0000081018-95-000015.txt : 19950811 0000081018-95-000015.hdr.sgml : 19950811 ACCESSION NUMBER: 0000081018-95-000015 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19950630 FILED AS OF DATE: 19950810 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-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-03280 FILM NUMBER: 95560855 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-Q 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 Form 10-Q [ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 1995 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 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 At August 4, 1995, 63,109,140 shares of the registrant's Common Stock, $5.00 par value (the only class of common stock), were outstanding. Table of Contents PART 1 - FINANCIAL INFORMATION Item 1. Financial Statements . . . . . . . . . . . . . . . . . . . . . . 1 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . 18 PART II - OTHER INFORMATION Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . 25 Item 4. Submission of Matters to a Vote of Security Holders . . . . . . 25 Item 5. Other Information . . . . . . . . . . . . . . . . . . . . . . . 25 Item 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . . . . . . 25 SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 EXHIBIT INDEX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 EXHIBIT 12(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 EXHIBIT 12(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 EXHIBIT 15 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 PART 1 - FINANCIAL INFORMATION Item 1. Financial Statements PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS (Thousands of Dollars) ASSETS
June 30, December 31, 1995 1994 (Unaudited) Property, plant and equipment, at cost: Electric . . . . . . . . . . . . . . . . . . . . . . . $ 3,711,283 $3,641,711 Gas . . . . . . . . . . . . . . . . . . . . . . . . . 891,691 867,239 Steam and other . . . . . . . . . . . . . . . . . . . 88,206 86,458 Common to all departments . . . . . . . . . . . . . . 387,734 369,070 Construction in progress . . . . . . . . . . . . . . . 202,895 187,577 5,281,809 5,152,055 Less: accumulated depreciation . . . . . . . . . . . . 1,923,397 1,860,653 Total property, plant and equipment . . . . . . . . 3,358,412 3,291,402 Investments, at cost . . . . . . . . . . . . . . . . . . 25,055 18,202 Current assets: Cash and temporary cash investments . . . . . . . . . 5,791 5,883 Accounts receivable, less reserve for uncollectible accounts ($4,022 at June 30, 1995; $3,173 at December 31, 1994) . . . . . . . . . . . . 138,758 163,465 Accrued unbilled revenues . . . . . . . . . . . . . . 69,716 86,106 Recoverable purchased gas and electric energy costs - net . . . . . . . . . . . . . . . . . - 37,979 Materials and supplies, at average cost . . . . . . . 66,572 67,600 Fuel inventory, at average cost . . . . . . . . . . . 36,501 31,370 Gas in underground storage, at cost (LIFO) . . . . . . 19,794 42,355 Current portion of accumulated deferred income taxes . 31,325 20,709 Regulatory assets recoverable within one year (Note 1) 39,728 39,985 Prepaid expenses and other . . . . . . . . . . . . . . 15,466 16,312 Total current assets . . . . . . . . . . . . . . . . 423,651 511,764 Deferred charges: Regulatory assets (Note 1) . . . . . . . . . . . . . . 328,331 335,893 Unamortized debt expense . . . . . . . . . . . . . . . 10,720 11,073 Other . . . . . . . . . . . . . . . . . . . . . . . . 41,337 39,498 Total deferred charges . . . . . . . . . . . . . . . 380,388 386,464 $ 4,187,506 $4,207,832 The accompanying notes to consolidated condensed financial statements are an integral part of these financial statements.
