under contracts entered into prior to the adoption of such procedure. Based on current CPUC criteria, QFs could provide up to 20% of the Company's net firm system peak load. In 1994, approximately 15% of the Company's summer net firm system peak demand was contracted to be provided by QFs. In addition to long-term and QF purchases, the Company also made short- term and non-firm purchases throughout the year to replace generation from Company owned units which were unavailable due to maintenance and unplanned outages, to provide the Company's reserve obligation to the Pool, to obtain energy at a lower cost than that which could be produced by higher-cost resource options, including Company owned generation and/or long-term purchase power contracts, and for various other operating requirements. Short-term and non-firm purchases accounted for approximately 3% of the Company's total energy requirement in 1994. Based on current projections, the Company expects that purchased capacity will continue to meet a significant portion of system requirements at least for the remainder of the 1990s. 4 Purchases of capacity and energy do not have a significant effect on the earnings of the Company because the costs thereof, without mark-up, are billed to customers through base rates, the ECA and the QFCCA. The CPUC, however, has established a schedule for reviewing the ECA (see Note 8. Commitments and Contingencies-Regulatory Matters in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). Such purchases neither require the Company to make an investment nor afford the Company an opportunity to earn a return. The Company is a member of the Pool which is composed of members each of which owns and/or operates electric generation and/or transmission systems which are interconnected to one or more other member systems. The objective of the Pool is to provide capacity which is categorized as 1) immediately accessible; 2) accessible within ten minutes; and 3) accessible within twelve hours, as required. As a result of membership in the Pool, the Company can supply and protect its electric system with less aggregate operating reserve capacity than otherwise would be necessary; emergency conditions can be met with less likelihood of curtailment or impairment of electric service; and generation and transmission facilities and interconnections can be used more efficiently and economically. Construction Program At December 31, 1994, the Company and its subsidiaries estimated the cost of their construction program, including AFDC, in 1995, 1996 and 1997 to be $323 million, $347 million and $316 million, respectively (see Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS). Included in these estimated costs is $117 million associated with the conversion of Fort St. Vrain to a 471 Mw gas fired combined cycle steam plant. The total conversion project cost is approximately $231 million. A CPCN for the conversion of Fort St. Vrain was approved by the CPUC in July 1994 (see Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). Fort St. Vrain See Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. 5 Electric Fuel Supply The following table presents the delivered cost per million Btu of each category of fuel consumed by the system for electric generation of the Company and its utility subsidiaries during the years indicated, the percentage of total fuel requirements represented by each category of fuel and the weighted average cost of all fuels during such years:
Weighted Average Coal* Gas All Fuels** ---------------------------------------------------------- Cost $ % Cost $ % Cost $ 1994 . . . . . . . . . . . 1.038 99 2.069 1 1.053 1993 . . . . . . . . . . . 1.078 98 2.319 2 1.097 1992 . . . . . . . . . . . 1.091 99 2.065 1 1.105 1991 . . . . . . . . . . . 1.176 98 1.991 2 1.198 1990 . . . . . . . . . . . 1.145 98 2.101 2 1.165 * The average cost per ton of coal, including freight, for years 1994 through 1990 shown above was $20.57, $21.03, $21.14, $22.40 and $21.44, respectively. ** Insignificant purchases of oil are included.
Coal The Company's primary fuel for its steam electric generating stations is low-sulfur western coal. The Company's coal requirements are purchased primarily under seven long-term contracts with suppliers operating in Colorado and Wyoming, the largest of which is with Cyprus/Amax Coal Company, which operates the Belle Ayr and Eagle Butte Mines near Gillette, Wyoming and the Foidel Creek and Empire Energy mines in northwestern Colorado. Long-term contracts presently in existence provide for a substantial portion of future annual coal requirements for existing plants through 1997. Any shortfall will be provided by purchases on the spot market. During the year ended December 31, 1994, the Company's coal requirements for existing plants were approximately 8,502,170 tons, a substantial portion of which was supplied pursuant to long-term supply contracts. Coal supply inventories at December 31, 1994 were approximately 52 days usage, based on the average peak burn rate for all the Company's coal-fired plants. 6 The following table is a synopsis of the basic supply provisions of the existing long-term contracts, which provide a minimum delivery of approximately 92 million tons of low-sulfur coal over their remaining life (see Note 8. Commitments and Contingencies-Purchase requirements in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ).
Minimum Maximum Contract delivery delivery maximum per contract year per contract year sulfur Coal Supplier and Delivery Year in tons in tons content _______________________________ ________________ ________________ ________ Amax (1) 1988 through Pawnee 2 completion . . . . . . . 3,960,000 (2) 0.50% Pawnee 2 completion through 2013 . . . . . . . 3,600,000 (3) 0.50% Colowyo Coal Company 1992 through 2017 . . . . . . . . . . . . . . . 79,429 (4) 79,429 0.70% Cyprus Coal Company 1988 through 1997 . . . . . . . . . . . . . . . 1,700,000 1,900,000 0.60% Mountain Coal Company 1993 through 2000 . . . . . . . . . . . . . . . 600,000 (5) 800,000 0.67% Powderhorn Coal Company 1992 through 1996 . . . . . . . . . . . . . . . 175,500 214,500 0.69% Seneca Coals, Ltd (6) 1992 through 2004 . . . . . . . . . . . . . . . 439,800 (7) 1.00% Trapper Mining, Inc 1992 through 2014 . . . . . . . . . . . . . . . 189,108 (8) 189,108 (9) ___________________ (1) The contract term is completed upon delivery of 144,843,970 tons regardless of the year in which delivery is completed. From January 1, 1976 through December 31, 1994, 70,661,607 tons have been delivered. (2) Coal requirements of Comanche and Pawnee. (3) Coal requirements of Pawnee and Pawnee 2. (4) The contract minimum quantity varies by year during the agreement from 79,429 tons in 1994 to 124,810 tons in 2017. (5) The contract term is completed on December 31, 2000 or upon delivery of 3,200,000 tons. As of December 31, 1994, 971,426 tons have been delivered. (6) The contract term is completed upon total delivery of 31,250,000 tons to Hayden from and after January 1, 1983. As of December 31, 1994, 17,311,889 tons have been delivered. Delivery is expected to be completed in the year 2004. (7) Coal requirements of Hayden. (8) The contract minimum quantity varies by year during the agreement from 189,108 tons in 1994 to 140,621 tons in 2014. (9) Not specified in the contract.
Each coal contract contains adjustment clauses which permit periodic price increases or decreases. See Note 8. Commitments and Contingencies-Purchase requirements in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for information regarding the Company's financial commitments under these contracts as well as coal transportation contracts. Natural Gas and Fuel Oil 7 The Company uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas used in steam heat production facilities and as boiler fuel in the Company's Denver area generating stations and Comanche is purchased primarily from North American Resources Co. pursuant to a Gas Sales Agreement that went into effect for a 12-month period beginning October 1, 1994. The agreement with North American Resources Co. provides for firm supplies ranging from 10,000 MMbtu per day (during the seven month summer season) to 20,000 MMbtu per day (during the five month heating season), with varying daily purchase obligations by the Company. Requirements above these levels are secured by purchasing competitively priced gas from other suppliers on an as-needed basis. Natural gas supplies for the Valmont and Ft. Lupton power plants are purchased from various suppliers on an as-needed basis. Natural Gas Operations During the period 1990-1994, the PSCo Gas Companies experienced growth in the number of commercial and residential customers ranging from 1.3% to 2.8% annually. Since 1990, commercial and residential gas volumes sold have averaged 150.6 Bcf annually, while industrial volumes sold have declined from 3.6 Bcf in 1990 to 0.1 Bcf in 1994. The growth of commercial and residential sales has been moderate due primarily to economic conditions in Colorado and Wyoming. Industrial sales have declined primarily because a majority of industrial customers have switched to purchasing gas directly from suppliers. In most cases, the PSCo Gas Companies transport gas from the suppliers to such industrial customers through the PSCo Gas Companies' transmission and distribution facilities. Fees for this transportation service, which are paid by these industrial customers, substantially offset the effect on net income of the revenue loss from decreased sales of gas to these industrial customers. During 1994, transportation services of the PSCo Gas Companies generated revenues of $23.5 million compared to $23.2 million in 1993 and $20.6 million in 1992. Gas Supply The PSCo Gas Companies have attempted to maintain low cost, reliable gas supplies by optimizing the balance between long- and short-term gas purchase contracts. During 1994, the PSCo Gas Companies purchased 132.6 Bcf (at 14.65 pounds per square inch) from 87 suppliers, including the following major suppliers: Interstate (44.7 Bcf); Associated Natural Gas, Inc. (8.9 Bcf); KN Energy and affiliates (7.2 Bcf); and Western Gas Resources, Inc. (5.2 Bcf). In 1994, the average delivered cost per Mcf for the PSCo Gas Companies was $2.86 compared to $2.82 per Mcf in 1993 and $2.72 per Mcf in 1992. As indicated above, Interstate was the primary supplier to the PSCo Gas Companies in 1994. During 1993, the PSCo Gas Companies entered into two non- regulated supply agreements, as allowed under FERC Order 636. Under the agreement with Interstate, which covers the period from October 1, 1993 through September 30, 1996, the annual quantities to be purchased declined from 44 Bcf in the first year to 33 Bcf in the second year and will decline to 22 Bcf in the third year. Under the agreement with KN Gas Supply Services, Inc., which covers the period from September 1, 1993 through August 31, 1996, the annual quantities to be purchased are fixed at 4 Bcf. This continued purchase of gas quantities from Interstate and KN Gas Supply Services, Inc. will eliminate any Gas Supply Realignment costs otherwise applicable under FERC Order 636. See Note 8. Commitments and Contingencies-Purchase requirements in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for information regarding the Company's financial commitments under these contracts. 8 Young Storage Young Storage, a partnership among Young Gas Storage Company and CIG Gas Storage Company, each 47.5% general partners, and The City of Colorado Springs Department of Public Utilities ("Colorado Springs"), a limited partner, is converting a depleted natural gas field into an underground natural gas storage facility at a cost of approximately $45 million. The facility, when fully developed by 1998, will have a maximum working gas capacity of 5.3 Bcf and a maximum daily deliverability of 200,000 Mcf. Commercial operations are expected to begin by mid-1995. On September 13, 1993, the Company signed a thirty year contract with Young Storage for natural gas storage services with a maximum available capacity of 4.77 Bcf and a maximum daily injection/withdrawal capacity of 180,000 Mcf per day. The remainder of the storage capacity has been contracted by Colorado Springs. Young Storage will be subject to FERC regulation. In December 1994, the Board of Directors of the Company approved exercising the option to acquire Young Gas Storage Company's 47.5% general partnership interest in Young Storage pursuant to the Company's Option For Purchase and Sale of the Young Gas Storage Company dated August 31, 1993. The Company expects to exercise this option during the first quarter of 1995 resulting in an investment of approximately $6.5 million. WGI WGI is engaged in transporting gas to Cheyenne, Wyoming via a thirteen mile connecting pipeline between Chalk Bluffs, Colorado and Cheyenne, Wyoming. Gas transportation volumes were approximately 1.7 Bcf for 1994. WGT WGT holds a one-third interest ($3.4 million) in the TransColorado Project. The TransColorado Project is a partnership of WGT and subsidiaries of KN Energy and Questar Pipeline Company for developing a pipeline to transport natural gas out of western Colorado and the Rocky Mountain Region into major western and midwestern markets. The TransColorado Project has been designed and engineered for a 300 mile pipeline capable of transporting 300 MMcf per day. The partnership is currently marketing the transportation service to producers in western Colorado and to marketers and local distribution companies in an effort to gain firm contracts to support the project. FERC approval was received in October 1994. Construction of the pipeline is scheduled to begin during 1996, depending upon the success of the marketing efforts. The Company is currently evaluating the possible divestiture of its interest in WGT. WGG WGG owned and operated natural gas gathering and processing facilities in Southern Colorado. On August 30, 1994, the Company sold all of its outstanding common stock of WGG (see Note 3. Divestiture of Nonutility Assets in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). Fuelco Fuelco has been engaged principally in the exploration for, and the development and production of, natural gas and crude oil. Fuelco also marketed and brokered natural gas to re-marketers and directly to end users. As part of the Company's strategy to focus its efforts on its core electric and gas businesses, during 1994 and 1993, the Company disposed of certain assets related to the Company's investment in Fuelco and its wholly-owned subsidiary, Synhytech. The Company is re-evaluating its alternatives related 9 to the disposition of the remaining assets (see Note 3. Divestiture of Nonutility Assets in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). Regulation and Rates The Company is subject to the jurisdiction of the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. Cheyenne is subject to the jurisdiction of the WPSC. The Company is subject to the jurisdiction of the DOE through the FERC with respect to its wholesale electric operations and accounting practices and policies. The Company is also subject to the jurisdiction of the NRC with respect to the decommissioning of Fort St. Vrain. Although the Company is a "holding company" under the PUHCA, it has filed an annual exemption statement pursuant to Rule 2 of the SEC under that Act and is, therefore, exempt from all of the provisions of such Act and the Rules thereunder, except Section 9(a)(2) thereof. Such exemption is subject to termination under Rule 6 of PUHCA. The Company holds a FERC certificate which allows it to transport natural gas in interstate commerce pursuant to the provisions of the Natural Gas Act, the Natural Gas Policy Act of 1978 and FERC Order Nos. 436 and 500 without the Company becoming subject to full FERC jurisdiction. WGI holds a FERC certificate which allows it to transport natural gas in interstate commerce pursuant to the provisions of the Natural Gas Act. WGI is subject to FERC jurisdiction. State Regulation CPUC The CPUC consists of three full-time members appointed by the Governor and approved by the Colorado Senate. Only two members may be from the same political party. Electric and Gas Adjustment Clauses The Company's ECA mechanism was revised and a new QFCCA mechanism was implemented on December 1, 1993, along with the base rate changes resulting from the 1993 rate case (see "1993 Rate Case"). Under the revised ECA, fuel used for generation and purchased energy costs from utilities, QFs and IPPFs (excluding all purchased capacity costs) to serve retail customers, are recoverable. Purchased capacity costs are recovered as a component of base rates, except as described below. The ECA rate is revised annually on October 1 and whenever total costs recoverable through the ECA change by $0.001 per kilowatt hour or more. Recovered energy costs are compared with actual costs on a monthly basis and differences, including interest, are deferred. The balance in the deferred account on June 30 of each year (including interest if the balance is negative) is reflected in the ECA over a 12 month period commencing October 1 of such year. Under the QFCCA, all purchased capacity costs from new QF projects, not otherwise reflected in base rates, are recoverable similar to the ECA. While the CPUC approved the QFCCA, recovery of such costs may be subject to an earnings test, which has not yet been defined by the CPUC. The OCC has proposed an annual earnings test that may result in a reduction of QFCCA recoveries to the extent the Company's earnings are in excess of its 11% authorized rate of return on regulated common equity granted in the 1993 rate case. Hearings regarding this matter are scheduled for April 1995. The Company, through its GCA, is allowed to recover the difference between its actual costs of purchased gas and the amount of these costs recovered under its base rates. The GCA rate is revised annually on October 1 and as needed, to coincide with supplier rate changes. Purchased gas costs and revenues received to recover such gas costs are compared on a monthly 10 basis and differences, including interest, are deferred. The balance in the deferred account on June 30 of each year (including interest if the balance is negative) is reflected in the GCA over a 12 month period commencing October 1 of such year. The Company and Cheyenne are required to file applications with their respective state regulatory commissions for approval of adjustment mechanisms in advance of the proposed effective date. The applications must be acted upon before becoming effective. In addition, the CPUC holds hearings to review the Company's adjustments made during preceding time periods, and the Company is required to file quarterly reports on matters relevant to the adjustments. The CPUC held a prehearing conference on May 24, 1994 for the purpose of establishing a schedule for reviewing the justness and reasonableness of GCA and ECA mechanisms used by gas and electric utilities within its jurisdiction resulting in the opening of an investigatory docket. Open hearings were held in December 1994. The OCC and the CPUC staff are recommending the elimination of these cost adjustment mechanisms. The Company is in opposition to the elimination of these cost adjustment mechanisms and has filed initial comments, as well as responded to the comments filed by the other parties. On February 6-7, 1995, as part of an open hearing, the CPUC determined that proceeding with a generic ECA rulemaking docket was not appropriate. However, the Company is required to make an individual filing with the CPUC related to its ECA by September 1, 1995 to assess whether the ECA should be maintained in its present form, altered or eliminated. Additionally, the CPUC preliminarily determined that the GCA will continue under current practices. The CPUC staff will hold informal roundtable discussions for the purpose of clarifying the review procedures for the GCA. Incentive Regulation and Demand Side Management The Company, in collaborative process with public interest groups, consumers and industry, has developed DSM programs (programs designed to reduce peak electricity demand, shift on-peak demand to off-peak hours and provide for more efficient operation of the electric generation system), including incentive and cost recovery mechanisms. On May 5, 1993, the CPUC approved the programs along with a schedule to be implemented over a three- year period. Effective July 1, 1993, the Company placed into effect a DSMCA clause which permits it to recover deferred DSM costs over seven years while non-labor incremental expenses, carrying costs associated with deferred DSM costs and certain incentives associated with the approved DSM programs are recovered on an annual basis. Under a separate CPUC order issued in December 1992, the Company has implemented a Low-Income Energy Assistance Program. The costs of this energy conservation and weatherization program for low-income customers are recoverable through the DSMCA. In addition, on June 8, 1994, the CPUC approved the recovery of certain "energy efficiency credits" from retail jurisdiction customers through the DSMCA (see Note 8. Commitments and Contingencies - Regulatory Matters in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). The CPUC has opened a separate docket to investigate issues relating to the adoption and implementation of incentive regulation, which includes the concept of decoupling the Company's earnings from sales, and additional DSM incentives. On February 10, 1994, the parties to this docket filed a unanimous stipulation and settlement agreement with the CPUC. Provisions of the stipulation include, among other things, retaining the cost recovery component of the DSMCA through December 31, 1998, modifying slightly the DSM 11 incentive mechanism for 1994 and 1995 and forming a technical working group to study and analyze various alternative annual revenue reconciliation mechanisms and incentive mechanisms for 1996 through 1998, which would replace existing DSM incentives until another mechanism or regulatory approach is approved by the CPUC. The stipulation agreement, which includes a procedural schedule to review the results of all studies and simulations over the next year, was approved by the CPUC on June 16, 1994. The technical working group will present to the CPUC a detailed analysis demonstrating the effect of the various proposed mechanisms by the end of the first quarter of 1995. 1993 Rate Case On November 26, 1993, the CPUC issued its final written decision regarding the Company's 1993 rate case, authorizing the Company to earn a return on regulated common equity of 11% and an annual rate of return on regulated rate base of 9.4%, lowering the Company's annual base rate revenue requirement by approximately $5.2 million (a $13.1 million electric revenue decrease partially offset by a $7.1 million gas revenue increase and a $0.8 million steam revenue increase). The new rates became effective December 1, 1993. As part of the final decision, the CPUC adopted the following significant positions: . the rejection of the Company's proposed use of a fully forecasted test year in the establishment of revenue requirements in favor of an historical test year ended September 30, 1992, . the adoption of full income tax normalization with a 13-year amortization of prior flow-through amounts currently reflected as a regulatory asset on the balance sheet, and . continued inclusion in rate base of the Pawnee 2 engineering costs ($18 million) and the investment in Southeast Water Rights ($28 million), but with an allowed rate of return on such assets based on the Company's weighted cost of debt and preferred stock. The OCC filed in Denver District Court an appeal of the CPUC's decision. The OCC has claimed that accounting related to a specific income tax issue results in the overcollection of costs from ratepayers. The Company is in opposition to the appeal. The Company believes that the resolution of this appeal will not have a material effect on its financial position or results of operations. On August 1, 1994, the Company filed its Phase II testimony. The Phase II proceedings will address cost allocation issues and specific rate changes for the various customer classes based on the results of the Phase I hearings and decision that became effective December 1, 1993. A final CPUC decision on the Phase II proceedings is expected in late 1995. IRP - Electric On October 1, 1993, the Company filed its first IRP pursuant to the Electric Integrated Resource Planning Rules of the CPUC. The Company's IRP describes the mix of resources to be utilized and/or acquired by the Company for the following three years, including the repowering of Fort St. Vrain as a gas fired combined cycle steam plant (see Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). In addition, certain DSM measures have been identified and described which are intended to reduce the amount of additional capacity required to be supplied by the Company in the future. Hearings regarding the Company's and other electric utilities' specific IRPs were held before the CPUC in April 1994 and an interim order 12 approving the Company's IRP was issued on June 10, 1994. The final order has not yet been received; however, no changes are expected to result from the final order. The Company's next IRP is scheduled to be filed with the CPUC on or about July 1, 1996. IRP - Gas In December 1992, the CPUC established a separate docket to consider the need for a gas IRP. The CPUC has held several pre-hearing conferences and has determined to conduct roundtable discussions to explore the impacts of the EPAct and the mandates in the EPAct regarding the consideration by state regulatory agencies of the adoption of standards for gas integrated resource planning and conservation incentives, as well as the impact on small businesses of adopting these standards. These proceedings have been completed and the CPUC determined there was no need to establish a gas IRP in Colorado. WPSC On July 31, 1992, Cheyenne filed a rate case application with the WPSC. On December 17, 1992, the WPSC issued an order approving a Settlement Agreement reached between Cheyenne and the Consumer Representative Staff of the WPSC. The Settlement Agreement provided for a return on equity of 11.66% which, in addition to new rates, became effective January 1, 1993. In June 1993, Cheyenne filed gas and electric IRPs with the WPSC pursuant to the Settlement Agreement. The WPSC has not formally acted on these filings. The WPSC has approved adjustment mechanisms for Cheyenne which are similar to the Company's ECA and GCA. Environmental Matters See Note 8. Commitments and Contingencies - Environmental Issues in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for a discussion of the impact on the Company of environmental site clean-up, the Clean Air Act Amendments of 1990 and other environmental matters not discussed below. For the years 1995, 1996 and 1997, the estimated expenditures for environmental control facilities are $11.3 million, $18.2 million and $26.9 million, respectively. These figures include estimated expenditures to install SO2 and NOx reduction equipment for the years 1995, 1996 and 1997 of $4.7 million, $14.1 million and $20.3 million, respectively. The Metro Denver Brown Cloud II Study, designed to investigate the formation of secondary particulates in the Denver metropolitan area, began in July 1990 and the results were released in December 1993. The study was inconclusive and did not offer any policy recommendations. As a result, the study will not impact the Company's current programs to reduce SO2 and NOx emissions. However, the Metro area brown cloud continues to be of concern, which may require the Company to participate in a Metro Area Brown Cloud III Study. The Company continues to research and implement various SO2 and NOx emissions reduction projects, including two CCT3 projects. The CCT3 projects are part of a larger DOE Clean Coal Program, which co-funds developing technologies aimed at more efficient and environmentally acceptable methods of burning coal. Research and implementation continues on the two CCT3 projects, which involve Arapahoe Unit 4 and Cherokee Unit 3. Testing is expected to be completed at both units in late 1995. 