1 PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS (Thousands of Dollars) CAPITAL AND LIABILITIES
June 30, December 31, 1995 1994 (Unaudited) Common stock . . . . . . . . . . . . . . . . . . . . . . $ 982,886 $ 959,268 Retained earnings . . . . . . . . . . . . . . . . . . . . 320,048 308,214 Total common equity . . . . . . . . . . . . . . . . . 1,302,934 1,267,482 Preferred stock: Not subject to mandatory redemption . . . . . . . . . 140,008 140,008 Subject to mandatory redemption at par . . . . . . . . 42,665 42,665 Long-term debt . . . . . . . . . . . . . . . . . . . . . 1,081,746 1,155,427 2,567,353 2,605,582 Noncurrent liabilities: Defueling and decommissioning liability (Note 2) . . . 24,315 40,605 Employees' postretirement benefits other than pensions . . . . . . . . . . . . . . . . . . . 45,799 42,106 Employees' postemployment benefits . . . . . . . . . . 20,975 20,975 Total noncurrent liabilities . . . . . . . . . . . . 91,089 103,686 Current liabilities: Notes payable and commercial paper . . . . . . . . . . 286,300 324,800 Long-term debt due within one year . . . . . . . . . . 83,174 25,153 Preferred stock subject to mandatory redemption within one year . . . . . . . . . . . . . 2,576 2,576 Accounts payable . . . . . . . . . . . . . . . . . . . 136,506 177,031 Dividends payable . . . . . . . . . . . . . . . . . . 35,091 34,078 Recovered purchased gas and electric energy costs - net 50,064 - Customers' deposits . . . . . . . . . . . . . . . . . 17,955 17,099 Accrued taxes . . . . . . . . . . . . . . . . . . . . 36,641 54,148 Accrued interest . . . . . . . . . . . . . . . . . . . 31,164 32,265 Current portion of defueling and decommissioning liability (Note 2) . . . . . . . . . . . . . . . . . 40,415 36,365 Other . . . . . . . . . . . . . . . . . . . . . . . . 64,447 62,640 Total current liabilities . . . . . . . . . . . . . 784,333 766,155 Deferred credits: Customers' advances for construction . . . . . . . . . 104,948 96,442 Unamortized investment tax credits . . . . . . . . . . 116,045 118,532 Accumulated deferred income taxes . . . . . . . . . . 492,948 485,668 Other . . . . . . . . . . . . . . . . . . . . . . . . 30,790 31,767 Total deferred credits . . . . . . . . . . . . . . . 744,731 732,409 Commitments and contingencies (Notes 2 and 3) . . . . . . $ 4,187,506 $4,207,832 The accompanying notes to consolidated condensed financial statements are an integral part of these financial statements.
2 PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited) (Thousands of Dollars except per share data)
Three Months Ended June 30, 1995 1994 Operating revenues: Electric . . . . . . . . . . . . . . . . . . . . . . . $ 341,516 $ 339,980 Gas . . . . . . . . . . . . . . . . . . . . . . . . . 148,312 130,317 Other . . . . . . . . . . . . . . . . . . . . . . . . 8,871 7,266 498,699 477,563 Operating expenses: Fuel used in generation . . . . . . . . . . . . . . . 43,935 48,143 Purchased power . . . . . . . . . . . . . . . . . . . 117,983 103,396 Gas purchased for resale . . . . . . . . . . . . . . . 102,164 83,899 Other operating expenses . . . . . . . . . . . . . . . 86,734 95,640 Maintenance . . . . . . . . . . . . . . . . . . . . . 16,156 18,069 Depreciation and amortization . . . . . . . . . . . . 35,027 36,382 Taxes (other than income taxes) . . . . . . . . . . . 21,412 22,441 Income taxes . . . . . . . . . . . . . . . . . . . . . 12,654 11,566 436,065 419,536 Operating income . . . . . . . . . . . . . . . . . . . . 62,634 58,027 Other income and deductions: Allowance for equity funds used during construction . 1,107 1,078 Miscellaneous income and deductions - net . . . . . . 101 (2,712) 1,208 (1,634) Interest charges: Interest on long-term debt . . . . . . . . . . . . . . 21,337 22,018 Amortization of debt discount and expense less premium 806 802 Other interest . . . . . . . . . . . . . . . . . . . . 14,403 10,590 Allowance for borrowed funds used during construction (959) (892) 35,587 32,518 Net income . . . . . . . . . . . . . . . . . . . . . . . 28,255 23,875 Dividend requirements on preferred stock . . . . . . . . 3,000 3,005 Earnings available for common stock . . . . . . . . . . . $ 25,255 $ 20,870 Weighted average common shares outstanding (thousands) . 62,846 61,425 Earnings per weighted average share of common stock outstanding . . . . . . . . . . $ 0.40 $ 0.34 Dividends per share declared on common stock . . . . . . $ 0.51 $ 0.50 The accompanying notes to consolidated condensed financial statements are an integral part of these financial statements.
3 PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited) (Thousands of Dollars except per share data)
Six Months Ended June 30, 1995 1994 Operating revenues: Electric . . . . . . . . . . . . . . . . . . . . . . . $ 708,099 $ 688,264 Gas . . . . . . . . . . . . . . . . . . . . . . . . . 392,869 385,321 Other . . . . . . . . . . . . . . . . . . . . . . . . 18,327 16,414 1,119,295 1,089,999 Operating expenses: Fuel used in generation . . . . . . . . . . . . . . . 91,120 101,511 Purchased power . . . . . . . . . . . . . . . . . . . 239,461 209,864 Gas purchased for resale . . . . . . . . . . . . . . . 270,299 261,413 Other operating expenses . . . . . . . . . . . . . . . 176,548 189,904 Maintenance . . . . . . . . . . . . . . . . . . . . . 30,860 34,502 Depreciation and amortization . . . . . . . . . . . . 70,193 73,300 Taxes (other than income taxes) . . . . . . . . . . . 44,503 45,120 Income taxes . . . . . . . . . . . . . . . . . . . . . 41,988 37,928 964,972 953,542 Operating income . . . . . . . . . . . . . . . . . . . . 154,323 136,457 Other income and deductions: Allowance for equity funds used during construction . 1,858 2,143 Miscellaneous income and deductions - net . . . . . . (3,782) (3,150) (1,924) (1,007) Interest charges: Interest on long-term debt . . . . . . . . . . . . . . 42,843 45,183 Amortization of debt discount and expense less premium 1,597 1,528 Other interest . . . . . . . . . . . . . . . . . . . . 27,711 19,986 Allowance for borrowed funds used during construction (1,651) (1,651) 70,500 65,046 Net income . . . . . . . . . . . . . . . . . . . . . . . 81,899 70,404 Dividend requirements on preferred stock . . . . . . . . 6,001 6,010 Earnings available for common stock . . . . . . . . . . . $ 75,898 $ 64,394 Weighted average common shares outstanding (thousands) . 62,680 61,172 Earnings per weighted average share of common stock outstanding . . . . . . . . . . $ 1.21 $ 1.05 Dividends per share declared on common stock . . . . . . $ 1.02 $ 1.00 The accompanying notes to consolidated condensed financial statements are an integral part of these financial statements.
4 PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (Thousands of Dollars)
Six Months Ended June 30, 1995 1994 Operating activities: Net income . . . . . . . . . . . . . . . . . . . . . . $ 81,899 $ 70,404 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization . . . . . . . . . . 72,159 74,647 Amortization of investment tax credits . . . . . . (2,487) (2,516) Deferred income taxes . . . . . . . . . . . . . . 3,179 17,726 Allowance for equity funds used during construction (1,858) (2,143) Change in accounts receivable . . . . . . . . . . 24,707 22,958 Change in inventories . . . . . . . . . . . . . . 18,458 30,552 Change in other current assets . . . . . . . . . . 54,574 54,015 Change in accounts payable . . . . . . . . . . . . (40,525) (78,958) Change in other current liabilities . . . . . . . 47,991 321 Change in deferred amounts . . . . . . . . . . . . 710 (46,930) Change in noncurrent liabilities . . . . . . . . . (12,596) 7,607 Other . . . . . . . . . . . . . . . . . . . . . . 65 32 Net cash provided by operating activities . . . 246,276 147,715 Investing activities: Construction expenditures . . . . . . . . . . . . . . (119,605) (128,756) Allowance for equity funds used during construction . 1,858 2,143 Proceeds from (cost of) disposition of property, plant and equipment . . . . . . . . . . . . . . . . . (11,933) 26,433 Purchase of other investments . . . . . . . . . . . . (7,283) (938) Sale of other investments . . . . . . . . . . . . . . 365 530 Net cash used in investing activities . . . . . (136,598) (100,588) Financing activities: Proceeds from sale of common stock . . . . . . . . . . 13,796 22,273 Proceeds from sale of long-term debt . . . . . . . . . 22,135 244,448 Redemption of long-term debt . . . . . . . . . . . . . (38,149) (280,579) Short-term borrowings - net . . . . . . . . . . . . . (38,500) 23,400 Dividends on common stock . . . . . . . . . . . . . . (63,051) (60,807) Dividends on preferred stock . . . . . . . . . . . . . (6,001) (6,010) Net cash used in financing activities . . . . . (109,770) (57,275) Net decrease in cash and temporary cash investments . . . . . . . . . . . . . . . (92) (10,148) Cash and temporary cash investments at beginning of period . . . . . . . . . . . . . 5,883 18,038 Cash and temporary cash investments at end of period . . . . . . . . . . . . . . . . $ 5,791 $ 7,890 The accompanying notes to consolidated condensed financial statements are an integral part of these financial statements.