13 The Mount Zirkel Wilderness Area Reasonable Attribution Study, which is designed to ascertain the contribution of various emission sources to visibility impairment in the Mount Zirkel Wilderness Area began in 1994. The Company is a participant in the Hayden and Craig generating stations, in the nearby Yampa Valley. Depending upon the outcome of the study, the participants may need to install emissions control equipment. However, the type and extent of equipment necessary will not be determined until after the conclusion of the study. Installation of a fabric filter dust collector at Pawnee, which was accelerated as a result of a Consent Decree between the Company, the DOJ, the EPA and the State of Colorado, was completed in December 1994. The cost of installing this equipment was approximately $41.6 million. Pursuant to the requirements of the Federal Clean Water Act, as amended, and the Colorado Water Quality Control Act and regulations issued thereunder, the Company receives NPDES permits to discharge effluents into various streams and waters of the State of Colorado for each of its generating stations. These permits, which have a five-year life, are issued by the CWQCD, but are subject to review by the EPA. The Company believes it is presently in compliance with such discharge permits. Renewed wastewater discharge permits have been issued for: 1) Fort St. Vrain, effective April 1, 1993; 2) Cherokee, effective July 1, 1994; 3) Zuni, effective August 1, 1993; 4) Hayden, effective August 1, 1994; 5) Valmont, effective October 1, 1994; 6) Arapahoe, effective December 1, 1994 and 7) Cameo, effective December 1, 1994. A permit renewal application was submitted for the Comanche generating station prior to the expiration of its existing permit. All discharge permits that are not renewed by the CWQCD prior to their expiration date automatically receive an administrative extension pending the issuance of a final permit. Environmental regulations at the Federal, state and local levels, including the Clean Air Act Amendments of 1990, some of which are discussed in Note 8. Commitments and Contingencies - Environmental Issues in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, are expected to have a continuing impact on the Company's operations. The Company continues to strive to achieve compliance with all environmental regulations currently applicable to its operations. However, it is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations or, generally, what effect future laws or regulations may have upon the Company's operations. Competition Industry Outlook During 1994, unprecedented change occurred in the electric utility industry nationwide, furthering the development of a competitive environment. In general, the economics of the electric generation business have fundamentally changed with open transmission access and the increased availability of electric supply alternatives. Such alternatives will ultimately serve to lower customer prices, particularly in areas where only higher cost energy is currently provided. Customer demands for lower prices and supplier choices, coupled with the availability of alternative supplies (IPPFs, QFs, EWGs and power marketers), have created significant pressure for open access to the utility transmission grid and the creation of a commodity market for bulk electric supply. The EPAct directly addressed this issue by giving FERC the authority to require utilities to provide non-discriminatory open access to the transmission grid for purposes of providing wholesale 14 customers with direct access. Additionally, an increasing number of states have recently begun to evaluate or pursue regulatory reform in an effort to proactively respond to this changing business environment and address the issue of retail wheeling. The presence of competition and the associated pressure on prices may ultimately lead to the unbundling of products and services similar to what has evolved in the natural gas industry. The concept of a vertically integrated utility, coupled with current regulatory practices, remain increasingly incongruent with the economic forces shaping the industry. Today's market view of the future envisions an unbundled electric utility industry consisting of at least four major business segments: energy supply, transmission, distribution and energy services- each having a different driving force. State Regulatory Environment Colorado law permits the CPUC to authorize rates negotiated with individual electric and gas customers which have threatened to discontinue using the services of the Company, so long as the CPUC finds that such authorization 1) in the case of electric rates, will not affect adversely the Company's remaining customers and 2) in the case of gas rates, will not affect the Company's remaining customers as adversely as would the alternative. In response to the increasingly competitive operating environment for utilities, the regulatory climate also is changing. Currently, the Company is participating in several CPUC dockets that address this change, and it is in the process of investigating various incentive/performance-based alternative forms of regulation. However, the Company believes it will continue to be subject to rate regulation that will allow for the recovery of all of its deferred costs (see Note 1. Summary of Significant Accounting Policies - Business and Regulation - Regulatory Assets and Liabilities and Note 8. Commitments and Contingencies - Regulatory Matters in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). Electric The wholesale electric business faces increasing competition in the supply of bulk power due to provisions of the EPAct and Federal and state initiatives with respect to providing open access to utility transmission systems. The Company does not anticipate that these provisions will have a material impact on its operations in the near-term. For 1994, the Company's wholesale revenues totaled approximately 9% of total electric revenues. A substantial portion of these revenues related to firm sales contracts, which are expected to continue at current levels for a minimum of 8 years. In addition, since 1992, the Company has had a FERC-approved transmission tariff, which provides for open access, with certain limitations. During 1994, the Company was notified by one wholesale customer of its intent to reduce future firm and peaking power purchases in accordance with current contractual arrangements. This customer is seeking a CPCN to construct its own generation facilities to serve its customers' needs. The Company has proposed alternative power supply arrangements for such customer's consideration. Today, the retail electric business faces increasing competition from industrial and large commercial customers who have the ability to own or operate facilities to generate their own electric energy requirements. In addition, customers may have the option of substituting fuels, such as natural gas for heating, cooling and manufacturing purposes rather than electric energy, or of relocating their facilities to a lower cost environment. While the Company faces these challenges, it believes its rates are competitive with currently available alternatives. The Company is taking actions to lower operating costs and is working with its customers to analyze the feasibility of various options, including energy efficiency, load management and co- 15 generation in order to better position the Company to more effectively operate in a competitive environment. Natural Gas Historically, gas utilities have competed with suppliers of electricity and fuel oil, as well as, to a lesser extent, propane, for sales of gas to customers for heating and/or cooling purposes. In the 1980s, industrial and large commercial customers began to "by-pass" the local gas utility through the construction of interconnections directly with, and the purchase of gas directly from, interstate pipelines, thereby avoiding the additional charges added by the local gas utility. In addition, industrial and commercial customers sought to purchase less expensive supplies of natural gas directly from producers, marketers and brokers. The Company has been actively involved for several years in providing transportation services for those industrial and large commercial customers who chose to purchase gas directly from suppliers. In addition, the Company has provided flexible transportation rates for several years. The per-unit fee charged for transportation services, while significantly less than the per-unit fee charged for the sale of gas to a similar customer, provides an operating margin approximately equivalent to the margin earned on gas sold. Therefore, increases in such activities will not have as great an impact on gas revenues as increases in deliveries from the sale of gas, but will have a positive impact on operating margin. Franchises The Company and its subsidiaries held nonexclusive franchises to provide electric or gas service or both services in 119 incorporated cities and towns at December 31, 1994. These franchises consist of 69 combined gas and electric service franchises, 28 electric service franchises and 22 gas service franchises. The Company is currently providing gas and electric service to one previously franchised municipality while a new franchise is being negotiated. The Company's franchise with the City of Denver will expire in 2006. The Company and its subsidiaries supply electric or gas service or both services in about 114 unincorporated communities in which franchises are not required. Employees The number of employees of the Company and its subsidiaries decreased from 6,507 at December 31, 1993 to 5,160 at December 31, 1994. The number of employees covered by collective bargaining agreements at December 31, 1994 was 2,449. The decrease in the number of employees is primarily due to an early retirement/severance package offered by the Company in 1994 and to an involuntary severance program implemented as part of the Company's restructuring activities in 1994. Effective February 13, 1995, approximately 390 positions were outsourced as part of a ten-year agreement with ISSC to manage most of the Company's information technology systems and network infrastructure. Research and Development The Company and its utility subsidiaries spent approximately $3.8 million in 1994, $4.3 million in 1993 and $4.8 million in 1992 on research and development. The major portion of those expenditures went to utility associations which engage in research projects to benefit the electric and gas industries as a whole. The balance of the expenditures went for smaller internal and external projects dealing with such areas as pollution control and alternative fuels research. 16
Consolidated Electric Operating Statistics Year Ended December 31, 1994 1993 1992 1991 1990 Energy Generated, Received, & Sold (Thousands of Kwh): Net Generated: Steam, Fossil . . . . . . . . . . . . . 15,949,980 15,470,247 14,972,688 13,164,941 13,103,990 Combustion Turbine . . . . . . . . . . . 41,705 39,228 47,194 7,643 5,440 Pumped Storage . . . . . . . . . . . . . 126,721 118,593 79,609 68,988 77,309 Hydro . . . . . . . . . . . . . . . . . 176,264 198,272 175,010 147,686 141,663 Total Net Generation . . . . . . . . 16,294,670 15,826,340 15,274,501 13,389,258 13,328,402 Energy Used for Pumping . . . . . . . . 201,744 185,850 126,266 111,008 124,648 Total Net System Input . . . . . . . 16,092,926 15,640,490 15,148,235 13,278,250 13,203,754 Purchased Power and Net Interchange . . . 9,653,067 9,631,982 8,663,339 8,738,907 8,416,081 Total System Input . . . . . . . . . 25,745,993 25,272,472 23,811,574 22,017,157 21,619,835 Used by Company . . . . . . . . . . . . 66,348 60,396 64,125 71,506 69,461 Other(1) . . . . . . . . . . . . . . . . 1,670,591 2,001,832 1,932,333 1,493,291 1,401,956 Total Energy Sold . . . . . . . . . . 24,009,054 23,210,244 21,815,116 20,452,360 20,148,418 Electric Sales (Thousands of Kwh)(2): Residential . . . . . . . . . . . . . . 6,119,914 5,969,529 5,747,048 5,699,374 5,552,879 Commercial . . . . . . . . . . . . . . . 8,931,962 10,797,272 10,350,155 10,307,829 10,175,316 Industrial . . . . . . . . . . . . . . . 5,726,837 3,289,501 3,375,638 3,334,405 3,382,450 Public Authorities . . . . . . . . . . . 187,939 186,397 187,500 184,315 185,813 Other Utilities(3) . . . . . . . . . . . 3,042,402 2,967,545 2,154,775 926,437 851,960 Total Energy Sold . . . . . . . . . . 24,009,054 23,210,244 21,815,116 20,452,360 20,148,418 Number of Customers at End of Period(2): Residential . . . . . . . . . . . . . . 913,582 898,752 894,217 880,676 871,455 Commercial . . . . . . . . . . . . . . . 120,886 120,317 120,198 119,118 118,332 Industrial . . . . . . . . . . . . . . . 384 157 194 179 164 Public Authorities . . . . . . . . . . . 77,842 76,476 647 660 653 Other Utilities(3) . . . . . . . . . . . 18 20 34 29 29 Total Customers . . . . . . . . . . 1,112,712 1,095,722 1,015,290 1,000,662 990,633 Electric Revenues (Thousands of Dollars)(2): Residential . . . . . . . . . . . . . . $ 453,614 $ 433,521 $ 413,655 $ 403,095 $ 389,935 Commercial . . . . . . . . . . . . . . . 519,340 602,187 572,780 568,588 553,429 Industrial . . . . . . . . . . . . . . . 252,552 142,146 148,951 147,997 146,114 Public Authorities . . . . . . . . . . . 21,950 20,828 20,221 19,256 19,185 Other Utilities (3) . . . . . . . . . . 120,238 116,937 80,290 35,480 32,323 Other Electric Revenues . . . . . . . . 32,142 21,434 24,872 6,085 4,929 Total Electric Revenues . . . . . . . $1,399,836 $1,337,053 $1,260,769 $1,180,501 $ 1,145,915 Average Annual Kwh Sales per Residential Customer 6,770 6,717 6,533 6,563 6,445 Average Annual Revenue per Residential Customer $501.82 $487.81 $470.26 $464.17 $452.59 Average Residential Revenue per Kwh . . . . .0741 .0726 .0720 .0707 .0702 Average Commercial Revenue per Kwh . . . . .0581 .0558 .0553 .0552 .0544 Average Industrial Revenue per Kwh . . . . .0441 .0432 .0441 .0444 .0432 Average Other Utilities Revenue per Kwh . . .0395 .0394 .0373 .0383 .0379 _________________________ (1) Primarily includes net distribution and transmission line losses. (2) Comparison of energy sales, customers and electric revenues to prior periods is impacted by: 1) a change in criteria for counting customers resulting from the implementation of a new customer information system during 17 1993, and 2) effective January 1, 1994, a reclassification to include large commercial customers (>1,000 Kw demand) within the industrial category, to be consistent with recommended utility industry guidelines. (3) Includes sales to four additional wholesale customers, resulting from the April 1992 Colorado-Ute asset acquisition.
18
Consolidated Gas Operating Statistics Year Ended December 31, 1994 1993 1992 1991 1990 Natural Gas Purchased and Sold (Thousands of Mcf)(1): Purchased from Interstate . . . . . . . 53,337 64,494 69,309 68,398 66,739 Purchased from Others . . . . . . . . . 104,102 103,609 92,302 96,358 93,180 Total Purchased . . . . . . . . . . 157,439 168,103 161,611 164,756 159,919 Company Use . . . . . . . . . . . . . . 2,817 2,750 3,041 2,262 1,830 Other(2) . . . . . . . . . . . . . . . . 4,515 (2,111) 7,070 2,628 4,706 Total Gas Sold . . . . . . . . . . . 150,107 167,464 151,500 159,866 153,383 Gas Deliveries (Thousands of Mcf)(1): Residential . . . . . . . . . . . . . . 92,036 98,350 87,560 91,807 86,622 Commercial . . . . . . . . . . . . . . . 57,366 62,193 57,321 61,266 58,722 Industrial . . . . . . . . . . . . . . . 118 1,097 1,772 2,468 3,604 Public Authorities . . . . . . . . . . . - 88 141 134 130 Other Utilities . . . . . . . . . . . . 587 5,736 4,706 4,191 4,305 Total Gas Sold . . . . . . . . . . . 150,107 167,464 151,500 159,866 153,383 Transported Gas . . . . . . . . . . . . 78,194 71,922 60,404 54,214 46,374 Gathered and Processed Gas . . . . . . . 29,889 42,010 33,052 18,622 11,170 Total Deliveries . . . . . . . . . . 258,190 281,396 244,956 232,702 210,927 Number of Customers at End of Period: Residential . . . . . . . . . . . . . . 845,464 820,521 808,722 792,646 780,157 Commercial . . . . . . . . . . . . . . . 87,077 86,202 85,954 85,317 84,672 Industrial . . . . . . . . . . . . . . . 26 25 237 331 327 Public Authorities . . . . . . . . . . . - - 1 1 1 Other Utilities . . . . . . . . . . . . 8 8 8 9 9 Total . . . . . . . . . . . . . . . 932,575 906,756 894,922 878,304 865,166 Transported Gas and Other . . . . . . . 786 619 416 275 233 Total Customers . . . . . . . . . . 933,361 907,375 895,338 878,579 865,399 Gas Revenues (Thousands of Dollars): Residential . . . . . . . . . . . . . . $ 375,406 $ 366,445 $ 329,406 $ 343,692 $ 327,403 Commercial . . . . . . . . . . . . . . . 202,873 201,693 185,851 198,160 190,409 Industrial . . . . . . . . . . . . . . . 438 2,887 5,213 7,765 11,166 Public Authorities . . . . . . . . . . . - 240 302 371 345 Other Utilities . . . . . . . . . . . . 7,319 13,966 10,099 9,198 10,003 Transported Gas . . . . . . . . . . . . 23,495 23,176 20,638 18,966 16,981 Gathered and Processed Gas . . . . . . . 8,335 10,575 8,023 5,465 2,829 Other Gas Revenues . . . . . . . . . . . 7,056 9,342 9,354 3,992 2,576 Total Gas Revenues . . . . . . . . . $ 624,922 $ 628,324 $ 568,886 $ 587,609 $ 561,712 Average Annual Mcf Sales per Residential Customer 110.59 120.85 109.5 116.8 112.0 Average Annual Revenue per Residential Customer $451.09 $450.29 $411.94 $437.40 $419.66 Average Residential Revenue per Mcf . . . . $4.079 $3.726 $3.762 $3.744 $3.780 Average Commercial Revenue per Mcf . . . . $3.536 $3.243 $3.242 $3.234 $3.243 Average Industrial Revenue per Mcf . . . . $3.716 $2.631 $2.942 $3.146 $3.098 Average Transport Gas Revenue per Mcf . . . $0.300 $0.322 $0.342 $0.350 $0.366 _________________________ (1) Volumes are reported at local pressure base. (2) Primarily includes distribution and transmission line losses and net changes to gas in storage. 19 Electric Transmission Map This page is a map of Colorado showing the Company's electric transmission interconnected system. 20 Item 2. Properties Electric Property The electric generating stations of the Company and its subsidiaries expected to be available at the time of the anticipated 1995 net firm system peak demand during the summer season are as follows:
Net Dependable Capacity Installed (Mw) Gross at Time of Major Name of Station Capacity 1995 Net Firm System Fuel and Location (Mw) Peak Demand* Source ________________ ___________ ___________ __________ Steam: Arapahoe-Denver . . . . . . . . . . . . . . 262.00 246.00 Coal Cameo-near Grand Junction . . . . . . . . . 77.00 72.70 Coal Cherokee-Denver . . . . . . . . . . . . . . 784.00 723.00 Coal Comanche-near Pueblo . . . . . . . . . . . . 725.00 660.00 Coal Craig-near Craig . . . . . . . . . . . . . . 86.89 (a) 83.20 Coal Hayden-near Hayden . . . . . . . . . . . . . 259.47 (b) 236.90 Coal Pawnee-near Brush . . . . . . . . . . . . . 530.00 495.00 Coal Valmont-near Boulder (Unit 5) . . . . . . . 188.00 178.00 Coal Zuni-Denver . . . . . . . . . . . . . . . . 115.00 107.00 Gas/Oil __________ __________ Total . . . . . . . . . . . . . . . . . . 3,027.36 2,801.80 Combustion turbines (6 units-various locations) . 209.00 171.00 Gas Hydro (14 units-various locations) (c) . . . . . 52.70 35.90 (d) Hydro Cabin Creek Pumped Storage-near Georgetown . . . 324.00 (e) 162.00 Hydro Diesel generators (7 units-various locations) . . 15.50 15.50 Oil __________ __________ Total . . . . . . . . . . . . . . . . . . . 3,628.56 3,186.20 ________________ * A measure of the unit capability planned to be available at the time of the system peak load net of seasonal reductions in unit capability due to weather, stream flow, fuel availability and station housepower, including requirements for air and water quality control equipment. (a) The gross maximum capability of Craig Units No. 1 and No. 2 is 894 Mw, of which the Company has a 9.72% undivided ownership interest. (b) The gross maximum capability of Hayden Units No. 1 and No. 2 is 202.01 Mw and 285.96 Mw, respectively, of which the Company has a 75.5% and 37.4% undivided ownership interest, respectively. (c) Includes one station (two units) not owned by the Company but operated under contract. (d) Seasonal Hydro Plant net dependable capabilities are based upon average water conditions and limitations for each particular season. The individual plant seasonal capabilities are sometimes limited by less than design water flow. (e) Capability at maximum load.
21 Nuclear Property Fort St. Vrain, near Platteville, the Company's only nuclear generating station, ceased operations on August 29, 1989 (see Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). Transmission and Distribution Property On December 31, 1994, the Company's transmission system consisted of approximately 182 circuit miles of 345 Kv overhead lines; 1,832 circuit miles of 230 Kv overhead lines; 15 circuit miles of 230 Kv underground lines; 65 circuit miles of 138 Kv overhead lines; 965 circuit miles of 115 Kv overhead lines; 19 circuit miles of 115 Kv underground lines; 355 circuit miles of 69 Kv overhead lines; 170 circuit miles of 44 Kv overhead lines; and 1 circuit mile of 44 Kv underground lines. The Company jointly owns with another utility approximately 347 circuit miles of 345 Kv overhead lines and 330 miles of 230 Kv overhead lines, of which the Company's share is 182 miles and 114 miles, respectively, which shares are included in the amounts listed above. The Company's transmission facilities are located wholly within Colorado. The map on page 18 illustrates the Company's transmission interconnected system. The system is interconnected with the systems of the following utilities with which the Company has major firm purchase power contracts; capacity and energy are provided primarily by generating sources in the locations indicated:
Utility Location Basin Electric Power Cooperative . . . . . . . . . . . . . . . . Southeast Wyoming PacifiCorp . . . . . . . . . . . . . . . . . . . . . . . . . . West & Northwest U.S. Northwest Colorado Platte River Power Authority . . . . . . . . . . . . . . . . . . Northcentral Colorado Tri-State. . . . . . . . . . . . . . . . . . . . . . . . . . . . Southeast Wyoming and Northwest Colorado
The Company has wheeling agreements with the above, and with other utilities and public power agencies, which are utilized to provide capacity and energy to the Company's system from time to time. The Company is a member of the WSCC, an interstate network of transmission facilities which are owned by public entities and investor-owned utilities. WSCC is the regional reliability coordinating organization for member electric power systems in the western United States. At December 31, 1994, the distribution systems consisted primarily of approximately 12,887 miles of overhead line, 1,068 miles of which are located on poles owned by other utilities under joint use agreements. The Company also owned approximately 7,389 cable miles of underground distribution system (excluding street lighting) located principally in the Denver metropolitan area. The Company owned 214 substations (four of which are jointly owned) having an aggregate transformer capacity of 18,179,300 Kva, of which 4,145,827 Kva is step-up transformer capacity at generating stations. Gas Property The gas property of the Company at December 31, 1994 consisted chiefly of approximately 14,619 miles of distribution mains ranging in size from 0.50 to 30 inches and related equipment. The Denver distribution system consisted 22 of 8,100 miles of mains. Pressures in the low pressure system are varied to meet load requirements and individual house regulators are installed on each customer's premises to provide uniform flow of gas to appliances. Other Property The Company's steam heating property at December 31, 1994 consisted of 10.5 miles of transmission, distribution and service lines in the business district of Denver, including a steam transmission line connecting the steam heating system with Zuni. Steam is supplied from boilers installed at the Company's Denver Steam Plant which has a capability of 295,000 pounds of steam per hour under sustained load and an additional 300,000 pounds of steam per hour is available from Zuni on a peak demand basis. The Company also owns service and office facilities in Denver and other communities strategically located throughout its service territory. Property of Subsidiaries The book value of the properties of the consolidated subsidiaries of the Company aggregates approximately 3% of the total book value of the properties of the Company and such subsidiaries combined. Such properties consist largely of electric and gas properties similar in character to the properties of the Company, except for the exploration, development and production properties still held by Fuelco (see Note 3. Divestiture of Nonutility Assets in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). Unregulated subsidiary property is approximately 2% of the total book value of the properties of the Company and consolidated subsidiaries combined. 1480 Welton, Inc. owns office buildings in Denver that are used by the Company. Character of Ownership The steam electric generating stations, the majority of major electric substations and the major gas regulator stations owned by the Company and its subsidiaries are on land owned in fee. Approximately half of the compressor stations and a limited number of town border and meter stations are also on land owned in fee. The remaining major electric substations and compressor stations and the majority of gas regulator stations and town border and meter stations are wholly or partially on land leased from others or on or along public highways or on streets or public places within incorporated towns and cities. The Company's Cabin Creek Pumped Storage Hydroelectric Generating Station, its Shoshone Hydroelectric Generating Station and a portion of the related intake tunnel are located on public lands of the United States. As to substantially all property on or across public lands of the United States, the Company or its subsidiaries hold licenses or permits issued by appropriate Federal agencies or departments. The Leyden gas storage facility is located largely on leased property under leases expiring December 31, 2040. The Company and its utility subsidiaries have the power of eminent domain pursuant to Colorado law to acquire property for their electric and gas facilities. The electric and gas transmission and distribution facilities are for the most part located over or under streets, public highways or other public places and on public lands under franchises or other rights, and on land owned by the Company or others pursuant to easements obtained from the record holders of title. The water rights of the Company and its subsidiaries are owned subject to divestment to the extent of any abandonment thereof. Substantially all of the utility plant and other physical property owned by the Company and its utility subsidiaries is subject to the liens of the respective indentures securing the mortgage bonds of the Company and its utility subsidiaries. 23 Item 3. Legal Proceedings See Note 2. Fort St. Vrain and Note 8. Commitments and Contingencies in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Item 4. Submission of Matters to a Vote of Security Holders Does not apply. 24 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters The Company's common stock is listed on the New York, Chicago and Pacific Stock Exchanges. The following table sets forth for the periods indicated the dividends declared per share of common stock and the high and low sale prices of the common stock on the consolidated tape as reported by The Wall Street Journal.
Dividends Price Range Year and Quarter Declared High Low 1994 First Quarter . . . . . . . . . . . . . . . . . . . . . . . . $ .50 $ 32 1/8 $ 28 1/2 Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . .50 29 3/4 25 3/8 Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . .50 27 7/8 24 3/4 Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . .50 30 1/8 25 7/8 $ 2.00 1993 First Quarter . . . . . . . . . . . . . . . . . . . . . . . . $ .50 $ 30 1/4 $ 27 1/2 Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . .50 33 1/4 28 1/2 Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . .50 33 3/8 31 Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . .50 32 7/8 28 $ 2.00
At December 31, 1994, the book value of the common stock was $20.39 per share. At February 24, 1995, there were 64,366 holders of record of the Company's common stock. The dividend level is dependent upon the Company's results of operations, financial position and other factors and is evaluated quarterly by the Board of Directors. The Company is subject to various uncertainties, including those associated with the eventual resolution of Fort St. Vrain decommissioning issues. See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. On February 26, 1991, the Company's Board of Directors declared a dividend of one common share purchase right ("right") on each outstanding share of the Company's common stock. All future common shares issued will contain this right. Each right stipulates an initial purchase price of $55 per share and also prescribes a means whereby the resulting effect is such that, under the circumstances described below, shareholders would be entitled to purchase additional shares of common stock at 50% of the prevailing market price at the time of exercise. The rights are not currently exercisable, but would become exercisable if certain events occurred related to a person or group acquiring or attempting to acquire 20% or more of the outstanding shares of common stock of the Company. In the event a takeover results in the Company being merged into an acquiror, the unexercised rights could be used to purchase shares in the acquiror at 50% of market price. Subject to certain conditions, if a person or group acquires 20% but no more than 50% of the Company's common stock, the Company's Board of Directors may exchange each right held by shareholders other than the acquiring person or group for one share of common stock (or its equivalent). 25 If a person or group successfully acquires 80% of the Company's common stock for cash, after tendering for all of the common stock, and satisfies certain other conditions, the rights would not operate. The rights expire on March 22, 2001; however, each right may be redeemed by the Board of Directors for one cent at any time prior to the acquisition of 20% of the common stock by a potential acquiror. For a description of the rights and their terms see the Company's Rights Agreement set forth as Exhibit 1 to the Company's Form 8-A filed with the SEC on March 1, 1991, which is incorporated herein by reference. 26 Item 6. Selected Financial Data The following selected consolidated financial data of the Company and its subsidiaries for each of the five years in the period ended December 31, 1994 should be read in conjunction with the consolidated financial statements and the management's discussion and analysis of financial condition and results of operations appearing elsewhere herein.
Year Ended December 31, 1994 1993 1992 1991 1990 (In Thousands-except per share data & ratios) Operating revenues: Electric . . . . . . . . . . . . . . . . $1,399,836 $1,337,053 $1,260,769 $1,180,501 $ 1,145,915 Gas . . . . . . . . . . . . . . . . . . 624,922 628,324 568,886 587,609 561,712 Other . . . . . . . . . . . . . . . . . 32,626 33,308 32,618 26,794 26,312 Total . . . . . . . . . . . . . . . . 2,057,384 1,998,685 1,862,273 1,794,904 1,733,939 Total operating expenses . . . . . . . . . 1,786,592 1,717,752 1,612,646 1,551,326 1,495,533 Operating income . . . . . . . . . . . . . 270,792 280,933 249,627 243,578 238,406 Total interest charges . . . . . . . . . . 132,134 130,337 121,116 101,537 97,296 Net income . . . . . . . . . . . . . . . . 170,269 157,360 136,623 149,693 146,144 Dividend requirements on preferred stock: . 12,014 12,031 12,077 12,234 12,439 Earnings available for common stock: . . . 158,255 145,329 124,546 137,459 133,705 Per share data applicable to common stock (a): Earnings . . . . . . . . . . . . . . . . $ 2.57 $ 2.43 $ 2.16 $ 2.48 $ 2.49 Dividends declared . . . . . . . . . . . $ 2.00 $ 2.00 $ 2.00 $ 2.00 $ 2.00 Shares of common stock outstanding: Weighted average . . . . . . . . . . . . 61,547 59,695 57,558 55,471 53,626 Year-end . . . . . . . . . . . . . . . . 62,155 60,457 58,477 56,294 54,320 Rate of return earned on average common equity (net to common) . . . . . . . . . . . . 12.9% 12.7% 11.7% 13.8% 14.3% Ratio of earnings to fixed charges (b) . . . . . . . . . . . 2.53 2.54 2.43 2.94 3.07 Total assets . . . . . . . . . . . . . . . $4,207,832 $4,057,600 $3,759,583 $3,462,668 $ 3,233,840 Total net plant . . . . . . . . . . . . . . 3,291,402 3,193,136 3,077,509 2,745,800 2,609,261 Total construction expenditures . . . . . . 317,138 293,515 261,666 260,704 261,221 AFDC . . . . . . . . . . . . . . . . . . 7,158 12,667 11,302 9,437 6,715 Cash generated internally as a percent of construction expenditures (c) . . . . . 35.4% 52.2% 57.5% 69.4% 67.6% Total common equity . . . . . . . . . . . . $1,267,482 $1,184,183 $1,101,047 $1,034,433 $ 963,663 Preferred stock: Not subject to mandatory redemption . . 140,008 140,008 140,008 140,008 140,008 Subject to mandatory redemption at par (including amounts due within one year) 45,241 45,454 45,654 46,368 48,944 Long-term debt (including amounts due within one year) 1,180,580 1,193,668 1,199,779 993,965 938,264 Notes payable & commercial paper . . . . . 324,800 276,875 250,626 200,640 213,833 _________________________ (a) Earnings per share are based on the weighted average number of shares of common stock outstanding. (b) See Exhibit 12(a) herein. (c) Calculated as cash provided by operations net of cash used for dividends, divided by construction expenditures net of AFDC equity-component.