5 PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Unaudited) 1. 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 Public Utilities Commission of the State of Colorado ("CPUC") with respect to its retail electric and gas operations and the Federal Energy Regulatory Commission ("FERC") with respect to its wholesale electric operations and accounting policies and practices. Cheyenne Light, Fuel and Power Company ("Cheyenne") and WestGas InterState, Inc. ("WGI") are subject to the jurisdictions of the Public Service Commission of Wyoming ("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 Statement of Financial Accounting Standards No. 71 - "Accounting for the Effects of Certain Types of Regulation" ("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. In response to the increasingly competitive 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. Although the Company does not currently anticipate such an event, to the extent the Company concludes in the future 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 Company may be required to recognize as expense, at a minimum, all deferred costs currently recognized as regulatory assets on the consolidated condensed balance sheet. In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of" ("SFAS 121"). SFAS 121 imposes stricter criteria for the continued recognition of regulatory assets on the balance sheet by requiring that such assets be probable of future recovery at each balance sheet date. The Company anticipates adopting this standard on January 1, 1996, the effective date of the new statement, and does not expect that adoption will have a material impact on the Company's results of operations, financial position or cash flow. 6 NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Continued) The following regulatory assets are reflected in the Company's consolidated condensed balance sheets:
June 30, December 31, Recovery 1995 1994 Through (Thousands of Dollars) Nuclear decommissioning costs (Note 2) $ 102,427 $ 107,374 2005 Income taxes . . . . . . . . . . . . . 119,317 125,832 2006 Employees' postretirement benefits other than pensions . . . . . . . . . . . . 42,586 37,573 2013 Early retirement costs . . . . . . . . 28,606 33,124 1998 Employees' postemployment benefits . . 20,975 20,975 Undetermined Demand-side management costs . . . . . 24,263 20,831 2002 Unamortized debt reacquisition costs . 22,952 22,360 2024 Other . . . . . . . . . . . . . . . . . 6,933 7,809 1999 Total . . . . . . . . . . . . . . . . 368,059 375,878 Classified as current . . . . . . . . . 39,728 39,985 Classified as noncurrent . . . . . . . $ 328,331 $ 335,893
Recovered/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 II generating station and certain water rights located in southeastern Colorado, also obtained for a future generating 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. Statements of Cash Flows - Non cash Transactions Shares of common stock (310,546 in 1995 and 334,223 in 1994), valued at the market price on date of issuance (approximately $9.7 million in 1995 and $10.1 million in 1994), were issued to the Employees' Savings and Stock Ownership Plan of Public Service Company of Colorado and Participating Subsidiary Companies. These estimated issuance values were recognized in other operating expenses during the respective preceding years. As part of the Company's Omnibus Incentive Plan, shares of common stock (3,891 in 1995 and 7,892 in 1994), valued at the market price on date of 7 NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Continued) issuance (approximately $0.1 million in 1995 and $0.2 million in 1994), were issued to certain executives. These stock issuances were not cash transactions and are not reflected in the consolidated condensed statements of cash flows. 2. Fort St. Vrain Overview During 1986, the Company entered into a Stipulation and Settlement Agreement with the CPUC, the Office of Consumer Counsel ("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 Independent Spent Fuel Storage Installation ("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 is pursuing the repowering of Fort St. Vrain as described below and, on July 1, 1994, the CPUC issued a decision granting the Company's application for a Certificate of Public Convenience and Necessity ("CPCN") for Phase 1 and Phase 2. The decision approved, with certain modifications, a Stipulation and Settlement Agreement (the "Settlement") among the Company, the OCC and various other parties regarding the CPCN. Repowering Fort St. Vrain is being 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 existing Fort St. Vrain assets 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. Because of the receipt of the CPCN related to the repowering of Fort St. Vrain, the Company believes the recovery of this remaining investment in the facility is probable. On July 17, 1995, the Nuclear Regulatory Commission ("NRC") approved the final radiation survey report of the repowering area prepared by the Company. 8 NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Continued) The Company reported that the survey data met unrestricted release criteria permitting such area to be released. 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, represented the inflation-adjusted estimated remaining cost of the early dismantlement/decommissioning activities not previously recognized as expense at the time of CPUC approval. At June 30, 1995, approximately $102.4 million of such amount remains to be collected from customers and, therefore, is reflected as a regulatory asset on the consolidated condensed balance sheet. The 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. At June 30, 1995, approximately 85% 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. Since the initiation of decommissioning activities, the decommissioning contractors have notified the Company of several 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. 9 NOTES TO CONSOLIDATED CONDENSED 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 Department of Energy ("DOE") for (a) the temporary storage of segments 1-8 at a DOE facility located in the State of Idaho (such contract includes an option to store 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 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 of segment 9 at the Idaho facility in conjunction with the first eight segments. The Company and the DOE are in discussions regarding the issues related to the disposal of Fort St. Vrain's spent nuclear fuel. In April 1995, the DOE issued an Environmental Impact Statement ("EIS") relative to, among other things, the receipt and storage of spent fuel at the Idaho facility. In May 1995, the final record of decision was issued related to such EIS. The EIS specifies a preferred alternative under which existing environmental restoration and waste management facilities and projects would continue to be operated, including Fort St. Vrain spent fuel nuclear fuel shipment from the ISFSI and storage at the Idaho facility. However, following the filing of a complaint by the State of Idaho contending that the EIS was not complete, the U.S. District Court for the District of Idaho issued an injunction prohibiting all shipments of spent fuel to the Idaho facility. Additionally, modifications to the Idaho facility will be required to accommodate the new spent fuel shipping casks. These modifications would be completed subsequent to the resolution of the various issues related to the EIS. The DOE's estimate of the time to complete the modification is between 15-18 months. Furthermore, 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 resolution of the various EIS issues. 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 additional 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 June 30, 1995, approximately $297.1 million has been spent for such activities with the remaining $64.7 million defueling and decommissioning liability reflected on the consolidated condensed balance sheet ($23.6 million - defueling; $41.1 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 assurance that the actual cost of defueling and decommissioning will not 10 NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Continued) 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 June 30, 1995, the letter of credit had been reduced to $50 million. The Company had previously set aside approximately $30 million in trust accounts for decommissioning the reactor. Since commencement of decommissioning, 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 $1.7 million at June 30, 1995. 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. 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 $8.9 billion, which includes a 5% surcharge. The Act 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 nuclear power plant. This amount is indexed every five years for inflation. Also, it is provided that not more than $10 million could be payable per incident in any one year. The Company's primary financial protection for this exposure was provided in the amount available ($200 million) by private insurance. In consideration of the shutdown and defueled status of Fort St. Vrain, the Company requested exemption from the indemnification obligations under the Act. The NRC granted the Company's request for exemption from participation in the indemnity program for nuclear incidents occurring after February 17, 1994 and reduced the amount of primary liability insurance required to $100 million. 11 NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Continued) 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, 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. However, on June 7, 1995, the NRC granted the Company an exemption from the requirement to maintain nuclear property damage insurance following an environmental assessment and finding of no significant impact. Accordingly, the Company has reduced such insurance coverage to $10 million, which is related only to the ISFSI. 