27 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Industry Outlook During 1994, unprecedented change occurred in the electric utility industry nationwide, furthering the development of a competitive environment. In general, the economics of the electric generation business have fundamentally changed with open transmission access and the increased availability of electric supply alternatives. Such alternatives will ultimately serve to lower customer prices, particularly in areas where only higher cost energy is currently provided. Customer demands for lower prices and supplier choices, coupled with the availability of alternative supplies (IPPFs, QFs, EWGs and power marketers), have created significant pressure for open access to the utility transmission grid and the creation of a commodity market for bulk electric supply. The EPAct directly addressed this issue by giving FERC the authority to require utilities to provide non-discriminatory open access to the transmission grid for purposes of providing wholesale customers with direct access. Additionally, an increasing number of states recently have begun to evaluate or pursue regulatory reform in an effort to proactively respond to this changing business environment. The presence of competition and the associated pressure on prices ultimately may lead to the unbundling of products and services similar to what has evolved in the natural gas industry. The concept of a vertically integrated utility, coupled with current regulatory practices, remain increasingly incongruent with the economic forces shaping the industry. Today's market view of the future envisions an unbundled electric utility industry consisting of at least four major business segments: energy supply, transmission, distribution and energy services -each having a different driving force. Corporate Overview While the Company continues to pursue the overall long-term strategy of focusing on its core electric and natural gas businesses, during 1994, several short-term strategies, primarily designed to lower operating costs, were implemented to better position the Company to more effectively operate in a competitive environment. Initially, an early retirement/severance program was offered with approximately 550 employees electing to participate. Annual salary savings are estimated to be approximately $22 million. Total program costs, of approximately $39.7 million, are being amortized over 4.5 years, which is the remaining average estimated service life of the program participants. Following the early retirement/severance program, the Company restructured internally, consistent with an anticipated unbundled business approach, in order to more effectively address customers' needs. In conjunction with the internal restructuring, an involuntary severance program was implemented. Approximately 550 management and staff level positions were eliminated, resulting in an additional estimated annual salary savings of $21 million. Involuntary severance costs of approximately $10.7 million were recognized, of which $8.7 million served to reduce pre-tax earnings. Additionally, in conjunction with the internal restructuring process, 32 customer offices were closed in support of the overall cost-containment effort. As part of an effort to expand the Company's markets by providing value-added services, in January 1995, the Company and IBM formed an alliance to develop advanced customer service and energy management 28 applications for utility and energy-using customers. In particular, a subsidiary of IBM, ISSC, and the Company's new subsidiary, e prime, will develop and deliver new information technology-based applications to assist utilities and others across the country to provide more responsive and efficient customer service. IBM has committed to use the services of e prime, thus becoming its first customer. Also as part of the alliance, ISSC, under a ten-year agreement, will manage most of the Company's information technology systems and network infrastructure, resulting in the outsourcing of approximately 390 positions, effective February 13, 1995. Such arrangement is expected to result in an estimated $190 million savings to the Company during the ten-year period. In spite of having to recognize an additional $43.4 million in costs primarily associated with the decommissioning of Fort St. Vrain in 1994, important milestones were achieved with the repowering and decommissioning activities. In July 1994, the CPUC approved a CPCN allowing the Company to repower the facility in a phased approach. The first phase is expected to be completed in 1996. Additionally, on January 26, 1995, the Company received NRC approval of its Final Survey Plan for Site Release, reducing the future uncertainty related to the completion of the decommissioning project. Decommissioning work is approximately 67% complete at December 31, 1994. Also supporting the Company's strategy of focusing on its core electric and gas businesses, in August 1994, the Company sold all of the outstanding common stock of WGG and certain related operating assets for $87 million, resulting in a gain of approximately $34.5 million. In response to the increasingly competitive operating environment for utilities, the regulatory climate also is changing. Currently, the Company is participating in several CPUC dockets that address this change, and it is in the process of investigating various incentive/performance- based alternative forms of regulation. However, the Company believes it will continue to be subject to rate regulation that will allow for the recovery of all of its deferred costs. Earnings Earnings per share were $2.57, $2.43 and $2.16 during 1994, 1993 and 1992, respectively. The increase in 1994 earnings was primarily due to the gain on the sale of WGG, as discussed above, and higher electricity sales. Furthermore, during 1994, the Company recognized additional defueling and decommissioning costs associated with Fort St. Vrain and a favorable income tax accrual adjustment following a complete analysis of the Company's income tax liabilities associated with the adoption of full normalization. The lower earnings for 1992 reflect charges related to the divestiture of certain of the Company's nonutility assets. 29 Electric Operations The following table details the annual change in electric revenues and energy costs as compared to the preceding year:
Increase (Decrease) From Prior Years 1994 1993 (Thousands of Dollars) Electric revenues: Retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 48,774 $ 43,075 Wholesale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,301 36,647 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,708 (3,438) Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62,783 76,284 Fuel used in generation . . . . . . . . . . . . . . . . . . . . . . . . . . 3,200 12,086 Purchased power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40,134 30,004 Net increase in electric margin . . . . . . . . . . . . . . . . . . . . . $ 19,449 $ 34,194
Electric operating revenues increased in 1994 and 1993, when compared to the respective prior year, primarily due to favorable weather, moderate customer growth and additional revenues related to the collection of decommissioning, DSM and QF purchased power capacity costs. The increase in 1993 also includes the full-year effect of the April 1992 addition of four new wholesale customers. Warmer weather during the summer months was the primary factor that contributed to 3.4% and 6.4% increases in electricity sales in 1994 and 1993, respectively. Based on weather comparisons, it was 74% warmer than normal in 1994 and 18% warmer than normal in 1993. Base rates are changed only through rate proceedings with the Company's and Cheyenne's regulatory agencies. Effective December 1, 1993, in connection with the final 1993 rate decision issued by the CPUC, the Company reduced its retail rates by approximately $5.2 million. This $5.2 million is comprised of a $13.1 million electric revenue decrease, a $7.1 million gas revenue increase and a $0.8 million steam revenue increase. Concurrently, all of the Company's QF capacity costs, previously recovered through the ECA, became recoverable under the QFCCA. However, the recovery of costs under the QFCCA may be subject to an earnings test, which has not yet been defined by the CPUC (see Note 8. Commitments and Contingencies - Regulatory Matters in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). Effective July 1, 1993, a $13.9 million annual revenue increase associated with the recovery of nuclear decommissioning costs was implemented. The Company and Cheyenne currently have cost adjustment mechanisms which recognize the majority of the effects of changes in fuel used in generation and purchased power and allow recovery of such costs on a timely basis. As a result, the changes in revenues associated with these mechanisms in 1994, 1993 and 1992 had little impact on net income. Purchased power expense increased 10.1% in 1994 and 8.2% in 1993, primarily due to increased purchases from QFs. Fuel used in generation expense increased 1.6% in 1994 and 6.6% in 1993, primarily due to higher generation levels. The higher generation levels in 1993 were predominantly due to the April 1992 purchase of 331 Mw of additional generating capacity. 30 Gas Operations The following table details the annual change in gas revenues and gas purchased for resale as compared to the preceding year:
Increase (Decrease) From Prior Years 1994 1993 (Thousands of Dollars) Total gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (3,402) $ 59,438 Less: transport, gathering, and processing revenues . . . . . . . . . . . . (1,921) 5,090 Revenues from gas sales . . . . . . . . . . . . . . . . . . . . . . . . . (1,481) 54,348 Gas purchased for resale . . . . . . . . . . . . . . . . . . . . . . . . . 13,484 41,205 Net (decrease) increase in gas sales margin . . . . . . . . . . . . . . . $ (14,965) $ 13,143
Gas operating revenues declined in 1994 and increased in 1993, primarily due to changes in total gas deliveries resulting from weather variations. There were approximately 16% fewer heating degree days in 1994, as compared to 1993, and approximately 10% more heating degree days in 1993 as compared to 1992. The base rate increase, effective December 1, 1993 (as discussed above), and moderate customer growth mitigated some of the effects of the lower gas deliveries in 1994. Total gas deliveries decreased 8.2% in 1994 as a result of lower retail gas sales and the disposition of Fuelco assets, offset by higher transport deliveries. The growth in transportation services is primarily due to serving two new QF customers. Total gas deliveries increased 14.9% in 1993, due to colder weather and growth in the transport services as industrial customers have procured their own gas supplies. The per-unit fee charged for transportation services, while significantly less than the per-unit fee charged for the sale of gas to a similar customer, provides an operating margin approximately equivalent to the margin earned on gas sold. Therefore, increases in such activities will not have as great an impact on gas revenues as increases in deliveries from the sale of gas. However, they will have a positive impact on operating margin. The Company and its regulated subsidiaries have in place GCA mechanisms for natural gas sales, which recognize the majority of the effects of changes in the cost of gas purchased for resale and adjust revenues to reflect such changes in cost on a timely basis. As a result, the changes in revenues associated with these mechanisms in 1994 and 1993, when compared to the respective preceding year, had little impact on net income. However, the fluctuations in gas sales impact the amount of gas the Company must purchase and, therefore, affect total gas purchased for resale along with increases and decreases in the per-unit cost of gas. The increase in gas purchased for resale for 1994 reflects the higher price of gas purchased from major suppliers. The increase in gas purchased for resale in 1993 is primarily due to higher gas sales, as well as a slight increase in the per-unit cost of gas. Non-Fuel Operating Expenses The Company recognized additional expenses aggregating approximately $43.4 million for increased costs associated with the defueling and decommissioning of Fort St. Vrain, as well as the impairment of certain related property and inventory. The additional expense is primarily associated with radiation levels in the reactor core being higher than originally anticipated and increased uncertainty related to spent fuel 31 disposal issues (see Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). Other operating and maintenance expenses decreased $16.7 million for 1994 compared to 1993, primarily due to lower labor costs resulting from the early retirement/severance program that was completed April 1, 1994, decreased maintenance expenses at the Company's steam generating plants and lower costs due to the ending of Fuelco operations. These decreases have been offset, in part, by increased OPEB costs and the severance costs associated with the Company's involuntary workforce reductions. The $34.0 million increase in other operating and maintenance expenses in 1993, when compared to 1992, is primarily due to increased labor and benefits costs. Other non-fuel operating expenses in 1992 included the recognition of charges to earnings associated with the Synhytech and BCC transactions of approximately $26.9 million and $11.4 million, respectively. Depreciation and amortization expense decreased in 1994, when compared to 1993, primarily due to the effects of using a CPUC-approved longer estimated depreciable life of the Company's electric steam production facilities. Higher 1993 depreciation expense reflects additional assets acquired from Colorado-Ute and other property additions. The 1994 and 1993 depreciation and amortization expense also include the amortization of the decommissioning regulatory asset associated with Fort St. Vrain, which became effective July 1, 1993, along with the collection of such costs. The decrease in income tax expense for 1994 includes a $21.3 million adjustment to the income tax liabilities as a result of a detailed analysis of the Company's income tax liabilities in conjunction with the Company's implementation of the full normalization method of accounting for income taxes which was provided for in a recent CPUC rate order. The increase in 1993 income tax expense, when compared to 1992, reflects a 1% increase in the Federal tax rate and higher pre-tax income offset by the $1.9 million benefit realized from the adoption of SFAS 109. Other income and deductions increased $24.8 million in 1994, primarily due to the approximately $34.5 million gain on the sale of WGG. This gain was offset, in part, by lower AFDC and the $3.0 million reversal of the 1991 gas search award as the Colorado Supreme Court reversed the incentive award previously granted by the CPUC. Interest charges increased $1.8 million in 1994 as compared to 1993. Interest on long-term debt, net of amortization costs, decreased $8.0 million in 1994 because the Company refinanced certain long-term debt issues with lower-cost debt. However, this decrease was more than offset by a $9.2 million increase in other interest, primarily due to increased levels of short-term borrowings in 1994, compared to 1993. Interest charges increased $9.2 million in 1993, compared to 1992. This was primarily due to higher interest on long-term debt, reflecting the issuance of $250 million in First Mortgage Bonds in April 1992, to finance the Colorado-Ute asset acquisition, as well as the issuance of $50 million in medium-term notes. Commitments and Contingencies Issues relating to Fort St. Vrain, regulatory and environmental matters are discussed in Notes 2 and 8 in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. On November 26, 1993, the CPUC issued its final decision in connection with the 1993 rate case denying the Company any rate relief and 32 lowering the Company's overall revenue requirements by approximately $5.2 million. The Company is implementing strategies which include reductions in operating expenses, at a minimum, to the historic test period level. It is possible, however, that despite such efforts, the Company could be required to issue increasing amounts of short-term and long-term securities to fund cash requirements. It is also possible that the Company's results of operations and financial position could be adversely affected over time. The Company's common stock dividend level is dependent upon the Company's results of operations, financial position and other factors. It will continue to be evaluated quarterly by the Board of Directors. The Company is subject to various uncertainties, including those associated with eventual resolution of Fort St. Vrain decommissioning issues. Liquidity and Capital Resources Cash Flows Cash provided by operating activities decreased $34.2 million for 1994, primarily due to the non-cash impact of the tax accrual adjustment. Cash provided by operations increased $7.1 million during 1993, when compared to 1992, primarily due to increased earnings and higher depreciation and amortization related to property additions, including the acquisition of the Colorado-Ute assets. Although the Company collected approximately $14 million and $6 million in 1994 and 1993, respectively, for the decommissioning of Fort St. Vrain, significant expenditures associated with this project will continue to reduce operating cash flows through 1996. Cash used in investing activities decreased $61.9 million for 1994, primarily due to the 1994 sale of WGG. This decrease was offset, in part, by increased construction expenditures. Cash used in investing activities decreased $192.6 million for 1993, primarily due to the 1992 acquisition of Colorado-Ute assets. In addition, in 1993 three new wholesale customers prepaid 100%, or approximately $24.9 million, of a twenty-five year surcharge associated with the Colorado-Ute acquisition. In comparing 1993 to 1992, however, this was offset by the 1992 receipt of approximately $75 million in loan proceeds from insurance policies held by one of the Company's subsidiaries. Cash used in financing activities increased approximately $6.8 million in 1994, primarily due to increased repayments of long-term debt, decreased proceeds from the sale of common stock and increased dividends, offset by higher short-term borrowings. Cash provided by financing activities decreased approximately $247.7 million during 1993, primarily due to the 1992 issuance of $250 million in First Mortgage Bonds related to the acquisition of the Colorado-Ute assets. 33 Prospective Capital Requirements and Sources At December 31, 1994, the Company and its subsidiaries estimated the cost of their construction programs, including AFDC and other capital requirements, in 1995, 1996 and 1997 to be as follows:
1995 1996 1997 (Thousands of Dollars) Company: Electric Production* . . . . . . . . . . . . . . . . . . $92,500 $111,312 $130,172 Transmission . . . . . . . . . . . . . . . . . . 13,015 33,110 15,699 Distribution . . . . . . . . . . . . . . . . . . 74,037 80,626 83,693 Gas . . . . . . . . . . . . . . . . . . . . . . . . 77,949 69,663 41,600 General** . . . . . . . . . . . . . . . . . . . . . . 58,514 44,710 40,878 Subtotal . . . . . . . . . . . . . . . . . . . 316,015 339,421 312,042 Subsidiaries . . . . . . . . . . . . . . . . . . . . 6,688 7,437 3,538 Total construction . . . . . . . . . . . . . . 322,703 346,858 315,580 Less: AFDC . . . . . . . . . . . . . . . . . . . . . 6,645 5,020 3,410 Add: Sinking funds and debt maturities . . . . . . . 43,188 86,451 78,948 Add: Fort St. Vrain Decommissioning . . . . . . . . . 33,243 13,962 0 Total capital requirements . . . . . . . . . . . $392,489 $442,251 $391,118 * Capital requirements for Electric Production include $117 million for Fort St. Vrain repowering (see Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). ** Capital requirements for the "General" category include assets leased under a leasing program.
The construction programs of the Company and its subsidiaries are subject to continuing review and adjustment. In particular, actual construction expenditures for the electric system may vary from the estimates due to changes in projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting the Company's long-term energy needs. In addition, actual decommissioning and defueling expenses may exceed the estimates, due to a variety of factors discussed in Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). Additionally, the Company evaluates merger, acquisition and divestiture opportunities on an ongoing basis to support the Company's corporate strategies. At December 31, 1994, the Company and its subsidiaries estimated that their 1995-1997 capital requirements would be met principally with a combination of funds from external sources and funds from operations. The Company and its subsidiaries may meet their external capital requirements through the issuance of first collateral trust bonds, preferred and/or common stock, by increasing the level of borrowing under PSCCC's medium-term note program or through short-term borrowing under committed and uncommitted bank borrowing arrangements discussed below. The financing needs are subject to continuing review and can change depending on market and business conditions and changes, if any, in the construction plans of the Company and its subsidiaries. The Company's Automatic Dividend Reinvestment and Common Stock Purchase Plan allows its shareholders to purchase additional shares of the 34 Company's common stock through the reinvestment of cash dividends and the purchase of additional shares of common stock with optional cash payments. The proceeds from the dividend reinvestment plan also will provide funds to help meet the capital requirements of the Company. At December 31, 1994, the Company and its subsidiaries had temporary cash investments of $3.5 million. As of December 31, 1994, PSCCC had borrowed $167.5 million in short-term debt, for use primarily in the purchase of the Company's customer accounts receivable and fossil fuel inventories. PSCCC may periodically convert short-term debt to medium-term notes. As of December 31, 1994, PSCCC had no medium-term notes outstanding. The level of financing of PSCCC is tied directly to daily changes in the level of the Company's outstanding customer accounts receivable and monthly changes in fossil fuel inventories. The Company expects that the amount of financing associated with PSCCC will vary minimally from year-to-year, although seasonal fluctuations in the level of assets will cause corresponding fluctuations in the level of associated financing. In 1990, the Company filed a registration statement with the SEC for the issuance of $500 million principal amount of first mortgage bonds of which $200 million was designated for a secured medium-term note program. As of December 31, 1994, $169.5 million principal amount of medium-term notes had been issued, and $250 million of first mortgage bonds had been issued. In 1993, the Company filed a registration statement with the SEC for the issuance of $322.667 million principal amount of first collateral trust bonds for the purpose of refunding outstanding debt securities and for the payment of short-term indebtedness incurred for such purposes, of which $212.667 million principal amount has been issued. On August 2, 1994, the Company filed a registration statement with the SEC for the issuance of first collateral trust bonds and cumulative preferred stock for the purpose of funding its construction program, refunding certain issues of its cumulative preferred stock and other general corporate purposes. The aggregate principal amount of first collateral trust bonds, plus the aggregate par value of shares of cumulative preferred stock, will not exceed $306.0 million. To date none of these registered securities has been issued. The Company's Indenture dated as of December 1, 1939 (the "1939 Indenture"), which is a mortgage on the Company's electric and gas properties, permits the issuance of additional first mortgage bonds to the extent of 60% of the value of net additions to the Company's utility property, provided net earnings before depreciation, taxes on income and interest expense for a recent twelve month period are at least 2.5 times the annual interest requirements on all bonds to be outstanding. The 1939 Indenture also permits the issuance of additional bonds on the basis of retired first mortgage bonds, in some cases with no requirement to satisfy such net earnings test. At December 31, 1994, the amount of net additions, as of December 31, 1993, would permit (and the net earnings test would not prohibit) the issuance of approximately $98 million of new bonds (in addition to the $200 million principal amount of secured medium-term notes discussed above) at an assumed annual interest rate of 8.9%. At January 31, 1995, the amount of retired bonds would permit the issuance of $889 million of new bonds. The Company's Indenture dated as of October 1, 1993 (the "1993 Indenture") is a second mortgage on the Company's electric properties. Generally, so long as the Company's 1939 Indenture remains in effect, first collateral trust bonds will be issued under the 1993 Indenture on the basis of the deposit with the trustee of an equal principal amount of 35 first mortgage bonds issued under the 1939 Indenture. If the bonds issued under the 1939 Indenture are to be issued on the basis of property additions, first collateral trust bonds may be issued under the 1993 Indenture only if net earnings before depreciation, taxes on income, interest expenses and non-recurring charges for a recent twelve-month period are at least 2 times annual interest requirements on all first mortgage bonds (other than bonds held by the trustee under the 1993 Indenture) and all first collateral trust bonds to be outstanding. As of December 31, 1994, coverage under the net earnings test was in excess of 5 times such annual interest requirements. The Company's Restated Articles of Incorporation prohibit the issuance of additional preferred stock without preferred shareholder approval, unless the gross income available for the payment of interest charges for a recent twelve month period is at least 1.5 times the total of: 1) the annual interest requirements on all indebtedness to be outstanding for more than one year; and 2) the annual dividend requirements on all preferred stock to be outstanding. At December 31, 1994, gross income available under this requirement would permit the Company, if allowed under provisions of the Company's Restated Articles of Incorporation, to issue approximately $1.7 billion of additional preferred stock at an assumed annual dividend rate of 8.25%. Coverage of gross income to interest charges was 4.5 at December 31, 1994. The Company's Restated Articles of Incorporation prohibit, without preferred shareholder approval, the issuance or assumption of unsecured indebtedness, other than for refunding purposes, greater than 15% of the aggregate of: 1) the total principal amount of all bonds or other securities representing secured indebtedness of the Company, then outstanding; and 2) the total of the capital and surplus of the Company, as then recorded on its books. At December 31, 1994, the Company had outstanding unsecured indebtedness, including subsidiary indebtedness with the credit support of the Company, in the amount of $157.4 million. The maximum amount permitted under this limitation was approximately $383.9 million at December 31, 1994. At December 31, 1994, the Company and certain of its subsidiaries had arrangements for bank lines of credit totaling $300 million in committed lines, of which $41.2 million was then available. On January 3, 1994, the Company established uncommitted lines of credit totaling $25 million which were increased throughout the year to $75 million. The amount of unused uncommitted bank lines of credit at December 31, 1994 was $9.0 million. These uncommitted lines of credit were renewed on December 31, 1994 and expire on December 31, 1995. The Company could generally borrow under the uncommitted pre-approved lines of credit upon request; however, the banks have no firm commitment to make such loans. On November 22, 1994, the Company, PSCCC and certain subsidiaries extended a credit facility with several banks providing $300 million in committed bank lines of credit. The credit facility, which is used primarily to support the issuance of commercial paper by the Company and PSCCC, alternatively provides for direct borrowing thereunder. Under the current extension, Cheyenne, 1480 Welton, Inc., Fuelco and PSRI are provided access to the credit facility with direct borrowings guaranteed by the Company. Generally, the banks participating in the credit facility would have no obligation to continue their commitments if there has been a material adverse change in the consolidated financial condition, operations, business or otherwise that would prevent the Company and its subsidiaries from performing their obligation under the credit facility. The credit facility expires November 21, 1995. The Company expects to seek renewal of the credit facility at that time (see Note 7. Bank Lines 36 of Credit and Compensating Bank Balances in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). 37 Item 8. Financial Statements and Supplementary Data REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS TO PUBLIC SERVICE COMPANY OF COLORADO We have audited the accompanying consolidated balance sheets of Public Service Company of Colorado (a Colorado corporation) and subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1994. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Public Service Company of Colorado and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. As more fully discussed in Note 2 to the consolidated financial statements, the adequacy of the Company's recorded liability for defueling and decommissioning its Fort St. Vrain Nuclear Generating Station (approximately $77.0 million at December 31, 1994) is primarily dependent on assurances that the dismantlement and decommissioning of the Fort St. Vrain Nuclear Generating Station can be accomplished at currently estimated costs and that the spent fuel storage and shipment issues are successfully resolved. The outcome of the above issues cannot be determined at this time. The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of these uncertainties. As more fully discussed in Notes 10 and 12 to the consolidated financial statements, effective January 1, 1993, the Company changed its methods of accounting for postretirement benefits other than pensions and for income taxes and, effective January 1, 1994, the Company changed its method of accounting for postemployment benefits. Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index of financial statements is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial 38 statements taken as a whole. We have also audited, in accordance with generally accepted auditing standards, the consolidated balance sheets as of December 31, 1992, 1991 and 1990 and the related consolidated statements of income, shareholders' equity and cash flows for each of the two years in the period ended December 31, 1991, (none of which are presented herein) and have expressed an opinion, which makes reference to uncertainties related to the Company's Fort St. Vrain Nuclear Generating Station, on those financial statements. In our opinion, the information set forth in the selected financial data for each of the five years in the period ended December 31, 1994 appearing in Item 6 of this Form 10-K, other than the ratios and percentages therein, is fairly stated, in all material respects, in relation to the financial statements from which it has been derived. Denver, Colorado ARTHUR ANDERSEN LLP February 10, 1995 39
PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Thousands of Dollars) December 31, 1994 and 1993 ASSETS 1994 1993 Property, plant and equipment, at cost: Electric . . . . . . . . . . . . . . . . . . . . . . . . . . $3,641,711 $3,466,627 Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 867,239 929,718 Steam and other . . . . . . . . . . . . . . . . . . . . . . . 86,458 75,288 Common to all departments . . . . . . . . . . . . . . . . . . 369,070 356,633 Construction in progress . . . . . . . . . . . . . . . . . . 187,577 181,802 5,152,055 5,010,068 Less: accumulated depreciation . . . . . . . . . . . . . . . 1,860,653 1,816,927 Total property, plant and equipment . . . . . . . . . . . . 3,291,402 3,193,141 Investments, at cost . . . . . . . . . . . . . . . . . . . . . . 18,202 18,487 Current assets: Cash and temporary cash investments . . . . . . . . . . . . . 5,883 18,038 Accounts receivable, less reserve for uncollectible accounts ($3,173 at December 31, 1994; $3,276 at December 31, 1993) (Schedule II) . . . 163,465 149,637 Accrued unbilled revenues (Note 1) . . . . . . . . . . . . . 86,106 76,983 Recoverable purchased gas and electric energy costs - net (Note 1) 37,979 60,692 Materials and supplies, at average cost . . . . . . . . . . . 67,600 77,732 Fuel inventory, at average cost . . . . . . . . . . . . . . . 31,370 35,484 Gas in underground storage, at cost (LIFO) . . . . . . . . . 42,355 41,130 Current portion of accumulated deferred income taxes (Note 12) 20,709 4,201 Regulatory assets recoverable within one year (Note 1) . . . 39,985 20,891 Prepaid expenses and other . . . . . . . . . . . . . . . . . 16,312 13,580 Total current assets . . . . . . . . . . . . . . . . . . . . 511,764 498,368 Deferred charges: Regulatory assets (Note 1) . . . . . . . . . . . . . . . . . 335,893 285,061 Unamortized debt expense . . . . . . . . . . . . . . . . . . 11,073 10,378 Pension benefits (Note 10) . . . . . . . . . . . . . . . . . 1,031 23,149 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38,467 29,016 Total deferred charges . . . . . . . . . . . . . . . . . . . 386,464 347,604 $4,207,832 $4,057,600
The accompanying notes to consolidated financial statements are an integral part of these financial statements. 40
PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Thousands of Dollars) December 31, 1994 and 1993 CAPITAL AND LIABILITIES 1994 1993 Common stock (Note 4) . . . . . . . . . . . . . . . . . . . . . . $ 959,268 $ 910,848 Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . 308,214 273,335 Total common equity . . . . . . . . . . . . . . . . . . . . 1,267,482 1,184,183 Preferred stock (Note 4): Not subject to mandatory redemption . . . . . . . . . . . . . 140,008 140,008 Subject to mandatory redemption at par . . . . . . . . . . . 42,665 42,878 Long-term debt (Note 5) . . . . . . . . . . . . . . . . . . . . . 1,155,427 1,135,344 2,605,582 2,502,413 Noncurrent liabilities: Defueling and decommissioning liability (Note 2) . . . . . . 40,605 45,220 Employees' postretirement benefits other than pensions (Note 10) 42,106 28,145 Employees' postemployment benefits (Note 10) . . . . . . . . 20,975 - Total noncurrent liabilities . . . . . . . . . . . . . . . . 103,686 73,365 Current liabilities: Notes payable and commercial paper (Note 6) . . . . . . . . . 324,800 276,875 Long-term debt due within one year . . . . . . . . . . . . . 25,153 58,324 Preferred stock subject to mandatory redemption within one year (Note 4) 2,576 2,576 Accounts payable . . . . . . . . . . . . . . . . . . . . . . 177,031 214,599 Dividends payable . . . . . . . . . . . . . . . . . . . . . . 34,078 33,234 Customers' deposits . . . . . . . . . . . . . . . . . . . . . 17,099 16,225 Accrued taxes . . . . . . . . . . . . . . . . . . . . . . . . 54,148 70,796 Accrued interest . . . . . . . . . . . . . . . . . . . . . . 32,265 29,507 Current portion of defueling and decommissioning liability (Note 2) 36,365 47,887 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62,640 64,664 Total current liabilities . . . . . . . . . . . . . . . . . 766,155 814,687 Deferred credits: Customers' advances for construction . . . . . . . . . . . . 96,442 76,204 Unamortized investment tax credits . . . . . . . . . . . . . 118,532 124,331 Accumulated deferred income taxes (Note 12) . . . . . . . . 485,668 445,530 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31,767 21,070 Total deferred credits . . . . . . . . . . . . . . . . . . . 732,409 667,135 Commitments and contingencies (Notes 2 and 8) . . . . . . . . . . $4,207,832 $4,057,600
The accompanying notes to consolidated financial statements are an integral part of these financial statements. 41
PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Thousands of Dollars Except per Share Data) Years ended December 31, 1994, 1993 and 1992 1994 1993 1992 Operating revenues: Electric . . . . . . . . . . . . . . . . . . . . . . . . . . $1,399,836 $1,337,053 $1,260,769 Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 624,922 628,324 568,886 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,626 33,308 32,618 2,057,384 1,998,685 1,862,273 Operating expenses: Fuel used in generation . . . . . . . . . . . . . . . . . . . 198,118 194,918 182,832 Purchased power . . . . . . . . . . . . . . . . . . . . . . . 437,087 396,953 366,949 Gas purchased for resale . . . . . . . . . . . . . . . . . . 397,877 384,393 343,188 Other operating expenses . . . . . . . . . . . . . . . . . . 369,094 376,686 346,368 Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . 67,097 76,229 72,540 Defueling and decommissioning (Note 2) . . . . . . . . . . . 43,376 - - Termination of Synhytech project (Note 3) . . . . . . . . . . - - 26,893 Loss on sale of real estate investments (Note 3) . . . . . . - - 11,370 Depreciation and amortization . . . . . . . . . . . . . . . . 139,035 140,804 127,317 Taxes (other than income taxes) . . . . . . . . . . . . . . 86,408 86,775 82,040 Income taxes (Note 12) . . . . . . . . . . . . . . . . . . . 48,500 60,994 53,149 1,786,592 1,717,752 1,612,646 Operating income . . . . . . . . . . . . . . . . . . . . . . . . 270,792 280,933 249,627 Other income and deductions: Allowance for equity funds used during construction . . . . . 3,140 8,119 7,378 Miscellaneous income and deductions - net (Note 3) . . . . . 28,471 (1,355) 734 302,403 287,697 257,739 Interest charges: Interest on long-term debt . . . . . . . . . . . . . . . . . 89,005 98,089 92,581 Amortization of debt discount and expense less premium . . . 3,126 2,018 1,790 Other interest . . . . . . . . . . . . . . . . . . . . . . . 44,021 34,778 30,669 Allowance for borrowed funds used during construction . . . . (4,018) (4,548) (3,924) 132,134 130,337 121,116 Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . 170,269 157,360 136,623 Dividend requirements on preferred stock . . . . . . . . . . . . 12,014 12,031 12,077 Earnings available for common stock . . . . . . . . . . . . . . . $ 158,255 $ 145,329 $ 124,546 Shares of common stock outstanding (thousands): Year-end . . . . . . . . . . . . . . . . . . . . . . . . . . 62,155 60,457 58,477 Weighted average . . . . . . . . . . . . . . . . . . . . . . 61,547 59,695 57,558 Earnings per weighted average share of common stock outstanding . $2.57 $2.43 $2.16
The accompanying notes to consolidated financial statements are an integral part of these financial statements. 42
PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Thousands of Dollars, Except Share Information) Years ended December 31, 1994, 1993 and 1992 Common Stock, $5 par value Premium on Retained Shares Amount Common Stock Earnings Total Balance at January 1, 1992 . . . . . 56,293,525 $ 281,468 $ 514,250 $ 238,715 $1,034,433 Net Income . . . . . . . . . . . . . - - - 136,623 136,623 Dividends Declared Common Stock, $2.00 per share . . . - - - (115,546) (115,546) Preferred Stock, $100 par value . . - - - (9,127) (9,127) Preferred Stock, $25 par value . . - - - (2,940) (2,940) Issuance of Common Stock Employees' Savings Plan . . . . . . 333,418 1,667 7,022 - 8,689 Dividend Reinvestment Plan . . . . 1,849,862 9,249 39,666 - 48,915 Balance at December 31, 1992 . . . . 58,476,805 292,384 560,938 247,725 1,101,047 Net Income . . . . . . . . . . . . . - - - 157,360 157,360 Dividends Declared Common Stock, $2.00 per share . . . - - - (119,722) (119,722) Preferred Stock, $100 par value . . - - - (9,088) (9,088) Preferred Stock, $25 par value . . - - - (2,940) (2,940) Issuance of Common Stock Employees' Savings Plan . . . . . . 329,220 1,646 7,716 - 9,362 Dividend Reinvestment Plan . . . . 1,651,350 8,257 39,907 - 48,164 Balance at December 31, 1993 . . . . 60,457,375 302,287 608,561 273,335 1,184,183 Net Income . . . . . . . . . . . . . - - - 170,269 170,269 Dividends Declared Common Stock, $2.00 per share . . . - - - (123,379) (123,379) Preferred Stock, $100 par value . . - - - (9,071) (9,071) Preferred Stock, $25 par value . . - - - (2,940) (2,940) Issuance of Common Stock Employees' Savings Plan . . . . . . 334,223 1,671 8,439 - 10,110 Dividend Reinvestment Plan . . . . 1,355,104 6,775 31,308 - 38,083 Omnibus Incentive Plan . . . . . . 7,892 39 188 - 227 Balance at December 31, 1994 . . . 62,154,594 $ 310,772 $ 648,496 $ 308,214 $1,267,482 Authorized shares of common stock were 160 million and 140 million at December 31, 1994 and 1993, respectively.
The accompanying notes to consolidated financial statements are an integral part of these financial statements. 43
PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Thousands of Dollars) Years ended December 31, 1994, 1993 and 1992 1994 1993 1992 Operating activities: Net income . . . . . . . . . . . . . . . . . . . . . . . . . $ 170,269 $ 157,360 $ 136,623 Adjustments to reconcile net income to net cash provided by operating activities (Note 1): Depreciation and amortization . . . . . . . . . . . . . . 142,843 143,940 134,335 Defueling and decommissioning expenses . . . . . . . . . . 43,376 - - Gain on sale of WGG . . . . . . . . . . . . . . . . . . . (34,485) - - Termination of Synhytech project . . . . . . . . . . . . . - - 26,893 Loss on sale of real estate investments . . . . . . . . . - - 11,370 Amortization of investment tax credits . . . . . . . . . . (5,799) (4,917) (5,138) Deferred income taxes . . . . . . . . . . . . . . . . . . 34,234 33,435 23,766 Allowance for equity funds used during construction . . . (3,140) (8,119) (7,378) Change in accounts receivable . . . . . . . . . . . . . . (16,281) (3,813) 10,380 Change in inventories . . . . . . . . . . . . . . . . . . 10,007 (25,378) 6,024 Change in other current assets . . . . . . . . . . . . . . (1,695) (14,619) (24,670) Change in accounts payable . . . . . . . . . . . . . . . . (35,364) 31,909 10,373 Change in other current liabilities . . . . . . . . . . . (39,730) (5,439) (16,101) Change in deferred amounts . . . . . . . . . . . . . . . . (33,920) (17,483) 23,011 Change in noncurrent liabilities . . . . . . . . . . . . . 15,321 (14,759) (57,207) Other . . . . . . . . . . . . . . . . . . . . . . . . . . 92 7,762 521 Net cash provided by operating activities . . . . . . . 245,728 279,879 272,802 Investing activities: Construction expenditures . . . . . . . . . . . . . . . . . . (317,138) (293,515) (261,666) Allowance for equity funds used during construction . . . . . 3,140 8,119 7,378 Colorado-Ute asset acquisition . . . . . . . . . . . . . . . - - (265,385) Proceeds from sale of WGG . . . . . . . . . . . . . . . . . . 87,000 - - Proceeds from (cost of) disposition of property, plant and equipment 49,438 43,120 (3,187) Purchase of other investments . . . . . . . . . . . . . . . . (955) (5,660) (6,348) Sale of other investments . . . . . . . . . . . . . . . . . . 1,148 8,678 97,357 Net cash used in investing activities . . . . . . . . . (177,367) (239,258) (431,851) 44 Financing activities: Proceeds from sale of common stock (Note 1) . . . . . . . . . 38,086 47,894 48,914 Proceeds from sale of long-term notes and bonds (Note 1) . . 250,068 257,913 296,476 Redemption of long-term notes and bonds . . . . . . . . . . . (281,835) (274,829) (94,197) Short-term borrowings - net . . . . . . . . . . . . . . . . . 47,925 26,249 49,986 Redemption of preferred stock . . . . . . . . . . . . . . . . (213) (200) (714) Dividends on common stock . . . . . . . . . . . . . . . . . . (122,531) (118,732) (114,454) Dividends on preferred stock . . . . . . . . . . . . . . . . (12,016) (12,033) (12,081) Net cash (used in) provided by financing activities . . (80,516) (73,738) 173,930 Net (decrease) increase in cash and temporary cash investments (12,155) (33,117) 14,881 Cash and temporary cash investments at beginning of year 18,038 51,155 36,274 Cash and temporary cash investments at end of year . . . $ 5,883 $ 18,038 $ 51,155
The accompanying notes to consolidated financial statements are an integral part of these financial statements. 45 PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1994 1. Summary of Significant Accounting Policies Business and regulation The Company is an operating public utility engaged, together with its subsidiaries, principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transmission, distribution, sale and transportation of natural gas. The Company is subject to the jurisdiction of the CPUC with respect to its retail electric and gas operations and the FERC with respect to its wholesale electric operations and accounting policies and practices. Cheyenne and WGI are subject to the jurisdiction of the WPSC and the FERC, respectively. Regulatory assets and liabilities The Company and its regulated subsidiaries prepare their financial statements in accordance with the provisions of SFAS 71. In general, SFAS 71 recognizes that accounting for rate regulated enterprises should reflect the relationship of costs and revenues introduced by rate regulation. As a result, a regulated utility may defer recognition of a cost (a regulatory asset) or recognize an obligation (a regulatory liability) if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in revenues. To the extent the Company concludes that collection of such revenues (or payment of liabilities) is no longer probable, through changes in regulation and/or the Company's competitive position, the associated regulatory asset or liability will be reversed with a charge or credit to income. 46 The following regulatory assets are reflected in the Company's consolidated balance sheets:
Recovery 1994 1993 Through (Thousands of Dollars) Nuclear decommissioning costs (Note 2) . . . . . . . . . $ 107,374 $ 118,419 2005 Income taxes (Note 12) . . . . . . . . . . . . . . . . . 125,832 132,647 2006 Employees' postretirement benefits other than pensions (Note 10) . . . . . . . . . . . . . 37,573 25,855 2013 Early retirement costs (Note 10) . . . . . . . . . . . . 33,124 - 1998 Employees' postemployment benefits (Note 10) . . . . . . 20,975 - Undetermined Demand-side management costs . . . . . . . . . . . . . . 20,831 10,424 2001 Unamortized debt reacquisition costs . . . . . . . . . . 22,360 18,607 2024 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 7,809 - 1999 Total . . . . . . . . . . . . . . . . . . . . . . . . . 375,878 305,952 Classified as current . . . . . . . . . . . . . . . . . . 39,985 20,891 Classified as noncurrent . . . . . . . . . . . . . . . . $ 335,893 $ 285,061
Certain costs associated with the Company's DSM programs are deferred and recovered in rates over a seven-year period through the DSMCA, which was implemented July 1, 1993. Non-labor incremental expenses, carrying costs associated with deferred DSM costs and incentives associated with approved DSM programs are recovered on an annual basis. Costs incurred to reacquire debt prior to scheduled maturity dates are deferred and amortized over the life of the debt issued to finance the reacquisition or as approved by the regulator. Recoverable purchased gas and electric energy costs - net The Company and Cheyenne tariffs contain clauses which allow recovery of certain purchased gas and electric energy costs in excess of the level of such costs included in base rates. These cost adjustment tariffs are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred. A substantial portion of this deferred amount represents the costs incurred to provide gas and electric energy which customers have used but for which they have not yet been billed. The cumulative effects are recognized as a current asset or liability until adjusted by refunds or collections through future billings to customers. Other Property, plant and equipment includes approximately $18.4 million and $25.4 million, respectively, for costs associated with the engineering design of the future Pawnee 2 generating station and certain water rights located in southeastern Colorado, also obtained for a future generating 47 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) station. Effective with the December 1, 1993 CPUC rate order, the Company is earning a return on these investments based on the Company's weighted average cost of debt and preferred stock. Consolidation The Company follows the practice of consolidating the accounts of its significant subsidiaries. All intercompany items and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to the current year's presentation. Revenue recognition The Company and Cheyenne accrue for estimated unbilled revenues for services provided after the meters were last read on a cycle billing basis through the end of each year. Statements of cash flows For purposes of the consolidated statements of cash flows, the Company and its subsidiaries consider all temporary cash investments to be cash equivalents. These temporary cash investments are securities having original maturities of three months or less or having longer maturities but with put dates of three months or less. Income taxes and interest (excluding amounts capitalized) paid:
1994 1993 1992 (Thousands of Dollars) Income taxes . . . . . . . . . . . . . . . . . . . . . . . $ 41,763 $ 49,196 $ 38,624 Interest . . . . . . . . . . . . . . . . . . . . . . . . . $ 126,250 $ 129,844 $ 112,695
Non-cash transactions: Shares of common stock (334,223 in 1994, 329,220 in 1993 and 333,418 in 1992), valued at the market price on date of issuance (approximately $10.1 million in 1994, $9.4 million in 1993 and $8.7 million in 1992), were issued to the Employees' Savings and Stock Ownership Plan of Public Service Company of Colorado and Participating Subsidiary Companies. The estimated issuance values were recognized in other operating expenses during the respective preceding years. During 1994, 7,892 shares of common stock, valued at the market price on date of issuance (approximately $0.2 million), were issued to certain executives. These stock issuances were not cash transactions and are not reflected in the consolidated statement of cash flows. A $16.8 million capital lease obligation was incurred in 1994 for computer equipment. 48 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Changes in certain balance sheet accounts, resulting from the sale of WGG in 1994 and the Colorado-Ute acquisition in 1992, have been recognized as non-cash activity. Property and depreciation Replacements and betterments representing units of property are capitalized. Maintenance and repairs of property and replacements of items of property determined to be less than a unit of property are charged to operations as maintenance. The cost of units of property retired, together with cost or removal, less salvage, is charged against accumulated depreciation. Provisions for depreciation of property for financial accounting purposes are based on straight-line composite rates applied to the various classes of depreciable property. Depreciation rates include provisions for disposal and removal costs of property, plant and equipment. Depreciation expense, expressed as a percentage of average depreciable property, approximated 2.6% for the year ended December 31, 1994 and 3.0% for the years ended December 31, 1993 and 1992. The average rate for 1994 reflects the effects of using a CPUC-approved longer estimated depreciable life for the Company's electric steam production facilities. For income tax purposes, the Company and its subsidiaries use accelerated depreciation and other elections provided by the tax laws. Allowance for funds used during construction AFDC, as defined in the system of accounts prescribed by the FERC and the CPUC, represents the net cost during the period of construction of borrowed funds used for construction purposes, and a reasonable rate on funds derived from other sources. AFDC does not represent current cash earnings. The Company capitalizes AFDC as a part of the cost of utility plant. The AFDC rates or ranges of rates used during 1994, 1993 and 1992 were 6.81%-8.75%, 10.21% and 8.95%-10.21%, respectively. Income taxes The Company and its subsidiaries file consolidated Federal and state income tax returns. Income taxes are allocated to the subsidiaries based on separate company computations of taxable income or loss. Investment tax credits have been deferred and are being amortized over the service lives of the related property. Deferred taxes are provided on temporary differences between the financial accounting and tax bases of assets and liabilities using the tax rates which are in effect at the balance sheet date (see Note 12). Gas in underground storage Gas in underground storage is accounted for under the last-in, first-out (LIFO) cost method. The estimated replacement cost of gas in 49 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) underground storage at December 31, 1994, exceeded the LIFO cost by approximately $12.5 million. Cash surrender value of life insurance policies The following amounts related to COLI contracts, issued by one major insurance company, are recorded as a component of Investments, at cost, on the consolidated balance sheets:
1994 1993 (Thousands of Dollars) Cash surrender value of contracts . . . . . . . . . . . . . . . . . . . . . $ 267,445 $ 228,195 Borrowings against contracts . . . . . . . . . . . . . . . . . . . . . . . 265,568 226,429 Net investment in life insurance contracts . . . . . . . . . . . . . . $ 1,877 $ 1,766
2. Fort St. Vrain Overview During 1994, the Company recognized additional expenses aggregating approximately $43.4 million ($26.7 million after-tax or 43 cents per share) associated with various Fort St. Vrain issues as described below, including the defueling and decommissioning of the facility. During 1986, the Company entered into a Stipulation and Settlement Agreement with the CPUC, the OCC and the other parties involved in litigation and administrative proceedings related to Fort St. Vrain's history of limited operations. As a result, the Company's investment in Fort St. Vrain was removed from rate base and certain charges were recognized including the write-down of a substantial portion of such investment and the recognition of the then estimated future unrecoverable defueling and decommissioning expenses. In 1989, the Company announced its decision to end nuclear operations at Fort St. Vrain. The decision was based on the financial impact of an anticipated lengthy outage necessary to repair the plant's steam generator system coupled with the plant's history of reduced levels of generation. The Company has completed defueling from the reactor to the ISFSI as discussed below in the section entitled "Defueling" and is currently decommissioning the facility as described below in the section entitled "Decommissioning." The Company has been pursuing the repowering of Fort St. Vrain and, on July 1, 1994, the CPUC issued a decision granting the Company's application for a CPCN for Phase 1 and Phase 2. The decision approved, with certain modifications, a Stipulation and Settlement Agreement (the 50 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Settlement) among the Company, the OCC and various other parties regarding the CPCN. Repowering Fort St. Vrain will be repowered as a gas fired combined cycle steam plant consisting of two combustion turbines and two heat recovery steam generators totalling 471 Mw. The CPCN provides for the repowering of Fort St. Vrain in a phased approach as follows: Phase 1A - 130 Mw in 1996, Phase 1B - 102 Mw in 1998 and Phase 2 - 239 Mw in 1999. The phased repowering allows the Company flexibility in timing the addition of this generation supply to meet future load growth. The Settlement provides for approximately $67.4 million of the then remaining $72.5 million investment in the existing Fort St. Vrain assets (comprised of approximately $60.1 million in plant assets and a $12.4 million regulatory asset associated with deferred income taxes) to be returned to rate base in future electric rate cases following the completion of each phase or phases of the repowering. The Settlement allows for the following assignment of existing assets: Phase 1A - $28.9 million, Phase 1B - $27.6 million and Phase 2 - $10.9 million. The approximately $5 million balance of the Company's remaining investment in Fort St. Vrain assets will not be returned to rate base pursuant to the Settlement. During 1994, the Company completed an evaluation of alternative uses of these assets and concluded that approximately $4.5 million of such assets will not be recovered; therefore, a $4.5 million impairment reserve has been established. Because of the receipt of the CPCN related to the repowering of Fort St. Vrain, the Company believes the recovery of the remaining investment in the facility is probable. Additionally, a detailed assessment of inventory requirements necessary for the completion of decommissioning and repowering was completed during 1994. Such analysis identified that approximately $4.5 million of inventory costs will not be recovered and, therefore, a $4.5 million impairment reserve has also been established. Decommissioning The Company has been pursuing the early dismantlement/decommissioning of Fort St. Vrain following the 1991 CPUC approval of the recovery from customers of approximately $124.4 million (plus a 9% carrying cost) for such activities, as well as the 1992 NRC approval of the Company's early dismantlement/decommissioning plan. The decommissioning amount being recovered from customers, which began July 1, 1993 and extends over a twelve-year period, represents the inflation- adjusted estimated remaining cost of the early dismantlement/decommissioning activities not previously recognized as expense. At December 31, 1994, approximately $107.4 million of such amount remains to be collected from customers and, therefore, is reflected as a regulatory asset on the consolidated balance sheet. The annual 51 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) amount recovered from customers each year is approximately $13.9 million. The Company has contracted with Westinghouse Electric Corporation and MK-Ferguson, a division of Morrison Knudsen Corporation, for the early dismantlement/decommissioning of Fort St. Vrain. Since defueling has been completed from the reactor to the ISFSI and the NRC decommissioning order has been received, the Company and the contractors have proceeded with decommissioning activities. At December 31, 1994, approximately 67% of the decommissioning process has been performed with final completion of such activities anticipated in the second quarter of 1996. The decommissioning contract stipulates a fixed price, based on a defined work scope; however, such price has been and could be further modified due to changes in work scope or applicable regulations. In addition to the four substantive changes in work scope previously agreed to by the Company since the initiation of decommissioning activities, the decommissioning contractors notified the Company of several additional potential scope changes which were primarily related to the identification of higher radiation levels in the reactor core than originally anticipated and regulatory changes related to site release as discussed below. On October 25, 1994, the Company and the decommissioning contractors reached an agreement resolving all issues and claims related to identified and certain possible future changes in scope of work covered by the contract, with certain exceptions. In order to complete all decommissioning activities related to such scope changes, the Company recognized an additional $15 million in decommissioning expense during 1994. The significant exceptions to the agreement, which were also areas for potential changes in the defined work scope under the decommissioning contract, include changes in law, radioactive material created by activation in the lower portion of the reactor, as well as changes in the methodology requirements and guidance established by the NRC for final site release. On January 26, 1995, the Company received NRC approval of its Final Survey Plan for Site Release reducing the future uncertainty related to this issue. In the event additional costs are identified, which relate to an issue excepted from the agreement, the decommissioning contractors will perform all required activities on a cost basis. While this agreement with the decommissioning contractors does not eliminate all future decommissioning risk, the Company believes it will serve to substantially reduce such risk. However, the Company can provide no assurance that recognition of additional costs will not be required if events or circumstances unknown to the Company today are identified in the future. 52 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Defueling Currently, six segments of Fort St. Vrain's spent nuclear fuel (segments 4-9) are stored in the ISFSI located at the plant site. While the Company has entered into two separate agreements with the DOE for (a) the temporary storage and processing of segments 1-8 at a DOE facility located in the State of Idaho (such contract includes an option to store/reprocess additional spent fuel segments at the DOE's discretion) and (b) the disposal of segment 9 at a Federal repository, resolution of all spent fuel reprocessing/disposal issues has been substantially delayed pending resolution of several lawsuits filed during 1991 by and among the Company, the DOE, the State of Idaho and the Shoshone - Bannock Indian Tribes. While the plant was operating and as part of routine refueling procedures, three spent fuel segments were transported to the Idaho facility. It is currently estimated that the Federal repository will not be available until 2010. The Company, however, intends to pursue with the DOE the storage/reprocessing of segment 9 at the Idaho facility in conjunction with the first eight segments. Most recently, the DOE has required that an EIS be completed relative to, among other things, the receipt and storage of spent fuel at the Idaho facility. The DOE had issued a draft EIS and the Company has submitted comments. Modifications to the Idaho facility will be required to accommodate the new spent fuel shipping casks. These modifications would be completed subsequent to the issuance of the EIS. The time required for these modifications from the DOE has been estimated to be between 15-18 months. In addition, the DOE has stated that a facility readiness review will be required. Such review is standard DOE procedure required to validate the readiness of equipment following a shut-down period. Such review will also be conducted subsequent to the completion of the EIS. As a result of increased uncertainties related to the ultimate disposal of Fort St. Vrain's spent nuclear fuel, the Company recognized during 1994 an additional $15 million defueling reserve, determined on a present value basis. This amount represents the estimated cost of operating and maintaining the ISFSI until 2020 (if required), the earliest date the Company believes a Federal repository will be available to accept the Company's spent nuclear fuel. These estimated expenditures have been escalated for inflation using an average rate of 3.5% and discounted to present value at a rate of 8%. The estimated total cost of defueling and decommissioning Fort St. Vrain is approximately $361.8 million. At December 31, 1994, approximately $284.8 million has been spent for such activities with the remaining $77 million defueling and decommissioning liability reflected on the consolidated balance sheet ($25 million - defueling; $52 million - decommissioning). Because of the possibility of further changes in the decommissioning work scope, changes in applicable regulations and/or the uncertainties related to the final disposal of spent fuel, there can be no 53 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) assurance that the actual cost of defueling and decommissioning will not exceed the estimated liability. The Company could be required to revise the estimated cost of defueling and decommissioning as a result of any such matters. Funding Under NRC regulations, the Company is required to make filings with, and obtain the approval of, the NRC regarding certain aspects of the Company's decommissioning proposals, including funding. On January 27, 1992, the NRC accepted the Company's funding aspects of the decommissioning plan. The Company has also obtained an unsecured irrevocable letter of credit totaling $125 million that meets the NRC's stipulated funding guidelines including those proposed on August 21, 1991 that address decommissioning funding requirements for nuclear power reactors that have been prematurely shut down. In accordance with the NRC funding guidelines, the Company is allowed to reduce the balance of the letter of credit based upon milestone payments made under the fixed-price decommissioning contract. As a result of such payments, at December 31, 1994, the letter of credit had been reduced to $66 million. The Company had previously set aside approximately $30 million in trust accounts for decommissioning the reactor. Since decommissioning activities have commenced, the Company completed withdrawing funds from the trust accounts during the second quarter of 1993. As previously discussed, on July 1, 1993, the Company began collection of the remaining decommissioning costs from customers. In addition, the Company has established a separate decommissioning trust for the ISFSI which had funds of approximately $1.6 million at December 31, 1994. It is anticipated that this amount, together with the expected earnings on the funds, will be sufficient to decommission the ISFSI. Costs for maintaining the ISFSI and removing fuel from the ISFSI, which the Company is not required to prefund, will be paid from a combination of operating funds of the Company and its subsidiaries and/or external financing. Uranium Enrichment Facility Decommissioning Assessment As part of the EPAct, the DOE Uranium Enrichment Enterprise Decontamination and Decommissioning Fund was established to provide for the decommissioning of DOE fuel enrichment facilities. The EPAct provides for a 15 year assessment of all domestic utilities that own nuclear generation facilities. The Company believed it would be excluded from the provisions of the EPAct as Fort St. Vrain was constructed under the Atomic Energy Demonstration Reactor Program. During 1994, the DOE advised the Company that it has not been exempted from the provisions of the EPAct. As a result, the Company recognized an approximate $4 million expense 54 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) associated with this assessment, determined on a present value basis (escalated for inflation at 4% and discounted at 8%). The Company, however, intends to further investigate the applicability of the EPAct as well as the recovery of such costs through the regulatory process. However, the Company is uncertain as to the ultimate resolution of this issue. Nuclear Insurance The Price Anderson Act, as amended, limits the public liability of a licensee for a single nuclear incident at its nuclear power plant to the amount of financial protection available through liability insurance and deferred premium assessment charges, currently approximately $7.8 billion, which includes a 5% surcharge. Financial protection for this exposure is provided by private insurance in an amount available from private insurers (currently $200 million). The Price Anderson Act also requires licensees to participate in an assessable excess liability program through an indemnity program with the NRC. Under the terms of this indemnity program, the Company could be liable for retrospective assessments of approximately $79 million per nuclear incident at any domestic nuclear power plant, indexed every five years for inflation, provided that not more than $10 million would be payable per incident in any one year. In consideration of the shutdown and defueled status of Fort St. Vrain, the Company requested an exemption from its indemnification obligations under the Price Anderson Act. On February 17, 1994, the NRC granted this request, exempting the Company from participation in this indemnity program and limiting the amount of private insurance required to $100 million. In addition to the Company's liability insurance, Federal regulations require the Company to maintain $1.06 billion in nuclear property insurance. Effective February 1, 1991, however, the NRC granted the Company's exemption request to reduce the nuclear property insurance coverage from $1.06 billion to a minimum of $169 million. This lower limit would cover stabilization and decontamination expenses resulting from a worst case accident. The Company currently maintains $281 million in property damage and decontamination insurance. The additional insurance coverage above the required $169 million is necessary to provide coverage for the estimated depreciated replacement value of the plant assets that will be used in the repowering of Fort St. Vrain. 3. Divestiture of Nonutility Assets As part of the Company's continuing strategy to focus its efforts on the core electric and gas businesses, the Company has divested certain nonutility investments. WestGas Gathering, Inc. During the third quarter of 1994, the Company sold all of its 55 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) outstanding common stock of WGG, its wholly-owned subsidiary, and certain related operating assets of the Company which are used by WGG for approximately $87 million. The Company recognized a pre-tax gain of approximately $34.5 million ($19.5 million after-tax or approximately 31 cents per share). In addition, pursuant to a Stipulation and Agreement dated November 17, 1992, approved by the CPUC by Order dated December 7, 1992, the regulatory treatment of a limited portion of this gain may be subject to a proceeding before the CPUC. The Company believes the resolution of this matter will not have a material impact on the Company's results of operations or financial position. Fuel Resources Development Co. In June 1993, the Company's Board of Directors approved pursuing the divestiture of Fuelco, a wholly-owned subsidiary primarily involved in the exploration and production of oil and natural gas. In 1993, the Company recorded the estimated effects of the disposition of all properties, including all costs expected to be incurred through the close of operations. All property sales have been completed, except the San Juan Coal Bed Methane properties. The Company is re-evaluating its alternatives related to the disposition of these properties. The net book value of the San Juan properties is approximately $21.7 million. In December 1992, the Company terminated its involvement in Fuelco's Synhytech fuel conversion technology project. As a result, Fuelco recognized an expense of approximately $26.9 million ($16.8 million after- tax) associated with writing-off its entire investment in the Synhytech plant and recognizing certain additional costs which were incurred in connection with the termination of this project. Bannock Center Corporation In December 1992, BCC sold substantially all of its real estate properties located near downtown Denver for $6 million, resulting in a loss of approximately $11.4 million ($8.4 million after-tax). 4. Capital Stock Common Stock On December 7, 1992, the Company filed a registration statement with the SEC relating to the registration of 1,000,000 shares of common stock, $5 par value, and 1,000,000 common share purchase rights. These shares and rights are associated with the Company's Omnibus Incentive Plan discussed in Note 10. During 1991, the Company's Board of Directors declared a dividend of one common share purchase right (right) on each outstanding share of the Company's common stock. All future common shares issued will contain this right. Each right stipulates an initial purchase price of $55 per share 56 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) and also prescribes a means whereby the resulting effect is such that, under the circumstances described below, shareholders would be entitled to purchase additional shares of common stock at 50% of the prevailing market price at the time of exercise. These rights are not currently exercisable, but would become exercisable if certain events occurred related to a person or group acquiring or attempting to acquire 20% or more of the outstanding shares of common stock of the Company. In the event a takeover results in the Company being merged into an acquiror, the unexercised rights could be used to purchase shares in the acquiror at 50% of market price. Subject to certain conditions, if a person or group acquires 20%, but no more than 50% of the Company's common stock, the Company's Board of Directors may exchange each right held by shareholders other than the acquiring person or group for one share of common stock (or its equivalent). If a person or group successfully acquires 80% of the Company's common stock for cash, after tendering for all of the common stock, and satisfies certain other conditions, the rights would not operate. The rights expire on March 22, 2001; however, each right may be redeemed by the Board of Directors for one cent at any time prior to the acquisition of 20% of the common stock by a potential acquiror. 57 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Preferred Stock
1994 1993 Shares Amount Shares Amount (Thousands (Thousands of Dollars) of Dollars) Cumulative preferred stock, $100 par value: Authorized . . . . . . . . . . . . . . . . . . 3,000,000 3,000,000 Issued and outstanding: Not subject to mandatory redemption: 4.20% series . . . . . . . . . . . . . . 100,000 $ 10,000 100,000 $ 10,000 4 1/4% series (includes $7,500 premium) . 175,000 17,508 175,000 17,508 4 1/2% series . . . . . . . . . . . . . . 65,000 6,500 65,000 6,500 4.64% series . . . . . . . . . . . . . . 160,000 16,000 160,000 16,000 4.90% series . . . . . . . . . . . . . . 150,000 15,000 150,000 15,000 4.90% 2nd series . . . . . . . . . . . . 150,000 15,000 150,000 15,000 7.15% series . . . . . . . . . . . . . . 250,000 25,000 250,000 25,000 Total . . . . . . . . . . . . . . . . . 1,050,000 $ 105,008 1,050,000 $ 105,008 Subject to mandatory redemption: 7.50% series . . . . . . . . . . . . . . 216,000 $ 21,600 216,000 $ 21,600 8.40% series . . . . . . . . . . . . . . 236,412 23,641 238,545 23,854 452,412 45,241 454,545 45,454 Less: Preferred stock subject to mandatory redemption within one year . . . . . . . (25,760) (2,576) (25,760) (2,576) Total . . . . . . . . . . . . . . . . . 426,652 $ 42,665 428,785 $ 42,878 Cumulative preferred stock, $25 par value: Authorized . . . . . . . . . . . . . . . . . . 4,000,000 4,000,000 Issued and outstanding: Not subject to mandatory redemption: 8.40% series . . . . . . . . . . . . . . 1,400,000 $ 35,000 1,400,000 $ 35,000
The preferred stock may be redeemed at the option of the Company upon at least 30, but not more than 60, days notice in accordance with the following schedule of prices, plus an amount equal to the accrued dividends to the date fixed for redemption: Cumulative preferred stock, not subject to mandatory redemption: $100 par value, all series: $101 per share. $25 par value, 8.40% series: $25.25 per share. 58 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Cumulative preferred stock, subject to mandatory redemption: 7.50% series: $102.25 per share on or prior to August 31, 1995, reducing each year thereafter by $0.25 per share until August 31, 2003, after which the redemption price is $100 per share; 8.40% series: $102.50 per share on or prior to July 31, 1995, and reducing each year thereafter by $0.25 per share until July 31, 2004, after which the redemption price is $100 per share. In 1995 and in each year thereafter, the Company must offer to repurchase 12,000 shares of the 7.50% series subject to mandatory redemption at $100 per share, plus accrued dividends to the date set for repurchase, and 13,760 shares of the 8.40% series subject to mandatory redemption at $100 per share, plus accrued dividends to the date set for repurchase. Consequently, this preferred stock to be redeemed is classified as preferred stock subject to mandatory redemption within one year in the December 31, 1994 consolidated balance sheet. In 1994, 1993, and 1992, the Company repurchased 2,133 shares, 2,000 shares and 7,135 shares, respectively of the 8.40% cumulative preferred series subject to mandatory redemption. No other changes in preferred stock occurred in the three years ended December 31, 1994. 59 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
5. Long-Term Debt 1994 1993 (Thousands of Dollars) Public Service Company of Colorado: First Collateral Trust Bonds: 6% - 6 3/8% series, due January 1, 2001 - November 1, 2005 . . . . . . $ 237,167 $ 134,500 7 1/4% series, due January 1, 2024 . . . . . . . . . . . . . . . . . . 110,000 - First Mortgage Bonds: 4 1/2% - 6 3/4% series, due June 1, 1994 - July 1, 1998 . . . . . . . 95,000 130,000 7 1/4% - 8 1/4% series, due February 1, 2001 - November 1, 2007 . . . 100,000 289,500 8 3/4% - 9 7/8% series, due July 1, 2020 - March 1, 2022 . . . . . . . 225,000 225,000 Pollution Control Series A, 5 7/8%, due March 1, 2004 . . . . . . . . 23,500 24,000 Pollution Control Series F, 7 3/8%, due November 1, 2009 . . . . . . . 27,250 27,250 Pollution Control Series G, 5 5/8% - 7 3/8%, due April 1, 2008 - April 2, 2014 79,500 79,500 Pollution Control Series H, 5 1/2%, due June 1, 2012 . . . . . . . . . 50,000 50,000 Secured Medium-Term Notes, Series A: 6.35% - 9.25%, due January 12, 1995 - October 30, 2002 . . . . . . 149,500 141,500 Unsecured promissory notes: 7 3/4% - 10.35%, due December 1, 1997 - December 1, 1999 . . . . . . . - 21,333 11.60% - 12.875%, due May 1, 2015 - May 1, 2025 . . . . . . . . . . . 15,000 15,000 Unamortized premium . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 157 Unamortized discount . . . . . . . . . . . . . . . . . . . . . . . . . . (5,105) (3,686) Capital lease obligations, 6.68%-14.65%, due in installments through August 31, 1999 17,093 1,112 1,123,948 1,135,166 Cheyenne Light, Fuel and Power Company: First Mortgage Bonds: 7 7/8% series, due April 1, 2003 . . . . . . . . . . . . . . . . . . . 4,000 4,000 7.5% series, due January 1, 2024 . . . . . . . . . . . . . . . . . . . 8,000 - Industrial Development Revenue Bonds, 7.25%, due September 1, 2021 . . 7,000 7,000 10.70% unsecured notes, due September 1, 1995 . . . . . . . . . . . . . . - 8,000 1480 Welton, Inc.: 12.50% secured promissory note, due in installments through March 1, 1998 5,480 6,766 13.25% secured promissory note, due in installments through October 1, 2016 32,083 32,320 Fuel Resources Development Co.: Capital lease obligations, 7.09% due in installments through March 1, 1995 13 303 Natural Fuels Corporation: 12.25% secured note, retired May 23, 1994 . . . . . . . . . . . . . . - 2 Capital lease obligations, 8 1/8% due in installments through August 31, 1997 56 111 1,180,580 1,193,668 Less: maturities due within one year . . . . . . . . . . . . . . . . . . . . 25,153 58,324 $ 1,155,427 $ 1,135,344
60 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Substantially all properties of the Company and its subsidiaries, other than expressly excepted property, are subject to the liens securing the Company's First Mortgage Bonds and First Collateral Trust Bonds or the mortgage bonds and notes of subsidiaries. Additionally, there is a second lien on the Company's electric property securing the Company's First Collateral Trust Bonds. The Company's First Collateral Trust Bonds are additionally secured by an equal amount of First Mortgage Bonds which bear no interest. The aggregate annual maturities and sinking fund requirements during the five years subsequent to December 31, 1994 are (in thousands of dollars):
Year Maturities Sinking Fund Requirements Total 1995 $ 25,153 $ 1,510 $ 26,663 1996 83,047 1,160 84,207 1997 75,176 810 75,986 1998 34,048 560 34,608 1999 28,184 560 28,744
The Company and Cheyenne expect to satisfy substantially all of their sinking fund obligations through the application of property additions. 6. Notes Payable and Commercial Paper Information regarding notes payable and commercial paper for the years ended December 31, 1994 and 1993 is as follows:
1994 1993 (Thousands of Dollars) Notes payable to banks (weighted average interest rates of 6.34% at December 31, 1994 and 3.69% at December 31, 1993) . . . . . . . . . . . . $ 107,850 $ 46,100 Commercial paper (weighted average interest rates of 6.22% at December 31, 1994 and 3.58% at December 31, 1993) . . . . . . . . . . . . 216,950 230,775 $ 324,800 $ 276,875 Maximum amount outstanding at any month-end during the period . . . . . . . . $ 333,865 $ 276,875 Weighted average amount (based on the daily outstanding balance) outstanding for the period (weighted average interest rates of 4.58% for the year ended December 31, 1994 and 3.33% for the year ended December 31, 1993) . . . . $ 273,015 $ 237,526
61 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) 7. Bank Lines of Credit and Compensating Bank Balances Arrangements by the Company and its subsidiaries for committed lines of credit are maintained entirely by fee payments in lieu of compensating balances. Arrangements for uncommitted lines of credit have no fee or compensating balance requirements. On November 22, 1994, the Company, PSCCC and certain subsidiaries extended a credit facility with several banks providing $300 million in committed bank lines of credit. The credit facility, which is used primarily to support the issuance of commercial paper by the Company and PSCCC, alternatively provides for direct borrowings thereunder. Under the current extension, Cheyenne, 1480 Welton, Inc., Fuelco and PSRI are provided access to the credit facility with direct borrowings guaranteed by the Company. The facility expires November 21, 1995. Individual arrangements for uncommitted bank lines of credit totaled $75 million at December 31, 1994. The unused uncommitted bank lines of credit at December 31, 1994 was $9 million. The Company may borrow under uncommitted preapproved lines of credit upon request; however, the banks have no firm commitment to make such loans. 8. Commitments and Contingencies Regulatory Matters Electric and Gas Cost Adjustment Mechanisms The Company's ECA mechanism was revised and a new QFCCA mechanism was implemented on December 1, 1993, along with the base rate changes resulting from the 1993 rate case. Under the revised ECA, fuel used for generation and purchased energy costs from utilities, QFs and IPPFs (excluding all purchased capacity costs) to serve retail customers, are recoverable. Purchased capacity costs are recovered as a component of base rates, except as described below. The ECA rate is revised annually on October 1. Recovered energy costs are compared with actual costs on a monthly basis and differences, including interest, are deferred. Under the QFCCA, all purchased capacity costs from new QF projects, not reflected in base rates, are recoverable similar to the ECA. While the CPUC approved the QFCCA, recovery of such costs may be subject to an earnings test, which has not yet been defined by the CPUC. The OCC has proposed an annual earnings test that may result in a reduction of QFCCA recoveries to the extent the Company's earnings are in excess of its 11% authorized rate of return on regulated common equity. Hearings regarding this matter are scheduled for April 1995. The CPUC held a prehearing conference on May 24, 1994 for the purpose of establishing a schedule for reviewing the justness and reasonableness of GCA and ECA mechanisms used by gas and electric utilities within its jurisdiction resulting in the opening of an 62 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) investigatory docket. Open hearings were held in December 1994. The OCC and the CPUC staff are recommending the elimination of these cost adjustment mechanisms. The Company is in opposition to the elimination of these cost adjustment mechanisms and has filed initial comments, as well as responded to the comments filed by the other parties. On February 6-7, 1995, as part of an open hearing, the CPUC determined that proceeding with a generic ECA rulemaking docket was not appropriate. However, the Company is required to make an individual filing with the CPUC related to its ECA by September 1, 1995 to review whether the ECA should be maintained in its present form, altered or eliminated. Additionally, the CPUC preliminarily determined that the GCA will continue under current practices. The CPUC staff will hold informal roundtable discussions for the purpose of clarifying the review procedures for the GCA. On June 8, 1994, the CPUC approved the recovery of certain "energy efficiency credits" from retail jurisdiction customers through the DSMCA with collection estimated to begin July 1, 1995. At December 31, 1994, the Company has recognized approximately $6.7 million of unbilled revenue related to these credits. On December 1, 1994, the OCC filed an appeal in Denver District Court of the CPUC's decision approving the collection of these credits. If the OCC is successful in its appeal, the Company could be required to reverse these unbilled revenues. Incentive Regulation and Demand Side Management The CPUC has opened a separate docket to investigate issues relating to the adoption and implementation of incentive regulation, which includes the concept of decoupling the Company's earnings from sales, and additional DSM incentives. On February 10, 1994, the parties to this docket filed a unanimous stipulation and settlement agreement with the CPUC. Provisions of the stipulation include, among other things, retaining the cost recovery component of the DSMCA through December 31, 1998, modifying slightly the DSM incentive mechanism for 1994 and 1995 and forming a technical working group to study and analyze various alternative annual revenue reconciliation mechanisms and incentive mechanisms for 1996 through 1998, which would replace existing DSM incentives until another mechanism or regulatory approach is approved by the CPUC. The stipulation agreement, which includes a procedural schedule to review the results of all studies and simulations over the next year, was approved by the CPUC on June 16, 1994. The technical working group will present to the CPUC a detailed analysis demonstrating the effect of the various proposed mechanisms by the end of the first quarter of 1995. 1993 Rate Case On November 26, 1993, the CPUC issued its final written decision regarding the Company's 1993 rate case, lowering the Company's annual base rate revenue requirement by approximately $5.2 million (a $13.1 million electric revenue decrease partially offset by a $7.1 million gas revenue increase and a $0.8 million steam revenue increase) with new rates 63 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) effective December 1, 1993. The OCC has filed in Denver District Court an appeal of the CPUC's decision. The OCC has claimed that the accounting related to a specific income tax issue results in the overcollection of costs from ratepayers. The Company is in opposition to the appeal. The Company believes that the resolution of this appeal will not have a material effect on its financial position or results of operations. On August 1, 1994, the Company filed its Phase II testimony. The Phase II proceedings will address cost allocation issues and specific rate changes for the various customer classes based on the results of the Phase I hearings and decision that became effective December 1, 1993. A final CPUC decision on the Phase II proceedings is expected in late 1995. Environmental Issues Environmental Site Cleanup Under CERCLA, the EPA has identified, and a Phase II environmental assessment has revealed, low level, widespread contamination from hazardous substances at the Barter Metals Company properties located in central Denver. For an estimated 30 years, the Company sold scrap metal and electrical equipment to Barter for reprocessing. The Company, which is one of several PRPs, is involved in the cleanup of this site which began in November 1992 and is expected to be completed during the second quarter of 1995. The total project cost is currently estimated to be approximately $8.5 million. The Company believes it is probable that a significant portion of these cleanup costs will be recovered through claims made against the Company's insurance companies as monetary settlements with certain insurers have been achieved. Lawsuits against certain remaining insurance companies have been filed in the Denver District Court and a trial is scheduled to begin in late February 1995. To the extent such costs are not recovered by insurance or from other PRPs, the Company believes it is probable that such costs will be recovered through the rate regulatory process. PCB presence has been identified in the basement of an historic office building located in downtown Denver. The Company was negotiating the future cleanup with the current owners; however, on October 5, 1993, the owners filed a civil action against the Company in the Denver District Court. The action alleged that the Company was responsible for the PCB releases and additionally claimed other damages in unspecified amounts. On August 8, 1994, the Denver District Court entered a judgment approving a $5.3 million settlement agreement between the Company and the building owners resolving all claims between the Company and the building owners. The Company believes it is probable that it will recover some portion of these costs through insurance claims. To the extent such costs are not recovered by insurance, the Company believes it is probable that such costs will be recovered through the rate regulatory process. The Company is pursuing reoccupation of its former Headquarters 64 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Office Building, which contained asbestos. The asbestos abatement/removal at the site was recently completed at a cost of approximately $8.3 million. The Company plans to further remodel and reoccupy the facility during 1995 and 1996 and expects to recover all such costs through the rate regulatory process. The Elitch Gardens Amusement Park site near downtown Denver has revealed low level, widespread contamination. The Company had used the site in the past as a manufactured gas plant site and is one of three PRPs. An agreement has been signed by Trillium Corporation, a PRP, Elitch Gardens Co. and the Company, releasing the Company from responsibility for the first $2 million of expenses related to contamination. Any contamination expenses incurred during construction or thereafter which exceed $2 million will be the responsibility of the Company; however, the Company could then pursue recovery of the incurred costs from Burlington Northern Railroad, the third PRP, and/or through insurance claims. Contamination expenses to date have not exceeded $2 million. In addition to these sites, the Company has identified several sites where cleanup of hazardous substances may be required. While potential liability and settlement costs are still under investigation and negotiation, the Company believes that the resolution of these matters will not have a material effect on its financial position or results of operations. The Company fully intends to pursue the recovery of all significant costs incurred for such projects through insurance claims and/or the rate regulatory process. To the extent any costs are not recovered through the options listed above, the Company would be required to recognize an expense for such unrecoverable amounts. Other Environmental Matters Under the Clean Air Act Amendments of 1990, coal burning power plants are required to reduce SO 2 and NOx emissions to specified levels through a phased approach. The Company is currently meeting Phase I emission standards placed on SO2 through the use of low sulfur coal and the operation of pollution control equipment on certain generation facilities. The Company will be required to modify certain boilers by the year 2000 to reduce NOx emissions in order to comply with Phase II requirements at an estimated total future cost of approximately $21 million. The Company is studying its options to reduce SO 2 emissions and currently does not anticipate that these regulations will significantly impact its operations. On August 18, 1993, a conservation organization filed a complaint in U.S. District Court for the District of Colorado, pursuant to Section 304 of the Federal Clean Air Act, against the Company and the other joint owners of the Hayden station. The plaintiff alleges that, on certain occasions, the station exceeded opacity limitations during the past several years. The complaint seeks, among other things, civil monetary 65 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) penalties. At this time the Company is not able to estimate the amount, if any, of its potential liability or whether additional particulate control equipment will be required. Discovery has been completed and a trial date has been set for August 1995. The Company believes that, consistent with historical regulatory treatment, any costs to comply with pollution control regulations would be recovered from its customers. However, no assurance can be given that this practice will continue in the future. Purchase requirements Coal purchases and transportation At December 31, 1994, the Company had in place long-term contracts for the purchase of coal through 2017. The minimum remaining quantities to be purchased under these contracts total 92 million tons. The coal purchase prices are subject to periodic adjustment for inflation and market conditions. Total estimated obligations, based on current prices, were approximately $820 million at December 31, 1994. The Company has entered into long-term contracts for the transportation of coal by railroad in Company-owned or leased railcars to existing power plants. These agreements, expiring in 2000, provide for a minimum remaining transport quantity of 27 million tons. Coal transport contract prices are negotiated based on market conditions and are adjusted periodically for inflation and operating factors. Total estimated obligations, based on current prices, were approximately $93 million at December 31, 1994. Natural gas purchases and transportation The Company and Cheyenne have entered into long-term contracts for the purchase, firm transportation and storage of natural gas which expire on various dates through 1998. In compliance with the rules established by FERC Order 636, the Company renegotiated contracts during 1993 with its two primary gas pipeline suppliers and committed to continue purchasing gas for the next three years. The Company will not incur any gas supply realignment costs otherwise applicable under FERC Order 636. At December 31, 1994, the Company and Cheyenne have minimum obligations under such contracts of $222 million in 1995 declining thereafter for a total estimated commitment of $431 million. Purchased power The Company and Cheyenne have entered into agreements with utilities and QFs for purchased power to meet system load and energy requirements, to replace generation from Company-owned units under maintenance and outages, and to meet the Company's operating reserve obligation to the Pool. 66 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) The Company has various pay-for-performance contracts with QFs having expiration dates through the year 2026. In general, these contracts provide for capacity payments, subject to the QFs meeting certain contract obligations, and energy payments based on actual power taken under the contracts. The capacity and energy costs are recovered through base rates, the ECA and the QFCCA. Additionally, the Company and Cheyenne have long-term purchased power contracts with various regional utilities expiring through 2022. In general, these contracts provide for capacity and energy payments which approximate the cost of the sellers. These costs have historically been recoverable through the ECA; however, effective December 1, 1993, the Company's capacity costs were reflected in base rates. Total capacity and energy payments associated with such contracts were $427 million, $366 million and $332 million in 1994, 1993 and 1992, respectively. At December 31, 1994, the estimated future payments for capacity that the Company and Cheyenne are obligated to purchase, subject to availability, are as follows:
Regional QFs Utilities Total (Thousands of Dollars) 1995 . . . . . . . . . . . . . . . . . . . . . $ 142,070 $ 176,936 $ 319,006 1996 . . . . . . . . . . . . . . . . . . . . . 143,499 183,089 326,588 1997 . . . . . . . . . . . . . . . . . . . . . 143,583 184,691 328,274 1998 . . . . . . . . . . . . . . . . . . . . . 143,299 183,383 326,682 1999 . . . . . . . . . . . . . . . . . . . . . 143,275 175,160 318,435 2000 and thereafter . . . . . . . . . . . . . . 1,292,476 2,239,290 3,531,766 Total . . . . . . . . . . . . . . . . . . . . $ 2,008,202 $ 3,142,549 $ 5,150,751
Historically, all minimum coal, coal transportation, natural gas and purchased power requirements have been met. Other purchases Commitments made for the purchase of materials, plant and equipment additions, DSM expenditures and other various items aggregated approximately $405 million at December 31, 1994. Employee Litigation Several employee lawsuits have been filed against the Company involving alleged sexual/age discrimination. In addition, certain employees terminated as part of the Company's 1991/1992 organizational analysis asserted breach of contract and promissory estoppel with respect to job security and breach of the covenant of good faith and fair dealing. A jury recently awarded two of 21 plaintiffs approximately $500,000, which 67 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) the Company has accrued. The Company is considering an appeal of this decision. The remaining 19 claims were dismissed. The Company is actively contesting all outstanding lawsuits and believes the ultimate outcome will not have a material impact on the Company's results of operations or financial position. Leasing program The Company and its subsidiaries maintain operating leases for equipment and facilities used in the normal course of business. The majority of these operating leases are under a leasing program that has initial noncancelable terms of one year, while the remaining operating leases have various terms. These leases may be renewed or replaced. No material restrictions exist in these leasing agreements concerning dividends, additional debt, or further leasing. Rental expense for 1994, 1993 and 1992 was $29.7 million, $28.1 million, and $25.1 million, respectively. At December 31, 1994, estimated future minimum rental payments applicable to noncancelable operating leases were as follows:
(Thousands of Dollars) 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 17,572 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16,521 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,250 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,038 1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,133 2000 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23,029 Total minimum rental payments . . . . . . . . . . . . . . . . . . . . . $ 95,543
The Company has in place a leasing program which includes a provision whereby the Company indemnifies the lessor for all liabilities which might arise from the acquisition, use, or disposition of the leased property. Fort St. Vrain See Note 2 for certain contingencies relating to Fort St. Vrain. 68 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) 9. Jointly-Owned Electric Utility Plants The Company's investment in jointly-owned plants and its ownership percentages as of December 31, 1994 are:
Plant Construction in Accumulated Work in Service Depreciation Progress Ownership % (Thousands of Dollars) Hayden Unit 1 . . . . . . . . . . . . . $ 37,183 $ 29,238 $ 1,151 75.50 Hayden Unit 2 . . . . . . . . . . . . . 57,616 29,489 229 37.40 Hayden Common Facilities . . . . . . . 1,679 1,258 924 53.10 Craig Units 1 & 2 . . . . . . . . . . . 56,874 21,091 312 9.72 Craig Common Facilities Units 1 & 2 . . 7,533 2,779 785 9.72 Craig Common Facilities Units 1,2 & 3 . 8,218 2,956 410 6.47 Transmission Facilities, Including Substations . . . . . . . . . . . . . 72,037 19,575 - 42.0-73.0 $ 241,140 $ 106,386 $ 3,811
These assets include approximately 331 Mw of net dependable generating capacity. The Company is responsible for its proportionate share of operating expenses (reflected in the consolidated statements of income) and construction expenditures. 10. Employee Benefits Pensions The Company and its subsidiaries (excluding Natural Fuels) maintain a noncontributory defined benefit pension plan covering substantially all employees. The net pension expense in 1994, 1993 and 1992 was comprised of:
1994 1993 1992 (Thousands of Dollars) Service cost . . . . . . . . . . . . . . . . . . . . . . . . $ 16,169 $ 15,868 $ 14,788 Interest cost on projected benefit obligation . . . . . . . . . . . . . . . . . . . . . . . . 45,518 38,106 35,695 Actual return on plan assets . . . . . . . . . . . . . . . . 5,844 (52,369) (34,317) Amortization of net transition asset . . . . . . . . . . . . (3,674) (3,674) (3,674) Other items . . . . . . . . . . . . . . . . . . . . . . . . . (56,996) 8,219 (6,317) Net pension expense . . . . . . . . . . . . . . . . . . . $ 6,861 $ 6,150 $ 6,175
69 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) The pension plan was amended in 1994 (as discussed below) requiring the use of two sets of assumptions in the calculation of the 1994 net periodic pension cost. Significant assumptions used in determining net periodic pension cost were:
Jan-Mar Apr-Dec 1994 1994 1993 1992 Discount rate 7.5% 8.0% 8.2% 8.2% Expected long-term increase in compensation level 5.0% 5.0% 5.5% 5.5% Expected weighted average long-term rate of return on assets 10.5% 10.5% 11% 11%
Variances between actual experience and assumptions for costs and returns on assets are amortized over the average remaining service lives of employees in the plan. A comparison of the actuarially computed benefit obligations and plan assets at December 31, 1994 and 1993, is presented in the following table. Plan assets are stated at fair value and are comprised primarily of corporate debt and equity securities, a real estate fund and government securities held either directly or in commingled funds. The Company and its subsidiaries' funding policy is to contribute annually, at a minimum, the amount necessary to satisfy the IRS funding standards.