3. Commitments and Contingencies Regulatory Matters Electric and Gas Cost Adjustment Mechanisms The Company's Electric Cost Adjustment ("ECA") mechanism was revised and a new Qualifying Facility Capacity Cost Adjustment ("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, Qualifying Facilities ("QF") and Independent Power Production Facilities (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 were held on April 10-11, 1995. A decision on this matter is expected by September 1995. During 1994, the CPUC initiated proceedings for reviewing the justness and reasonableness of Gas Cost Adjustment ("GCA") and ECA mechanisms used by gas and electric utilities within its jurisdiction. On March 17, 1995, the CPUC issued an order requiring the Company to make an individual filing with the CPUC related to its ECA by September 1, 1995, at which time the CPUC will review whether the ECA should be maintained in its present form, altered or eliminated. On April 14, 1995, the CPUC issued a final order which retained the GCA with no modifications and closed its investigation with respect to the GCA mechanism. On June 8, 1994, the CPUC approved the recovery of certain "energy efficiency credits" from retail jurisdiction customers through the Demand Side Management Cost Adjustment ("DSMCA"). On December 1, 1994, the OCC filed an appeal in the District Court in and for the City and County of Denver ("Denver District Court") of the CPUC's decision. The Denver District Court approved the collection of these credits on June 19, 1995, subject to refund. Accordingly, effective July 1, 1995, the Company began collection of the December 31, 1994 balance of unbilled revenue related to these credits 12 NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Continued) (approximately $6.7 million). At June 30, 1995, approximately $8.5 million of unbilled revenue related to these credits has been recognized by the Company. If the OCC is successful in its appeal, the Company could be required to reverse these unbilled revenues and refund the amounts previously collected. 1995 Rate Filing The Company is developing a comprehensive proposal which it anticipates filing with the CPUC in the third quarter of 1995. The proposal may include, among other things, maintaining current rates for an interim period, retention, modification or elimination of the ECA, GCA, and/or QFCCA and the implementation of performance based incentive measures. 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 demand side management ("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 included 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. During the first quarter of 1995, the technical working group presented to the CPUC a detailed analysis demonstrating the effect of the various proposed mechanisms. The Company is in opposition to all proposed alternative annual revenue reconciliation mechanisms and incentive mechanisms, but not the DSMCA. Direct testimony and exhibits were filed by the Company on June 15, 1995. Hearings have been scheduled for September 1995. Phase II of 1993 Rate Case 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 settlement agreement was reached related to gas rates in June 1995. Approval of the gas settlement agreement by the CPUC is expected in the third quarter of 1995 and a final decision on the Phase II proceedings related to electric rates is expected before year-end. Federal Energy Regulatory Commission On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking ("NOPR") on Open Access Non-Discriminatory Transmission Services by Public Utilities and Transmitting Utilities and a supplemental NOPR on Recovery of Stranded Costs. The rules proposed in the NOPR are intended to facilitate competition among electric generators for sales to the bulk power supply market. If 13 NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Continued) adopted, the NOPR on open access transmission would require public utilities under the Federal Power Act to provide open access to their transmission systems and would establish guidelines for their doing so. A final rule would define the terms under which independent power producers, neighboring utilities, and others could gain access to a utility's transmission grid to deliver power to wholesale customers, such as municipal distribution systems, rural electric cooperatives, or other utilities. Under the NOPR, each public utility would also be required to establish separate rates for its transmission and generation services for new wholesale service, and to take transmission services, including ancillary services, under the same tariffs that would be applicable to third-party users for all of its new wholesale sales and purchases of energy. The supplemental NOPR on stranded costs provides a basis for recovery by regulated public utilities of legitimate and verifiable stranded costs associated with existing wholesale requirements customers and retail customers who become unbundled wholesale transmission customers of the utility. The FERC would provide public utilities a mechanism for recovery of stranded costs that result from municipalization, former retail customers becoming wholesale customers, or the loss of a wholesale customer. The FERC will consider allowing recovery of stranded investment costs associated with retail wheeling only if a state regulatory commission lacks the authority to consider that issue. On June 26, 1995, the Company filed transmission tariffs with the FERC that are intended to meet the comparability of service requirements as set out in the NOPR. Concurrently with the comparability filing, e prime, a non- regulated energy services subsidiary of the Company, filed a power marketer application with the FERC. The Company has requested that the transmission tariffs be made effective