1994 1993 (Thousands of Dollars) Actuarial present value of benefit obligations: Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $410,117 $392,623 Nonvested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30,136 39,343 440,253 431,966 Effect of projected future salary increases . . . . . . . . . . . . . . . . 87,079 128,294 Projected benefit obligation for service rendered to date . . . . . . . . . 527,332 560,260 Plan assets at fair value . . . . . . . . . . . . . . . . . . . . . . . . . (491,735) (523,548) Projected benefit obligation in excess of plan assets . . . . . . . . . . . (35,597) (36,712) Unrecognized net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . 33,650 58,252 Prior service cost not yet recognized in net periodic pension cost . . . . 32,368 34,673 Unrecognized net transition asset at January 1, 1986, being recognized over 17 years . . . . . . . . . . . . . . . . . . . . (29,390) (33,064) Prepaid pension asset . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,031 $ 23,149
70 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Significant assumptions used in determining the benefit obligations were:
1994 1993 Discount rate 8.75% 7.5% Expected long-term increase in compensation level 5.0% 5.0%
On January 25, 1994, the Board of Directors approved an amendment to the Plan which offered an incentive for early retirement for employees age 55 or older with 20 years of service as well as a Severance Enhancement Program (SEP) option for these same eligible employees for the period February 4, 1994 to April 1, 1994. The Plan amendment generally provided for the following retirement enhancements: a) unreduced early retirement benefits, b) three years of additional credited service and c) a supplement of either a one-time payment equal to $400 for each full year of service to be paid from general corporate funds or a $250 social security supplement each month up to age 62 to be paid by the Plan. The SEP provided for: a) a one-time severance ranging from $20,000 - $90,000, depending on an employee's organization level, b) a continuous years of service bonus (up to 30 years) and c) a cash benefit of $10,000. Approximately 550 employees elected to participate in the early retirement/severance enhancement program, of which approximately 370 employees elected the early retirement benefit. The total cost of the program was approximately $39.7 million. These costs have been deferred and, effective April 1, 1994, are being amortized to expense over approximately 4.5 years in accordance with rate regulatory treatment. This amortization period represents the participants' average remaining years of service to their expected retirement date. During 1993, the Board of Directors of the Company approved amendments that: 1) eliminated the minimum age of 21 for receiving credited service, 2) provided for an automatic increase in monthly payments to a retired plan member in the event the member's spouse or other contingent annuitant dies prior to the member and 3) provided for Average Final Compensation to be based on the highest average of three consecutive years compensation. These plan changes increased the projected benefit obligation by approximately $24.6 million. Involuntary severance program During 1994, in a continuing effort to lower operating costs, the Company implemented an involuntary severance program which reduced management and staff levels by approximately 550 employees. Approximately $10.7 million of involuntary severance costs were accrued, of which $8.7 million served to reduce pre-tax earnings. 71 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Postretirement benefits other than pensions The Company and its subsidiaries provide certain health care and life insurance benefits for retired employees. A significant portion of the employees become eligible for these benefits if they reach either early or normal retirement age while working for the Company or its subsidiaries. Historically, the Company has recorded the cost of these benefits on a pay-as-you-go basis, consistent with the regulatory treatment. Effective January 1, 1993, the Company and its subsidiaries adopted SFAS 106 which requires the accrual, during the years that an employee renders service to the Company, of the expected cost of providing postretirement benefits other than pensions to the employee and the employee's beneficiaries and covered dependents. The Company is transitioning to full accrual accounting for OPEB costs between January 1, 1993 and December 31, 1997, consistent with the accounting requirements for rate regulated enterprises. All OPEB costs deferred during the transition period will be amortized on a straight line basis over the subsequent 15 years. Effective December 1, 1993, the Company began recovering such costs based on the level of expense determined in accordance with the CPUC approach in the Fort St. Vrain Supplemental Settlement Agreement. On January 13, 1995, the CPUC approved the 1994 revision to the Supplemental Settlement Agreement, which accelerated the recovery of OPEB costs as required under SFAS 106 and approved other changes to certain ratemaking principles. The change in recovery was retroactive to January 1, 1994, and accordingly, resulted in an increased OPEB expense. The Company plans to file a FERC rate case in 1995 which will include a request for approval to recover all wholesale jurisdiction SFAS 106 costs. Effective January 1, 1993, Cheyenne began recovering SFAS 106 costs as approved by the WPSC. The Company and Cheyenne intend to fund this plan based on the amounts reflected in cost-of-service, consistent with the rate orders. 72 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The net periodic postretirement benefit cost in 1994 and 1993 under SFAS 106 was comprised of: 1994 1993 (Thousands of Dollars) Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,101 $ 4,943 Interest cost on projected benefit obligation . . . . . . . . . . . . . . . 24,111 20,828 Return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . (938) (164) Amortization of net transition obligation at January 1, 1993, assuming a 20 year amortization period . . . . . . . . . . . . . . . . . 12,710 12,710 Net postretirement benefit cost required by SFAS 106 . . . . . . . . . . . 41,984 38,317 OPEB expense recognized in accordance with current regulation . . . . . . . (30,266) (12,462) Increase in regulatory asset (Note 1) . . . . . . . . . . . . . . . . . . . 11,718 25,855 Regulatory asset at beginning of year . . . . . . . . . . . . . . . . . . . 25,855 - Regulatory asset at end of year . . . . . . . . . . . . . . . . . . . . . . $ 37,573 $ 25,855
Significant assumptions used in determining net periodic postretirement benefit cost were:
Jan-Mar Apr-Dec 1994 1994 1993 Discount rate 7.5% 8.0% 8.2% Expected long-term increase in compensation level 5.0% 5.0% 5.5% Expected return on plan assets 10.5% 10.5% 10.5%
The OPEB expense on a pay-as-you-go basis was $9.1 million for 1992. 73 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) A comparison of the actuarially computed benefit obligations and plan assets at December 31, 1994 and 1993 is presented in the following table. Plan assets are stated at fair value and are comprised primarily of corporate debt and equity securities, a real estate fund, government securities and other short-term investments held either directly or in commingled funds.
1994 1993 (Thousands of Dollars) Accumulated postretirement benefit obligation: Retirees and eligible beneficiaries . . . . . . . . . . . . . . . . . . $ 95,382 $ 86,718 Other fully eligible plan participants . . . . . . . . . . . . . . . . 71,683 95,103 Other active plan participants . . . . . . . . . . . . . . . . . . . . 86,505 98,342 Total 253,570 280,163 Plan assets at fair value . . . . . . . . . . . . . . . . . . . . . . . . . (18,114) (476) Accumulated benefit obligation in excess of plan assets . . . . . . . . . . 235,456 279,687 Unrecognized net gain (loss) . . . . . . . . . . . . . . . . . . . . . . . 35,423 (10,059) Unrecognized transition obligation . . . . . . . . . . . . . . . . . . . . (228,773) (241,483) Accrued postretirement benefit obligation . . . . . . . . . . . . . . . . $ 42,106 $ 28,145
Significant assumptions used in determining the accumulated postretirement benefit obligation were:
1994 1993 Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.75% 7.5% Ultimate health care cost trend rate . . . . . . . . . . . . . . . . . . . 6.0% 5.3% Expected long-term increase in compensation level . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.0% 5.0%
The assumed health care cost trend rate for 1994 is 11.5%, decreasing to 6.0% in 0.5% annual increments. A 1% increase in the assumed health care cost trend will increase the estimated total accumulated benefit obligation by $35.8 million, and the service and interest cost components of net periodic postretirement benefit costs by $4.6 million. Postemployment benefits The Company and its subsidiaries adopted SFAS 112 on January 1, 1994, the effective date of the statement. SFAS 112 establishes the accounting standards for employers who provide benefits to former or inactive employees after employment but before retirement (postemployment benefits). The Company has recorded a $21 million regulatory asset (see 74 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Note 1) and a corresponding liability on the consolidated balance sheet, assuming an 8% discount rate. The Company believes it is probable that it will receive regulatory approvals to recover these costs in future rates. Incentive compensation The Omnibus Incentive Plan provides for annual and long-term incentive awards for officers and management employees. One million shares of common stock have been authorized for awards under the Plan as it allows for the issuance of stock options and/or restricted shares. The stock options are issued at the fair market value of the Company's common stock at the date of issue and vest over a three-year period. Cash and restricted stock awards were made under the Omnibus Incentive Plan for calendar years 1994 and 1993. Additionally, options were granted to eligible employees for these same years. The Employee Incentive Plan provides for cash awards to all employees based on the achievement of corporate goals. Performance goals were met in 1994 and 1993. The expenses accrued under both incentive plans totaled approximately $6.0 million in 1994 and $5.2 million in 1993. 11. Financial Instruments Fair value of financial instruments The following table presents the carrying amounts and fair values of the Company's significant financial instruments at December 31, 1994 and 1993. The carrying amount of all other financial instruments approximates fair value. SFAS 107 defines the fair value of a financial instrument as the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale.
1994 1993 Carrying Fair Carrying Fair Amount Value Amount Value (Thousands of dollars) Investments, at cost . . . . . . . . . . . . $ 7,308 $ 7,283 $ 7,693 $ 7,749 Preferred stock subject to mandatory redemption 45,241 45,518 45,454 46,650 Long-term debt . . . . . . . . . . . . . . . 1,168,480 1,119,391 1,195,669 1,255,768
The fair value of the debt and equity securities included in Investments, at cost is estimated based on quoted market prices for the same or similar investments and are classified as held-to-maturity. The unrealized holding gains and losses for these debt and equity securities are not significant. 75 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) The estimated fair values of preferred stock subject to mandatory redemption and long-term debt are based on quoted market prices of the same or similar instruments. Since the Company and Cheyenne are subject to regulation, any gains or losses related to the difference between the carrying amount and the fair value of these financial instruments would not be realized by the Company's shareholders. Off-balance-sheet financial instrument In accordance with NRC decommissioning funding requirements for nuclear power reactors, the Company has obtained a $66 million irrevocable letter of credit which bears a market interest rate. The NRC is the beneficiary of this letter of credit. At December 31, 1994 and 1993, no amounts were outstanding under this letter of credit. In general, such letter of credit may be exercised by the NRC in the event the Company is in default of its performance obligations under the decommissioning plan. Concentration of credit risk - accounts receivable No individual customer or group of customers engaged in similar activities represents a material concentration of credit risk to the Company and its subsidiaries. 12. Income Tax Expense The provisions for income tax for the years ended December 31, 1994, 1993 and 1992 consist of the following:
1994 1993 1992 (Thousands of Dollars) Current income taxes: Federal . . . . . . . . . . . . . . . . . . . . . . . . . $ 22,081 $ 34,684 $ 34,265 State . . . . . . . . . . . . . . . . . . . . . . . . . . (2,016) (2,208) 1,513 Total current income taxes . . . . . . . . . . . . . . 20,065 32,476 35,778 Deferred income taxes . . . . . . . . . . . . . . . . . . . . 34,234 33,435 22,509 Investment tax credits - net . . . . . . . . . . . . . . . . (5,799) (4,917) (5,138) Total provision for income taxes . . . . . . . . . . . . . . $ 48,500 $ 60,994 $ 53,149
During 1994, as a result of a detailed analysis of the income tax accounts, the Company recorded a decrease in its income tax liabilities, which served to reduce Federal and state income tax expenses by approximately $21.3 million, or 34 cents per share. The detailed analysis was completed in conjunction with the Company's implementation of the full 76 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) normalization method of accounting for income taxes as provided for in a recent rate order from the CPUC. A reconciliation of the statutory U.S. income tax rates to the effective tax rates is as follows:
1994 1993 1992 (Thousand of Dollars) Tax computed at U.S. statutory rate on pre-tax accounting income . . . . . . $76,569 35.0% $76,424 35.0% $64,522 34.0% Increase (decrease) in tax from: Allowance for funds used during construction . . . . . . . . . (2,449) (1.1) (4,369) (2.0) (3,827) (2.0) Amortization of investment tax credits (5,792) (2.6) (4,889) (2.2) (5,128) (2.7) Cash surrender value of life insurance policies . . . . . . . . . (7,643) (3.5) (6,386) (2.9) (4,620) (2.4) Capitalized software, net of amortization - - (4,820) (2.2) (7,115) (3.7) Capitalized overheads . . . . . . . . . - - 7,170 3.3 7,112 3.7 Lease amortization . . . . . . . . . . - - 3,692 1.7 3,407 1.8 Amortization of prior flow-through amounts 10,509 4.8 934 0.4 - - Adoption of SFAS 109 . . . . . . . . . - - (1,911) (0.9) - - Tax accrual adjustment . . . . . . . . (21,262) (9.7) - - - - Other-net . . . . . . . . . . . . . . . (1,432) (0.7) (4,851) (2.2) (1,202) (0.7) Total income taxes . . . . . . . . . . $48,500 22.2% $60,994 28.0% $53,149 28.0%
The Company and its subsidiaries adopted SFAS 109 on January 1, 1993. The impact of adoption was not material to the consolidated results of operations and, therefore, has not been reflected as the cumulative effect of a change in accounting principle. The Company and its regulated subsidiaries have historically provided for deferred income taxes to the extent allowed by their regulatory agencies whereby deferred taxes were not provided on all differences between financial statement and taxable income (the flow- through method). To give effect to temporary differences for which deferred taxes were not previously required to be provided, a regulatory asset was recognized. The regulatory asset represents temporary differences primarily associated with prior flow-through amounts and the equity component of allowance for funds used during construction, net of temporary differences related to unamortized investment tax credits and excess deferred income taxes that have resulted from historical reductions in tax rates (see Note 1). During 1993, the Federal statutory income tax rate was raised from 34% to 35%, retroactive to January 1, 1993. The impact of this tax rate change on the Company was to increase the net deferred income tax liability by $16.8 million, of which $16.7 million increased the regulatory asset related to income taxes. 77 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Effective December 1, 1993, pursuant to a CPUC order, the Company adopted full income tax normalization for rate regulatory purposes with the regulatory tax asset being recovered over a thirteen year period. Effective January 1, 1993, Cheyenne began recovering SFAS 109 costs as approved by the WPSC. The tax effects of significant temporary differences representing deferred tax liabilities and assets as of December 31, 1994 and 1993 are as follows:
1994 1993 (Thousands of Dollars) Deferred income tax liabilities: Accelerated depreciation and amortization . . . . . . . . . $332,222 $313,275 Plant basis differences (prior flow-through) . . . . . . . 188,194 168,131 Allowance for equity funds used during construction . . . . 49,824 51,500 Pensions . . . . . . . . . . . . . . . . . . . . . . . . . 35,975 31,689 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,792 28,398 Total . . . . . . . . . . . . . . . . . . . . . . . . . . 648,007 592,993 Deferred income tax assets: Investment tax credits . . . . . . . . . . . . . . . . . . 73,270 76,841 Contributions in aid of construction . . . . . . . . . . . 47,832 33,063 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 61,946 41,760 Total . . . . . . . . . . . . . . . . . . . . . . . . . . 183,048 151,664 Net deferred income tax liability . . . . . . . . . . . . . . $464,959 $441,329
As of December 31, 1994 the Company has cumulative AMT carryforwards of approximately $12.7 million. A valuation allowance has not been recorded as the Company expects that all deferred income tax assets will be realized in the future. 78 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) 13. Segments of Business Segment information for the year ended December 31, 1994 is as follows:
Electric(1) Gas Other Total (Thousands of Dollars) Operating revenues . . . . . . . . . . . . . . . $ 1,399,836 $ 624,922 $ 32,626 $ 2,057,384 Operating expenses, excluding depreciation and income taxes . . . . . . . . . . . . . . . 1,032,396 558,929 7,732 1,599,057 Depreciation and amortization . . . . . . . . . . 107,769 29,078 2,188 139,035 Total operating expenses* . . . . . . . . . . . 1,140,165 588,007 9,920 1,738,092 Operating income* . . . . . . . . . . . . . . . . $ 259,671 $ 36,915 $ 22,706 $ 319,292 Plant construction expenditures** . . . . . . . . $ 223,773 $ 91,492 $ 1,873 $ 317,138 Identifiable assets, December 31, 1994: Property, plant and equipment** . . . . . . . . $ 2,543,267 $ 674,974 $ 73,161 $ 3,291,402 Materials and supplies . . . . . . . . . . . . $ 55,756 $ 11,782 $ 62 67,600 Fuel inventory . . . . . . . . . . . . . . . . $ 31,225 $ -- $ 145 31,370 Gas in underground storage(2) . . . . . . . . . $ -- $ 42,355 $ -- 42,355 Other corporate assets . . . . . . . . . . . . 775,105 $ 4,207,832
Segment information for the year ended December 31, 1993 is as follows:
Electric Gas Other Total (Thousands of Dollars) Operating revenues . . . . . . . . . . . . . . . $ 1,337,053 $ 628,324 $ 33,308 $ 1,998,685 Operating expenses, excluding depreciation and income taxes . . . . . . . . . . . . . . . 953,049 560,593 2,312 1,515,954 Depreciation and amortization . . . . . . . . . . 109,958 28,305 2,541 140,804 Total operating expenses* . . . . . . . . . . . 1,063,007 588,898 4,853 1,656,758 Operating income* . . . . . . . . . . . . . . . . $ 274,046 $ 39,426 $ 28,455 $ 341,927 Plant construction expenditures** . . . . . . . . $ 205,153 $ 86,867 $ 1,495 $ 293,515 79 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Identifiable assets, December 31, 1993: Property, plant and equipment** . . . . . . . . $ 2,413,585 $ 695,456 $ 84,100 $ 3,193,141 Materials and supplies . . . . . . . . . . . . $ 64,674 $ 12,993 $ 65 77,732 Fuel inventory . . . . . . . . . . . . . . . . $ 35,337 $ -- $ 147 35,484 Gas in underground storage(2) . . . . . . . . . $ -- $ 41,130 $ -- 41,130 Other corporate assets . . . . . . . . . . . . 710,113 $ 4,057,600 (1) Includes additional expense of approximately $43.4 million for defueling and decommissioning. (2) Additional gas storage was purchased as part of the Company's implementation strategy associated with FERC Order 636. * Before income taxes. ** Includes allocation of common utility property.
80 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Segment information for the year ended December 31, 1992 is as follows:
Electric Gas(3) Other(4) Total (Thousands of Dollars) Operating revenues . . . . . . . . . . . . . . . $ 1,260,769 $ 568,886 $ 32,618 $ 1,862,273 Operating expenses, excluding depreciation and income taxes . . . . . . . . . . . . . . . 886,215 529,225 16,740 1,432,180 Depreciation and amortization . . . . . . . . . . 97,274 27,621 2,422 127,317 Total operating expenses* . . . . . . . . . . . 983,489 556,846 19,162 1,559,497 Operating income* . . . . . . . . . . . . . . . . $ 277,280 $ 12,040 $ 13,456 $ 302,776 Plant construction expenditures** . . . . . . . . $ 185,170 $ 73,685 $ 2,811 $ 261,666 Identifiable assets, December 31, 1992: Property, plant and equipment** . . . . . . . . $ 2,331,116 $ 653,898 $ 92,495 $ 3,077,509 Materials and supplies . . . . . . . . . . . . $ 67,618 $ 13,302 $ 82 81,002 Fuel inventory . . . . . . . . . . . . . . . . $ 33,384 $ -- $ 189 33,573 Gas in underground storage . . . . . . . . . . $ -- $ 14,393 $ -- 14,393 Other corporate assets . . . . . . . . . . . . 553,106 $ 3,759,583 (3) Includes additional expense of approximately $26.9 million associated with the termination of the Synhytech project. (4) Includes additional expense of approximately $11.4 million associated with the loss on sale of BCC real estate properties. * Before income taxes. ** Includes allocation of common utility property.
81 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Concluded) 14. Quarterly Financial Data (Unaudited) The following summarized quarterly information for 1994 and 1993 is unaudited, but includes all adjustments (consisting only of normal recurring accruals) which the Company considers necessary for a fair presentation of the results for the periods. Information for any one quarterly period is not necessarily indicative of the results which may be expected for a twelve month period due to seasonal and other factors.
1994 Three months ended March 31 June 30 September 30 December 31 (In Thousands-except per share data) Operating revenues . . . . . . . . . . . . . . . $ 612,436 $ 477,563 $ 431,954 $ 535,431 Operating income . . . . . . . . . . . . . . . . $ 78,430 $ 58,027 $ 47,601 $ 86,734 Net income . . . . . . . . . . . . . . . . . . . $ 46,529 $ 23,875 $ 49,054 $ 50,811 Earnings available for common stock . . . . . . . $ 43,524 $ 20,870 $ 46,051 $ 47,810 Weighted average common shares outstanding . . . 60,919 61,425 61,779 62,064 Earnings per weighted average common share . . . $0.71 $0.34 $0.75 $0.77
1993 Three months ended March 31 June 30 September 30 December 31 (In Thousands-except per share data) Operating revenues . . . . . . . . . . . . . . . $ 607,389 $ 448,001 $ 422,353 $ 520,942 Operating income . . . . . . . . . . . . . . . . $ 88,014 $ 49,681 $ 56,575 $ 86,663 Net income . . . . . . . . . . . . . . . . . . . $ 58,687 $ 20,435 $ 25,527 $ 52,711 Earnings available for common stock . . . . . . . $ 55,678 $ 17,426 $ 22,519 $ 49,706 Weighted average common shares outstanding . . . 58,997 59,535 59,925 60,324 Earnings per weighted average common share . . . $0.94 $0.29 $0.38 $0.82
82
SCHEDULE II PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Years Ended December 31, 1994, 1993 and 1992 Additions Balance at Charged Charged to Deductions Balance beginning to other from at end of period income accounts(1) reserves(2) of year (Thousands of Dollars) Reserve deducted from related assets: Provision for uncollectible accounts: 1994 . . . . . . . . . . . . . . . . $ 3,276 $ 8,533 $ 132 $ 8,768 $ 3,173 1993 . . . . . . . . . . . . . . . . $ 3,388 $ 6,878 $ 13 $ 7,003 $ 3,276 1992 . . . . . . . . . . . . . . . . $ 4,741 $ 5,483 $ 1,511 $ 8,347 $ 3,388 --------------------------------------- (1) Bad debts recovered, transfers from customers' deposit, etc. (2) Bad debt written off.
83
EXHIBIT 12(a) PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES COMPUTATION OF RATIO OF CONSOLIDATED EARNINGS TO CONSOLIDATED FIXED CHARGES (not covered by Report of Independent Public Accountants) Year Ended December 31, 1994 1993 1992 1991 1990 (Thousands of Dollars, except ratios) Fixed charges: Interest on long-term debt . . . . . . . . . $ 89,005 $ 98,089 $ 92,581 $81,666 $75,075 Interest on borrowings against COLI contracts 29,786 25,333 18,312 8,144 7,771 Other interest . . . . . . . . . . . . . . . 14,235 9,445 12,357 14,574 16,178 Amortization of debt discount and expense less premium . . . . . . . . . . . . . . . . 3,126 2,018 1,790 1,827 1,543 Interest component of rental expense . . . . 6,888 6,824 7,904 6,892 5,806 Total . . . . . . . . . . . . . . . . . . $143,040 $141,709 $132,944 $113,103 $106,373 Earnings (before fixed charges and taxes on income): Net income . . . . . . . . . . . . . . . . . $170,269 $157,360 $136,623 $149,693 $146,144 Fixed charges as above . . . . . . . . . . . 143,040 141,709 132,944 113,103 106,373 Provisions for Federal and state taxes on income, net of investment tax credit amortization . 48,500 60,994 53,149 69,288 73,978 Total . . . . . . . . . . . . . . . . . . $361,809 $360,063 $322,716 $332,084 $326,495 Ratio of earnings to fixed charges . . . . . . . 2.53 2.54 2.43 2.94 3.07
84
EXHIBIT 12(b) PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES COMPUTATION OF RATIO OF CONSOLIDATED EARNINGS TO CONSOLIDATED COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS (not covered by Report of Independent Public Accountants) Year Ended December 31, 1994 1993 1992 1991 1990 (Thousands of Dollars, except ratios) Fixed charges and preferred stock dividends: Interest on long-term debt . . . . . . . . . $ 89,005 $ 98,089 $ 92,581 $ 81,666 $ 75,075 Interest on borrowings against COLI contracts 29,786 25,333 18,312 8,144 7,771 Other interest . . . . . . . . . . . . . . . 14,235 9,445 12,357 14,574 16,178 Amortization of debt discount and expense less premium 3,126 2,018 1,790 1,827 1,543 Interest component of rental expense . . . . 6,888 6,824 7,904 6,892 5,806 Preferred stock dividend requirement . . . . 12,014 12,031 12,077 12,234 12,439 Additional preferred stock dividend requirement 3,422 4,662 4,699 5,662 6,297 Total . . . . . . . . . . . . . . . . . . $158,476 $158,402 $149,720 $130,999 $125,109 Earnings (before fixed charges and taxes on income): Net income . . . . . . . . . . . . . . . . . $170,269 $157,360 $136,623 $149,693 $146,144 Interest on long-term debt . . . . . . . . . 89,005 98,089 92,581 81,666 75,075 Interest on borrowings against COLI contracts 29,786 25,333 18,312 8,144 7,771 Other interest . . . . . . . . . . . . . . . 14,235 9,445 12,357 14,574 16,178 Amortization of debt discount and expense less premium 3,126 2,018 1,790 1,827 1,543 Interest component of rental expense . . . . 6,888 6,824 7,904 6,892 5,806 Provisions for Federal and state taxes on income, net of investment tax credit amortization . 48,500 60,994 53,149 69,288 73,978 Total . . . . . . . . . . . . . . . . . . $361,809 $360,063 $322,716 $332,084 $326,495 Ratio of earnings to fixed charges and preferred stock dividends . . . . . . . . . 2.28 2.27 2.16 2.54 2.61
85 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Does not apply. PART III Item 10. Directors and Executive Officers of the Registrant Information concerning the directors of the registrant is contained under ELECTION OF DIRECTORS in the registrant's 1995 Proxy Statement, which information is incorporated herein by reference. Executive Officers (at December 31, 1994 except as noted):
Executive Officers Initial Effective Date D. D. Hock, Age 59 Chairman of the Board . . . . . . . . . . . . . . . . . . . . . . . . . . . . . February 28, 1989 and Chief Executive Officer . . . . . . . . . . . . . . . . . . . . . . . . . . October 1, 1988 Chairman of the Board, Cheyenne Light, Fuel and Power Company . . . . . . . . . September 21, 1988 Chairman of the Board, Fuel Resources Development Co. . . . . . . . . . . . . . March 22, 1989 President, Fuel Resources Development Co. . . . . . . . . . . . . . . . . . . . May 12, 1993 Chairman of the Board, 1480 Welton, Inc. . . . . . . . . . . . . . . . . . . . . September 26, 1988 President, 1480 Welton, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . March 22, 1990 Chairman of the Board and President, PSR Investments, Inc. . . . . . . . . . . . March 22, 1990 Chairman of the Board and President, PS Colorado Credit Corporation . . . . . . March 22, 1990 Chairman of the Board and President, Green and Clear Lakes Company . . . . . . . December 6, 1988 Chairman of the Board, WestGas Interstate, Inc. . . . . . . . . . . . . . . . . April 22, 1993 President, WestGas Interstate, Inc. . . . . . . . . . . . . . . . . . . . . . . June 4, 1993 Chairman of the Board, WestGas TransColorado, Inc. . . . . . . . . . . . . . . . April 22, 1993 President, WestGas TransColorado, Inc. . . . . . . . . . . . . . . . . . . . . . June 4, 1993 Chairman of the Board, Natural Fuels Corporation . . . . . . . . . . . . . . . . June 11, 1993 President, Natural Fuels Corporation . . . . . . . . . . . . . . . . . . . . . . November 5, 1993 Chairman of the Board, e prime . . . . . . . . . . . . . . . . . . . . . . . . . January 30, 1995 Company Service: September, 1962 Wayne H. Brunetti, Age 52 President and Chief Operating Officer . . . . . . . . . . . . . . . . . . . . . June 28, 1994 President, e prime . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . January 30, 1995 Company Service: June, 1994 Richard C. Kelly, Age 48 Senior Vice President, Finance, Treasurer . . . . . . . . . . . . . . . . . . . June 28, 1994 and Chief Financial Officer . . . . . . . . . . . . . . . . . . . . . . . . . January 23,1990 Vice President, Fuel Resources Development Co. . . . . . . . . . . . . . . . . . April 26, 1990 Treasurer, Fuel Resources Development Co . . . . . . . . . . . . . . . . . . . . August 5, 1994 Vice President, PSR Investments, Inc. . . . . . . . . . . . . . . . . . . . . . September 22, 1986 Vice President, PS Colorado Credit Corporation . . . . . . . . . . . . . . . . . March 30, 1987 86 Treasurer, Cheyenne Light, Fuel and Power Company . . . . . . . . . . . . . . . July 15, 1994 Treasurer, 1480 Welton, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . July 15, 1994 Treasurer, Green and Clear Lakes Company . . . . . . . . . . . . . . . . . . . . July 15, 1994 Treasurer, WestGas Interstate, Inc. . . . . . . . . . . . . . . . . . . . . . . July 15, 1994 Treasurer, WestGas TransColorado, Inc . . . . . . . . . . . . . . . . . . . . . July 15, 1994 Chairman and Chief Executive Officer, Service Telecommunications Co. . . . . . . February 8, 1991 Vice President and Treasurer, e prime. . . . . . . . . . . . . . . . . . . . . . January 30, 1995 Company Service: May, 1968 Patricia T. Smith, Age 47 Senior Vice President and General Counsel . . . . . . . . . . . . . . . . . . . December 5, 1994 Company Service: December, 1994 W. Wayne Brown, Age 44 Controller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . November 24, 1987 Corporate Secretary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . November 23, 1993 Secretary, Cheyenne Light, Fuel and Power Company . . . . . . . . . . . . . . . December 15, 1993 Secretary, 1480 Welton, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . December 16, 1993 Secretary, PSR Investments, Inc. . . . . . . . . . . . . . . . . . . . . . . . December 16, 1993 Secretary, PS Colorado Credit Corporation . . . . . . . . . . . . . . . . . . . December 16, 1993 Secretary, Green and Clear Lakes Company . . . . . . . . . . . . . . . . . . . . December 7, 1993 Secretary and Treasurer, Service Telecommunications Co. . . . . . . . . . . . . February 8, 1991 Secretary, Fuel Resources Development Co. . . . . . . . . . . . . . . . . . . . January 27, 1994 Secretary, WestGas Interstate, Inc. . . . . . . . . . . . . . . . . . . . . . . May 2, 1994 Secretary, WestGas TransColorado, Inc. . . . . . . . . . . . . . . . . . . . . . May 2, 1994 Secretary, e prime. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . January 30, 1995 Company Service: June, 1972 A. Clegg Crawford, Age 62 Vice President, Engineering and Operations Support . . . . . . . . . . . . . . . June 28, 1994 Company Service: May, 1989 Ross C. King, Age 53 Vice President, Gas and Electric Distribution . . . . . . . . . . . . . . . . . June 28, 1994 President, Cheyenne Light, Fuel and Power Company . . . . . . . . . . . . . . . July 15, 1994 Company Service: February, 1966 Earl E. McLaughlin, Jr., Age 54 Vice President, Retail Energy Services . . . . . . . . . . . . . . . . . . . . . June 28, 1994 Vice President, Cheyenne Light, Fuel and Power Company . . . . . . . . . . . . . March 24, 1994 Company Service: August, 1960 Ralph Sargent III, Age 45 Vice President, Production and System Operations . . . . . . . . . . . . . . . . June 28, 1994 Company Service: July, 1978 Philip D. Shaffer, Age 49 Vice President, Wholesale Energy Services . . . . . . . . . . . . . . . . . . . June 28, 1994 Company Service: February, 1966 Marilyn E. Taylor, Age 52 87 Vice President, Human Resources . . . . . . . . . . . . . . . . . . . . . . . . June 28, 1994 Company Service: December, 1987
Each of the above executive officers, except Mr. Brunetti and Ms. Smith, has been employed by the Company and/or its subsidiaries for more than five years in executive or management positions. Prior to election to the positions shown above and since January 1, 1990: Mr. Hock has been Chief Operating Officer and President; Mr. Brunetti has been President and Chief Executive Officer of Management Systems International from June 1991 through July 1994 and Executive Vice President of Florida Power & Light Company from 1987 through May 1991; Mr. Kelly has been Vice President, Financial Services, Principal Accounting Officer and Senior Vice President, Finance and Administration; Ms. Smith has been Vice President and General Counsel for South Carolina Electric and Gas Company from May 1992 through December 1994 and Vice President, Regulatory Affairs and Purchasing from 1988 through May 1992; Mr. Crawford has been Vice President, Nuclear Operations and Vice President, Electric Production; Mr. King has been Manager, Denver Metro Region; Vice President, Regional Customer Operations and Vice President, Metropolitan Customer Operations; Mr. McLaughlin has been Vice President, Marketing, Customer Services and Support Services; Mr. Sargent has been Executive Assistant to Chairman, President and Chief Executive Officer and Vice President, Finance, Planning and Communication and Treasurer; Mr. Shaffer has been President, Cheyenne Light, Fuel and Power Company and Vice President, Division Customer Operations; Ms. Taylor has been Vice President, Human Resources and Vice President Administrative Services. There are no family relationships between executive officers or directors of the Company. There are no arrangements or understandings between the executive officers individually and any other person with reference to their being selected as officers. All executive officers are elected annually by the Board of Directors. Item 11. Executive Compensation Information concerning executive compensation is contained under COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS in the registrant's 1995 Proxy Statement, which information is incorporated herein by reference. 88 Item 12. Security Ownership of Certain Beneficial Owners and Management Information concerning the security ownership of the directors and officers of the registrant is contained under ELECTION OF DIRECTORS in the registrant's 1995 Proxy Statement, which information is incorporated herein by reference. Item 13. Certain Relationships and Related Transactions Information concerning relationships and related transactions of the directors and officers of the registrant is contained under CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS in the registrant's 1995 Proxy Statement, which information is incorporated herein by reference. PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) Financial Statements, Financial Statement Schedules, and Exhibits. Page 1. Financial Statements: Report of Independent Public Accountants . . . . . . . . . . . . . . 32 Consolidated Balance Sheets, December 31, 1994 and 1993 . . . . . . 33 Consolidated Statements of Income for each of the three years in the period ended December 31, 1994 . . . . . . . . . 35 Consolidated Statements of Shareholders' Equity for each of the three years in the period ended December 31, 1994 . . . 36 Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 1994 . . . . . . . . . 37 Notes to Consolidated Financial Statements . . . . . . . . . . . . . 38 2. Financial Statement Schedules: II Valuation and Qualifying Accounts and Reserves (Consolidated) for each of the three years in the period ended December 31, 1994 . . . . . . . . . . . . . . . . . . . 66 All other schedules have been omitted since the required information is not present or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or the notes thereto. 89 Financial statements of several unconsolidated majority-owned subsidiaries are omitted since such subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary. 3. Exhibits: Exhibits are listed in the Exhibit Index . . . . . . . . . . . . . 77 The Exhibits include the management contracts and compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601 (10) (iii) of Regulation S-K. (b) Reports on Form 8-K: A report on Form 8-K, dated October 25, 1994, was filed on October 27, 1994. The items reported were Item 5. Other Events - Fort St. Vrain and Income Taxes and Item 7. Financial Statements and Exhibits, which presented information regarding third quarter earnings. 90 EXPERTS The consolidated balance sheets of the Company and its subsidiaries as of December 31, 1994 and 1993, the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1994, and the related financial statement schedule, appearing in this Annual Report on Form 10-K, have been audited by Arthur Andersen LLP, independent public accountants, and the selected financial data for each of the five years in the period ended December 31, 1994, appearing in Item 6 of this Annual Report on Form 10-K, other than the ratios and percentages therein, have been derived from the consolidated financial statements audited by Arthur Andersen LLP, as set forth in their report appearing elsewhere herein. Reference is made to said report which includes an explanatory paragraph that describes uncertainties discussed in Note 2 to the consolidated financial statements relating to the Company's Fort St. Vrain Nuclear Generating Station. The consolidated financial statements, the related financial statement schedule and the selected financial data appearing in Item 6 other than the ratios and percentages therein, which are included in this Annual Report on Form 10-K, are included herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said reports. 91 EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our report included in this Form 10-K, into the Company's previously filed Registration Statement (Form S-3, File No. 33-42442) pertaining to the Automatic Dividend Reinvestment and Common Stock Purchase Plan; the Company's Registration Statement (Form S-3, File No. 33-37431), as amended on December 4, 1990, pertaining to the shelf registration of the Company's First Mortgage Bonds; the Company's Registration Statement (Form S-8, File No. 33-55432) pertaining to the Omnibus Incentive Plan; the Company's Registration Statement (Form S-3, File No. 33-51167) pertaining to the shelf registration of the Company's First Collateral Trust Bonds and the Company's Registration Statement (Form S-3, File No. 33-54877) pertaining to the shelf registration of the Company's First Collateral Trust Bonds and Cumulative Preferred Stock and to all references to our Firm included in this Form 10-K. ARTHUR ANDERSEN LLP Denver, Colorado February 27, 1995 EXHIBIT 24 POWER OF ATTORNEY Each director and/or officer of Public Service Company of Colorado whose signature appears herein hereby appoints D. D. Hock and R. C. Kelly, and each of them severally, as his or her attorney-in-fact to sign in his or her name and behalf, in any and all capacities stated herein, and to file with the Securities and Exchange Commission, any and all amendments to this Annual Report on Form 10-K. 92 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Public Service Company of Colorado has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 28th day of February, 1995. PUBLIC SERVICE COMPANY OF COLORADO By /s/R.C. Kelly _________________________________ R. C. KELLY Senior Vice President, Finance, Treasurer and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Public Service Company of Colorado and in the capacities and on the date indicated.
Signature Title Date _________________________________________________________________________________________ /s/D. D. Hock __________________________________ Principal Executive D. D. Hock Officer and Director Chairman of the Board and Chief Executive Officer /s/R. C. Kelly __________________________________ Principal Financial Officer February 28, 1995 R. C. Kelly Senior Vice President, Finance, Treasurer and Chief Financial Officer /s/W. Wayne Brown __________________________________ Principal Accounting Officer W. Wayne Brown Controller and Corporate Secretary
93
Signature Title Date _________________________________________________________________________________________ /s/Wayne H. Brunetti __________________________________ Wayne H. Brunetti /s/Collis P. Chandler Jr. __________________________________ Collis P. Chandler, Jr. /s/Doris M. Drury __________________________________ Doris M. Drury /s/Thomas T. Farley __________________________________ Thomas T. Farley /s/Gayle L. Greer __________________________________ Gayle L. Greer __________________________________ A. Barry Hirschfeld /s/George B. McKinley __________________________________ George B. McKinley Director February 28, 1995 __________________________________ Will F. Nicholson, Jr. /s/J. Michael Powers __________________________________ J. Michael Powers /s/Thomas E. Rodriguez __________________________________ Thomas E. Rodriguez __________________________________ Rodney E. Slifer 94 /s/W. Thomas Stephens __________________________________ W. Thomas Stephens /s/Robert G. Tointon __________________________________ Robert G. Tointon
95 EXHIBIT INDEX 3(a)* Restated Articles of Incorporation of the Registrant dated July 9, 1990 (10-K, 1990 - Exhibit 3(a)). 3(b)* By-laws dated November 30, 1992 (10-K, 1993 - Exhibit 3(b)). 4(a)(1)* Indenture, dated as of December 1, 1939, providing for the issuance of First Mortgage Bonds (Form 10 for 1946 Exhibit (B-1)). 4(a)(2)* Indentures supplemental to Indenture dated as of December 1, 1939:
Previous Filing: Previous Filing: Form; Date or Exhibit Form; Date or Exhibit Dated as of File No. No. Dated as of File No. No. Mar. 14, 1941 10, 1946 B-2 July 1, 1968 8-K, July 1968 2 May 14, 1941 10, 1946 B-3 Apr. 25, 1969 8-K, Apr. 1969 1 Apr. 28, 1942 10, 1946 B-4 Apr. 21, 1970 8-K, Apr. 1970 1 Apr. 14, 1943 10, 1946 B-5 Sept. 1, 1970 8-K, Sept. 1970 2 Apr. 27, 1944 10, 1946 B-6 Feb. 1, 1971 8-K, Feb. 1971 2 Apr. 18, 1945 10, 1946 B-7 Aug. 1, 1972 8-K, Aug. 1972 2 Apr. 23, 1946 10-K, 1946 B-8 June 1, 1973 8-K, June 1973 1 Apr. 9, 1947 10-K, 1946 B-9 Mar. 1, 1974 8-K, Apr. 1974 2 June 1, 1947 S-1, (2-7075) 7(b) Dec. 1, 1974 8-K, Dec. 1974 1 Apr. 1, 1948 S-1, (2-7671) 7(b)(1) Oct. 1, 1975 S-7, (2-60082) 2(b)(3) May 20, 1948 S-1, (2-7671) 7(b)(2) Apr. 28, 1976 S-7, (2-60082) 2(b)(4) Oct. 1, 1948 10-K, 1948 4 Apr. 28, 1977 S-7, (2-60082) 2(b)(5) Apr. 20, 1949 10-K, 1949 1 Nov. 1, 1977 S-7, (2-62415) 2(b)(3) Apr. 24, 1950 8-K, Apr. 1950 1 Apr. 28, 1978 S-7, (2-62415) 2(b)(4) Apr. 18, 1951 8-K, Apr. 1951 1 Oct. 1, 1978 10-K, 1978 D(1) Oct. 1, 1951 8-K, Nov. 1951 1 Oct. 1, 1979 S-7, (2-66484) 2(b)(3) Apr. 21, 1952 8-K, Apr. 1952 1 Mar. 1, 1980 10-K, 1980 4(c) Dec. 1, 1952 S-9, (2-11120) 2(b)(9) Apr. 28, 1981 S-16, (2-74923) 4(c) Apr. 15, 1953 8-K, Apr. 1953 2 Nov. 1, 1981 S-16, (2-74923) 4(d) Apr. 19, 1954 8-K, Apr. 1954 1 Dec. 1, 1981 10-K, 1981 4(c) Oct. 1, 1954 8-K, Oct. 1954 1 Apr. 29, 1982 10-K, 1982 4(c) Apr. 18, 1955 8-K, Apr. 1955 1 May 1, 1983 10-K, 1983 4(c) Apr. 24, 1956 10-K, 1956 1 Apr. 30, 1984 S-3, (2-95814) 4(c) May 1, 1957 S-9, (2-13260) 2(b)(15) Mar. 1, 1985 10-K, 1985 4(c) Apr. 10, 1958 8-K, Apr. 1958 1 Nov. 1, 1986 10-K, 1986 4(c) May 1, 1959 8-K, May 1959 2 May 1, 1987 10-K, 1987 4(c) Apr. 18, 1960 8-K, Apr. 1960 1 July 1, 1990 S-3, (33-37431) 4(c) Apr. 19, 1961 8-K, Apr. 1961 1 Dec. 1, 1990 10-K, 1990 4(c) Oct. 1, 1961 8-K, Oct. 1961 2 Mar. 1, 1992 10-K, 1992 4(d) Mar. 1, 1962 8-K, Mar. 1962 3(a) Apr. 1, 1993 10-Q, June 30, 1993 4(a) June 1, 1964 8-K, June 1964 1 June 1, 1993 10-Q, June 30, 1993 4(b) 96 May 1, 1966 8-K, May 1966 2 November 1, 1993 S-3, (33-51167) 4(a)(3) July 1, 1967 8-K, July 1967 2 January 1, 1994 10-K, 1993 4(a)(3)
4(b)(1)* Indenture, dated as of October 1, 1993, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, September 30, 1993 - Exhibit 4(a)). 4(b)(2)* Indenture supplemental to Indenture dated as of October 1, 1993:
Previous Filing: Form; Date or Exhibit Dated as of File No. No. November 1, 1993 S-3, (33-51167) 4(b)(2) January 1, 1994 10-K, 1993 4(b)(3)
4(c)* Rights Agreement dated as of February 26, 1991, between the Registrant and Mellon Bank, N.A. (Form 8-A, filed on March 1, 1991 - Exhibit 1). 10(a)(1)* Contract dated July 1, 1965 between the Registrant, United States Atomic Energy Commission and General Dynamics Corporation (Form S-7, File No. 2-24772 - Exhibit 4(g)). 10(a)(2)* Settlement Agreement dated June 27, 1979 between the Registrant and General Atomic Company (Form S-7, File No. 2- 66484 - Exhibit 5(a)(1)). 10(a)(3)* Services Agreement executed June 27, 1979 and effective as of January 1, 1979 between the Registrant and General Atomic Company (Form S-7, File No. 2-66484 - Exhibit 5(a)(3)). 10(b)* Agreement for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste dated June 24, 1983 between the Registrant and the United States Department of Energy (10-K, 1983 - Exhibit 10(b)(2)). 10(c)(1)* Amended and Restated Coal Supply Agreement entered into October 1, 1984 but made effective as of January 1, 1976 between the Registrant and Amax Inc. on behalf of its division, Amax Coal Company (10-K, 1984 - Exhibit 10(c)(1)). 97 10(c)(2)* First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective January 1, 1988 between the Registrant and Amax Coal Company (10-K, 1988 - Exhibit 10(c)(2).** 10(e)(2)*+ Supplemental Executive Retirement Plan for Key Management Employees, as amended and restated March 26, 1991 (10-K, 1991 - Exhibit 10(e)(2)). 10(e)(3)*+ Omnibus Incentive Plan (1992 Proxy Statement - Exhibit A). 10(e)(5)*+ Executive Savings Plan (10-K, 1991 - Exhibit 10(e)(5)). 10(e)(6)*+ Form of Key Executive Severance Agreement (10-K, 1991 - Exhibit 10(e)(6)). 10(f)(1)*+ Form of Director's Agreement (10-K, 1987 - Exhibit 10(f)(1)). 10(f)(2)*+ Form of Officer's Agreement (10-K, 1987 - Exhibit 10(f)(2)). 10(g)(1)*+ Employment Agreement dated April 8, 1994 between the Company and Mr. Delwin D. Hock (10-Q, March 31, 1994 - Exhibit 10). 10(g)(2)*+ Employment Agreement dated July 18, 1994 between the Company and Mr. Wayne H. Brunetti (10-Q, September 30, 1994 - Exhibit 10). 10(g)(3)+ Employment Agreement dated December 5, 1994 between the Company and Ms. Patricia T. Smith. 12(a) Computation of Ratio of Consolidated Earnings to Consolidated Fixed Charges is set forth at page 67 herein. 12(b) Computation of Ratio of Consolidated Earnings to Consolidated Combined Fixed Charges and Preferred Stock Dividends is set forth at page 68 herein. 21 Subsidiaries 23 The Consent of Arthur Andersen LLP is set forth at page 74 herein. 24 Power of Attorney is set forth at page 74 herein. 27 Financial Data Schedule UT _________________ * Previously filed as indicated and incorporated herein by reference. ** Confidential Treatment. + Management contracts of compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(10)(iii) of Regulation S-K. 98 EX-10 2 EMPLOYMENT AGREEMENT-PAT SMITH EXHIBIT 10(g)(3) EMPLOYMENT AGREEMENT PATRICIA T. SMITH Public Service Company of Colorado December 5, 1994 Contents _________________________________________________________________ Page Section 1. Term of Employment 1 Section 2. Position and Responsibilities 1 Section 3. Executive to Devote Full Time 1 Section 4. Compensation 2 Section 5. Expenses 4 Section 6. Disability 5 Section 7. Termination of Employment 5 Section 8. Compensation Upon Termination 7 Section 9. Offset for Compensation Earned Subsequent to Termination 8 Section 10. Covenants 8 Section 11. Indemnification 9 Section 12. Assignment 9 Section 13. Income Tax 10 Section 14. Dispute Resolution and Notice 10 Section 15. Miscellaneous 11 Section 16. Governing Law 11 Employment Agreement Patricia T. Smith This Employment Agreement is made, entered into, and is effective as of this 5th day of December, 1994, by and between Public Service Company of Colorado (hereinafter referred to as the "Company"), having its principal offices at 1225 17th Street, Denver, Colorado, and Patricia T. Smith (hereinafter referred to as the "Executive"): WHEREAS, Executive possesses considerable experience in, and knowledge of, the electric and natural gas utility industries; and WHEREAS, the Company desires to employ Executive in an executive capacity for the Company; NOW, THEREFORE, in consideration of the foregoing and of the mutual covenants and agreements of the parties set forth in this Agreement, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound, agree as follows: Section 1. Term of Employment The Company hereby agrees to employ Executive, and Executive hereby agrees to serve the Company, in accordance with the terms and conditions set forth herein, commencing as of the effective date of this Agreement, as indicated above, and ending on December 4, 1997. Section 2. Position and Responsibilities Executive agrees to serve as Senior Vice President and General Counsel of the Company, or in any other similar executive capacity for the Company, if so elected by the Board of Directors. Any change in these terms will be by mutual agreement of the Executive and the Board of Directors. Section 3. Executive to Devote Full Time During the term of this Agreement, Executive agrees to devote substantially her full time, attention, and energies to the Company's business and shall not be engaged directly or indirectly in any other business activity, whether or not such business activity is pursued for gain, profit, or other pecuniary advantage without prior approval of the Board of Directors, as expressed by formal resolution. This prohibition does not include charitable, civic, nonprofit, or other community service activities, nor shall it be construed as preventing the Executive from investing assets in such form or manner as will not require her services in the daily operations of the affairs of the companies in which such investments are made, or serving as a director of other companies (subject to the covenants of Section 10 herein). Section 4. Compensation 4.1 Sign-On Bonus. Upon the commencement of Executive's employment with the Company, Executive shall receive a single lump sum cash payment in the gross amount of Twenty Thousand Dollars ($20,000), and further, shall be issued 750 shares of restricted stock of the Company. Stock certificates evidencing these 750 shares shall bear restrictions that: (a) Executive may not trade, sell, transfer or gift said shares for a period of three (3) years from the effective date of this Agreement and thereafter only in accordance with applicable federal and state securities laws; and (b) Executive shall transfer the shares to the Company in the event Executive's employment with the Company is terminated for "cause" (as provided in Section 7.4 herein) prior to December 4, 1997. In the event the Company is subject to a "Change in Control," the above restrictions on said shares shall lapse and such shares shall become freely tradeable, subject to any transfer restrictions under applicable federal and state securities laws. For purposes of this Agreement, "Change in Control" shall mean (i) receipt by the Company of a report on Schedule 13D filed pursuant to Section 13(d) of the Securities Exchange Act of 1934, as amended, or knowledge of facts on which a Schedule 13D is required to be so filed, disclosing that the person filing, or who should be filing, the Schedule 13D is a beneficial owner, directly or indirectly, of twenty percent (20%) or more of the Company's outstanding common shares; (ii) any person becomes the owner, directly or indirectly, of twenty percent (20%) or more of the outstanding common shares of the Company; (iii) a change in the majority of the Board within a twenty-four (24) month period, unless the election or nomination for election by the Company's shareholders of any person who becomes a director subsequent to the date hereof is approved by the vote of at least two-thirds of the directors then still in office who were in office at the beginning of the twenty-four (24) month period, shall be for purposes hereof considered as though such person was a member of the Board as of the date hereof; or (iv) the shareholders of the Company approve a dissolution of the Company or an agreement to merge, consolidate or sell substantially all the assets of the Company pursuant to which the Company is not the surviving entity. 4.2 Base Salary. The Company shall pay Executive a salary at a rate (hereinafter referred to as "Base Salary") that shall - 2 - be established from time to time by the Board of Directors of the Company or the Board's designee; provided, however, that such Base Salary shall not be less than Two Hundred Twenty Thousand Dollars ($220,000) per year. This Base Salary shall be paid to Executive in equal monthly installments throughout the year, consistent with the normal payroll practices of the Company. Base Salary shall be reviewed at least annually following the effective date of this Agreement, while this Agreement is in force, to ascertain whether, in the judgment of the Board or the Board's designee, such Base Salary should be increased (but not decreased). If so increased, that salary shall become the Base Salary for all purposes of this Agreement. 4.3 Incentive Compensation. (a) Annual Bonus. During the term of this Agreement, the Executive shall be eligible to receive short-term incentive opportunities commensurate with her position with the Company, based upon such terms as the Board of Directors or its designee establishes from year to year, and pursuant and subject to the terms and conditions of all then applicable plans. Executive's annual target bonus potential shall not be less than thirty percent (30%) of Base Salary. The Board of Directors or its designee reserves discretion to award an annual bonus above or below the target bonus potential, based on the Board's or the designee's assessment of Executive's individual performance, Executive's contributions to the Company's corporate goals, and the Company's corporate performance; provided, however, that if all other terms and conditions of the bonus program are fully satisfied, Executive shall not receive less than fifty percent (50%) of the target bonus potential nor more than one hundred fifty percent (150%) of the target bonus potential. The annual bonus may be in the form of cash and/or restricted stock, as determined by the Board of Directors or its designee. (b) Stock Options and Dividend Equivalents. The Company will provide the Executive the opportunity to receive stock options and dividend equivalents commensurate with her position with the Company, based upon such terms as the Board of Directors or its designee establishes from year to year, and pursuant and subject to the terms and conditions of all then applicable plans; provided, however, that the Executive's annual stock option award opportunity shall not be less than one hundred fifteen percent (115%) of Base Salary. Dividend equivalents shall be periodically paid on the stock options, whether or not exercised, based on the Company's corporate performance, as determined by the Board of Directors or its designee. - 3 - 4.4 Executive Benefits. The Company shall provide to the Executive all benefits which other officers and employees of the Company are entitled to receive, as commensurate with the Executive's position, pursuant and subject to the terms and conditions of all then applicable plans. Such benefits shall include, but not be limited to, group term life insurance, comprehensive health and major medical insurance, long-term disability, accidental death and dismemberment insurance, travel accident insurance, and participation in any supplemental benefit plans (including supplemental executive retirement), employee savings plans, executive savings plan, all employee welfare benefit plans, and employee pension benefit plans. As of the effective date of this Agreement and continuing throughout Executive's employment under this Agreement, Executive shall be a participant in the Supplemental Executive Retirement Plan for Key Management Employees, which may be amended or revised from time to time by the Company ("SERP Plan"). Under the SERP Plan in effect on the effective date of this Agreement, a participating executive who terminates employment at age 65 or above, if entitled to a fully vested and accrued SERP Plan benefit under the terms and conditions of the SERP Plan, receives a monthly benefit in an amount that, when added to the highest optional monthly benefit the executive is entitled to receive from the Employees' Retirement Plan of Public Service Company of Colorado, regardless of the actual benefit so paid, equals sixty- five percent (65%) of the executive's regular monthly base salary at the time of termination. Executive's rights and benefits shall be pursuant and subject to the terms and conditions (including but not limited to the vesting schedule and vesting requirements) of the then applicable SERP Plan, if any. Notwithstanding any provision of the then applicable SERP Plan, if any, to the contrary, two-twentieths (2/20) of the total benefit from the Plan shall be deemed accrued on the effective date of this Agreement, and the balance of the total benefit from the Plan shall accrue annually over the period commencing on the effective date of this Agreement and ending on the date Executive reaches age 65, with a portion equal to one-twentieth (1/20) of the total benefit accruing annually, on the anniversary of Executive's date of birth, during said eighteen (18) year period. Executive shall be entitled each calendar year to paid vacation in accordance with the standard written policy of the Company with regard to vacations of employees; provided, however, that such paid vacation shall not be less than four (4) weeks in a full calendar year. Executive shall receive a sick leave accrual of 2,080 hours upon execution of this Agreement. Executive shall likewise have the benefit of any additional benefits, as may be established during the term of this Agreement, by written policy of the Company. - 4 - 4.5 Perquisites. The Company shall provide to Executive, at the Company's cost, all perquisites to which other officers of the Company are entitled. The Company also shall provide such other perquisites which are suitable to the character of Executive's position with the Company and adequate for the performance of her duties hereunder, including, but not limited to, a furnished executive office and a full-time secretary located at the Company's corporate headquarters. 4.6 Modifications to Programs. By reason of Sections 4.4 and 4.5 herein, the Company shall not be obligated to institute, maintain, or refrain from changing, amending, or discontinuing any benefit plan, program, or perquisite, so long as such changes are similarly applicable to senior executive employees generally. Section 5. Expenses 5.1 Moving and Relocation Expenses. The Company shall pay, or reimburse Executive, for reasonable and necessary moving and relocation expenses incurred in the relocation of Executive's principal residence, in accordance with the Company's existing relocation policy. 5.2 Ongoing Expenses. The Company shall pay, or reimburse Executive in accordance with Company policies, for all ordinary and necessary expenses, in a reasonable amount, which Executive incurs in performing her duties under this Agreement, including, but not limited to, travel, entertainment, professional dues and subscriptions, and all dues, fees, and expenses associated with membership in various professional, business, social, and civic associations and societies of which Executive's participation is in the best interests of the Company. Section 6. Disability 6.1 Long-Term Disability. In the event of the disability of the Executive, the Company will provide to the Executive benefits pursuant and subject to the terms and conditions of the Long-Term Disability Income Plan then in effect. 6.2 Termination of Disability. Upon termination of the Executive's disability, she shall regain the rights, benefits, and obligations inuring to her pursuant to this Agreement as an active employee, provided that this Agreement has not otherwise earlier been terminated. Section 7. Termination of Employment 7.1 Termination for Good Reason. Executive may terminate this Agreement for good reason by giving the Board a minimum of thirty (30) days' prior written notice of such intent to terminate, which sets forth in reasonable detail the facts and circumstances claimed to provide a basis for such termination. - 5 - Good reason shall mean, without Executive's express written consent, the occurrence of any one or more of the following: (a) The assignment to the Executive of any duties inconsistent in any respect with the Executive's position (including status and reporting requirements), authorities, duties, or other responsibilities as contemplated by Section 2 of this Agreement, or any other action of the Company which results in a diminishment in such position, authority, duties, or responsibilities, other than an insubstantial and inadvertent action which is remedied by the Company promptly after receipt of notice thereof given by the Executive, or actions required because of Executive's incapacity due to physical or mental illness; (b) The Company's requiring the Executive to be based more than forty (40) miles from the location of her principal office at that time; (c) A reduction or elimination of any component of Executive's compensation, as provided for in Section 4 herein; or (d) A breach by the Company of any provision of this Agreement which is not remedied by the Company promptly after receipt of notice thereof given by the Executive. Subject to the consulting requirements of Section 8 herein, upon lapse of the thirty (30) day notice period, the Executive's obligation to serve the Company, and the Company's obligation to employ Executive, under the terms of this Agreement, shall terminate simultaneously, and the Executive shall receive those benefits specified in Section 8 herein. The Executive's right to terminate employment for "good reason" shall not be affected by the Executive's incapacity due to physical or mental illness, except that Executive may not terminate employment for "good reason" under category (a) hereinabove for actions of the Company required by said incapacity. The Executive's continued employment shall not constitute consent to, or a waiver of rights with respect to, any circumstance constituting "good reason" herein. 7.2 Termination by Notice. Either the Company or the Executive may terminate this Agreement without cause by delivering proper written notice to the other party. (a) Notice by Executive. Executive may terminate this Agreement at any time by giving the Company's Board of Directors a minimum of ninety (90) days' prior written notice of her intent to terminate. In such case, upon the lapse of the ninety (90) days, the Company shall - 6 - pay Executive her full Base Salary through the effective date of termination, and Executive shall immediately thereafter forfeit all rights and benefits (other than vested benefits) she would otherwise have been entitled to receive under this Agreement (including, if applicable, the Executive's annual expected target bonus for that year). Subject to the consulting requirements of Section 8 herein, the Company and Executive thereafter shall have no further obligations under this Agreement. (b) Notice by the Company. The Company may terminate this Agreement at any time by the Board of Directors giving Executive ninety (90) days' prior written notice of the Company's intent to terminate. Subject to the consulting requirements of Section 8 herein, upon the lapse of the ninety (90) days, Executive's obligation to serve the Company, and the Company's obligation to employ Executive under the terms of this Agreement shall terminate simultaneously, and the Executive shall receive those benefits specified in Section 8 herein. 7.3 Termination for Cause. Nothing in this Agreement shall be construed to prevent the Company's Board of Directors from terminating Executive's employment under this Agreement for "cause." In the event this Agreement is terminated by the Company for "cause," the Company shall pay Executive her full Base Salary through the date of termination, and Executive shall immediately thereafter forfeit all rights and benefits (other than vested benefits) she would otherwise have been entitled to receive under this Agreement (including, if applicable, the Executive's annual expected target bonus for that year). The Company and Executive thereafter shall have no further obligations under this Agreement. 7.4 Termination After Change in Control. In the event of a Change in Control (as defined in Section 4.1 herein), the Executive shall be entitled to the greater of (a) the payments she would otherwise be entitled to receive for the remaining term of this Agreement; or (b) those payments provided for under the Severance Agreement. If it is determined that payments will be made pursuant to this Agreement following a Change in Control, the Executive shall be entitled to tax-free reimbursements of any excise taxes that may arise as a result of such payments. Section 8. Compensation Upon Termination In the event Executive's employment is terminated for good reason (as provided in Section 7.1 herein), or by notice by the Company (as provided in Section 7.2(b) herein), the Company shall continue the Executive's total compensation package for the - 7 - remaining term of this Agreement which shall constitute the following amounts upon the effective date of such termination, or as otherwise specified: (a) Executive's annual Base Salary (as stated in Section 4.1 herein and adjusted by the Board from time to time), continued for the remaining term of this Agreement, paid to the Executive in equal monthly installments consistent with the normal payroll practices of the Company; (b) For annual incentive plan(s) in place and operational on the date of termination, the greater of target or actual bonus paid for the year in which employment termination occurs, as provided in the annual incentive plan and subject to the authority of the Board under such plan, continued for the remaining term of this Agreement; (c) For long-term incentive plan(s) in place and operational on the date of termination, an immediate vesting of all outstanding long-term incentive awards (including dividend equivalents) held by the Executive, with payout of dividend equivalents already credited equal to the greater of target or actual value, and the value of any dividend equivalents that otherwise would have been paid but for accelerated vesting based on target; plus the economic equivalent value of any long- term incentive awards (including dividend equivalents) the Executive would have received had she remained employed for the remaining term of this Agreement; as provided in the long-term incentive plan and subject to the authority of the Board under such plan; (d) For the Supplemental Executive Retirement Plan (or any successor plan) in place and operational on the date of termination, payment, in accordance with the terms of the plan, of the Executive's accrued benefits, vested or otherwise; plus, Executive shall receive credit for such additional years of service equal to the number of years remaining under this Agreement at the time of termination; (e) For the Executive Savings Plan (or any successor plan) in place and operational on the date of termination, payment, in accordance with the terms of the plan, within thirty (30) days of termination, of the Executive's account balances therein; plus credit for the maximum additional Company contributions the Executive would have been entitled to receive had she remained employed for the remaining term of this Agreement; - 8 - (f) For welfare benefit plan(s) in place and operational on the date of termination, Executive shall receive full benefit coverage for the remaining term of this Agreement; (g) For all qualified retirement plans in place and operational on the date of termination, Executive shall receive, by direct payment from the Company, the present value of the benefits that would have been paid under the qualified plans if the Executive had received credit for such additional years of service equal to the number of years remaining under this Agreement at the time of termination; plus the maximum Company matching contributions and accruals under any such retirement plans Executive would have been entitled to receive had her employment continued for the remaining term of this Agreement; and (h) For all perquisite programs in place and operational on the date of termination, Executive shall receive full perquisites for the remaining term of this Agreement. As consideration for the continuation of the above-stated benefits, Executive agrees to make herself available during the remaining term of the Agreement, at reasonable times and location, to the Company and/or to the successor to her position at the Company, to provide consulting advice (as requested). Section 9. Offset for Compensation Earned Subsequent to Termination In the event the Executive's employment is terminated for good reason (as provided in Section 7.1 herein), or by notice by the Company (as provided in Section 7.2(b) herein), the continuation of the Executive's Base Salary (as provided in Section 8(a) herein), any annual bonus, if applicable (as provided in Section 8(b) herein), long-term incentive plan(s) awards, if any (as provided in Section 8(c) herein), the Supplemental Executive Retirement Plan, if any (as provided in Section 8(d) herein), and the Executive Savings Plan, if any (as provided in Section 8(e) herein), shall not be offset by compensation earned from a subsequent employer during the remaining term of this Agreement. Section 10. Covenants 10.1 Noncompetition. Without the prior written consent of the Company, for the greater of twenty-four (24) months following a termination under Section 7 of this Agreement, or the remaining term of this Agreement, the Executive shall not, as a shareholder, employee, officer, director, partner, consultant, or otherwise, engage directly or indirectly in any business or - 9 - enterprise which is "in competition" with the Company or its successors or assigns. A business or enterprise is deemed to be "in competition" if it is engaged in the business of generation, purchase, transmission, distribution, or sale of electricity, or in the purchase, transmission, distribution, sale or transportation of natural gas within the States of Colorado and Wyoming. 10.2 Disclosure of Information. Executive recognizes that she will have access to and knowledge of certain confidential and proprietary information of the Company and its subsidiaries which is essential to the performance of her duties under this Agreement. Executive will not, during or after the term of her employment by the Company, in whole or in part, disclose such information to any person, firm, corporation, association, or other entity for any reason or purpose whatsoever, nor shall she make any use of any such information for her own purposes. 10.3 Covenants Regarding Other Employees. For the greater of twenty-four (24) months following a termination under Section 7 of this Agreement, or the remaining term of this Agreement, the Executive agrees not to induce any employees of the Company to terminate their employment, accept employment with anyone else, or to interfere in a similar manner with the business of the Company. Section 11. Indemnification The Company hereby covenants and agrees to indemnify and hold harmless Executive fully, completely, and absolutely against, and in respect to any and all actions, suits, proceedings, claims, demands, judgments, costs, expenses (including attorney's fees), losses, and damages resulting from Executive's good faith performance of her duties and obligations under the terms of this Agreement. Section 12. Assignment 12.1 Assignment by Company. With the Executive's consent, this Agreement may and shall be assigned or transferred to, and shall be binding upon and shall inure to the benefit of, any successor of the Company, and any such successor shall be deemed substituted for all purposes for the "Company" under the terms of this Agreement. As used in this Agreement, the term "successor" shall mean any person, firm, corporation, or business entity which, at any time, whether by merger, purchase, consolidation, or otherwise acquires all or essentially all of the assets of the business of the Company or controls the business activities of the Company. Notwithstanding such assignment, the Company shall remain with such successor, jointly and severally liable for all its obligations hereunder. - 10 - If the Executive does not provide her consent to the transfer or assignment of this Agreement, or upon failure of the Company to obtain agreement by the successor organization to be bound by this Agreement prior to the effectiveness of any such succession, it shall immediately entitle Executive to compensation from the Company in the same amount and on the same terms as Executive would be entitled in the event of a Termination by Notice by the Company, as described in Sections 7.2(b), 7.4 and 8 herein. Except as herein provided, this Agreement may not otherwise be assigned by the Company. 12.2 Assignment by Executive. This Agreement shall inure to the benefit of, and be enforceable by, Executive's personal or legal representatives, executors, and administrators, successors, heirs, distributees, revisees, and legatees. If Executive should die while any amounts payable to Executive hereunder remain outstanding, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to Executive's devisee, legatee, or other designee or, in the absence of such designee, the Executive's estate. Other than a transfer by reason of death, the rights and duties of Executive hereunder are personal and may not be assigned or transferred. Section 13. Income Tax The Company may withhold, from any benefits payable under this Agreement, all federal, state, city, or other taxes as may be required pursuant to any law or governmental regulation or ruling. Section 14. Dispute Resolution and Notice 14.1 Dispute Resolution. The parties agree that any dispute or controversy arising under or in connection with this Agreement shall be submitted to arbitration as the exclusive forum, provided that if a party gives notice to the other party of her or its desire that the arbitration hearing be held forthwith and a hearing is not conducted within ninety (90) days following said notice, the party having given such notice may initiate litigation, in which case the Court's jurisdiction shall supersede and replace that of the arbitrators. The arbitrators shall have all powers of a court to grant legal or equitable relief to remedy any breach of this Agreement. Arbitration proceedings shall be conducted before a panel of three (3) arbitrators sitting in a location selected by the Executive within fifty (50) miles from the location of her principal place of employment, in accordance with the rules of the American Arbitration Association then in effect. Judgment - 11 - may be entered on the award of the arbitrators in any court having competent jurisdiction. The arbitrators' fees shall be divided and paid equally by Executive and the Company. Executive and the Company shall pay her/its own costs and attorney fees, if any, in the arbitration proceedings, preliminary and ancillary proceedings, and any court proceedings to enforce or vacate an arbitration award. 14.2 Notice. Any notices, requests, demands, and other communications provided for by this Agreement shall be sufficient if in writing and if sent by registered or certified mail to Executive at the last address she has filed in writing with the Company or, in the case of the Company, at its principal executive offices. Section 15. Miscellaneous 15.1 Waiver. A waiver of any breach of this Agreement shall not be construed as a waiver of any subsequent breach of the Agreement. 15.2 Modification. This Agreement shall not be varied, altered, modified, canceled, changed, or in any way amended except by mutual agreement of the parties in a written instrument executed by the parties hereto or their legal representatives. 15.3 Severability. In the event that any provision or portion of this Agreement shall be determined to be invalid or unenforceable for any reason, the remaining provisions of this Agreement shall be unaffected thereby and shall remain in full force and effect. 15.4 Integration Clause. This Agreement sets forth the complete agreement between the parties, and supersedes all prior statements, stipulations, representations, promises, or agreements, if any, between the parties. No other consideration, other than that set forth in this Agreement, is due between the parties. 15.5 Counterparts. This Agreement may be executed in one (1) or more counterparts, each of which shall be deemed to be an original, but all of which together will constitute one (1) and the same Agreement. Section 16. Governing Law The provisions of this Agreement shall be construed and enforced in accordance with the laws of the State of Colorado. IN WITNESS WHEREOF, Executive has executed, and the Company (pursuant to a resolution adopted at a duly constituted meeting - 12 - of its Board of Directors) has executed this Agreement, as of the day and year first above-written. ATTEST: PUBLIC SERVICE COMPANY OF COLORADO By: /s/W.Wayne Brown By: /s/D.D. Hock __________________________ ________________________________ Corporate Secretary EXECUTIVE /s/Patricia T. Smith ________________________________ Patricia T. Smith - 13 - EX-21 3 SUBSIDIARIES EXHIBIT 21 SUBSIDIARIES OF PUBLIC SERVICE COMPANY OF COLORADO As of December 31, 1994 Subsidiary State of Incorporation 1. Cheyenne Light, Fuel and Power Company Wyoming 2. 1480 Welton, Inc. Colorado 3. Fuel Resources Development Co. Colorado 4. Green and Clear Lakes Company New York 5. Natural Fuels Corporation Colorado 6. PS Colorado Credit Corporation Colorado 7. PSR Investments, Inc. Colorado 8. WestGas InterState, Inc. Colorado 9. WestGas TransColorado, Inc. Colorado The names of several majority-owned subsidiaries are omitted since such subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary as of December 31, 1994. EX-27 4 FINANCIAL DATA SCHEDULE WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 1994 AND CONSOLIDATED STATEMENTS OF INCOME AND CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1994 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATMENTS 1,000 DEC-31-1994 DEC-31-1994 12-MOS 20.39 3,291,402 18,202 511,764 386,464 0 4,207,832 310,772 648,496 308,214 1,267,482 42,665 140,008 1,155,427 107,850 0 216,950 25,153 2,576 0 0 1,249,721 4,207,832 2,057,384 48,500 369,094 1,786,592 270,792 31,611 302,403 132,134 170,269 12,014 158,255 123,379 89,005 245,728 2.57 2.57
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