on August 25, 1995, sixty days from the date of the filing, and that e prime be authorized to make wholesale sales of electric power beginning on that same day. The Company is continuing to evaluate the NOPR to determine its impact on the Company and its customers. It is anticipated that a final rule could take effect in early 1996. The Company cannot predict the outcome of this matter. Environmental Issues Environmental Site Cleanup Under the Comprehensive Environmental Response, Compensation and Liability Act, the Environmental Protection Agency 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 Potentially Responsible Parties ("PRPs"), is involved in the cleanup of this site which began in November 1992 and is expected to be completed during the third quarter of 1995. The total project cost is currently estimated to be approximately $8.9 million. On March 16, 1995, the Denver District Court entered judgment in favor of the Company in the amount of $5.6 million, for costs incurred through January 31, 1995, regarding a lawsuit against one of the Company's insurance providers for the cleanup of this site. Additionally, the Company expects to recover costs incurred subsequent to 14 NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Continued) January 31, 1995 through future insurance claims. The insurance provider has appealed the jury decision. Previously, the Company had received certain insurance settlement proceeds, a portion of which remains to be allocated to this site. 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. Polychlorinated biphenyl ("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 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 incurred through June 30, 1995 have not exceeded $2 million. The amusement park began operations in the second quarter of 1995. 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, results of operations or cash flows. 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 Sulfur Dioxide ("SO2") and Nitrogen Oxide ("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. The estimated costs for future plant modifications total approximately $33 million. The Company is studying its options to reduce SO2 15 NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Continued) 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 the U.S. District Court for the District of Colorado ("U.S. District Court"), pursuant to Section 304 of the Federal Clean Air Act, against the Company and the other joint owners of the Hayden Steam Electric Generating Station. The plaintiff alleges that 1) the station exceeded the 20% opacity limitations in excess of 19,000 six minute intervals during the period extending from the last quarter of 1988 through mid-1993 based on the data and reports obtained from the station's continuous opacity monitors ("COMs"), which measure average emission stream opacity in six minute intervals on a continuous basis, 2) the station was operated for over two weeks in late 1992 without a functioning electrostatic precipitator which constituted a "modification" of the station without the requisite permit from the Colorado Department of Public Health and Environment and 3) the owners failed to operate the station in a manner consistent with good air pollution control practices. The complaint seeks, among other things, civil monetary penalties and injunctive relief. The joint owners of the station contest all of these claims and contend that there were no violations of the opacity limitation, because pursuant to the Colorado state implementation plan ("SIP"), visual emissions are to be measured by qualified personnel using the U.S. Environmental Protection Agency's ("EPA") visual test known as "Method 9" and not by any measurements from the station's COMs as alleged by the plaintiff. Discovery was completed and oral arguments on summary judgment motions were heard in mid-May 1995. On July 21, 1995, the U.S. District Court ordered partial summary judgment of liability in favor of the plaintiff in regards to the claims described in items 1) and 3) above and denied the plaintiff's motion in regards to the claims described in item 2) above. On July 31, 1995, the joint owners filed a petition for an interlocutory appeal with the 10th Circuit Court of Appeals. If the joint owners are not successful in their appeal, the U.S. District Court will determine the appropriate penalties and/or remedies. At this time, the Company is not able to estimate the outcome of the appeal or the amount, if any, of its potential liability. The plaintiff has requested, among other things, that the joint owners "pay to the EPA to finance air compliance and enforcement activities, as provided for by 42 U.S.C. section 7604(g)(1), a penalty of $25,000 per day for each of their violations of the Clean Air Act." The statute provides for penalties of up to $25,000 per day per violation, but the level of penalties imposed in any particular instance is discretionary. In setting penalties in its own enforcement actions, the EPA relies, in part, on such factors as the economic benefit of noncompliance, the actual or possible harm of noncompliance, the size of the violator, the willfulness or negligence of the violator and its degree of cooperation in resolving the matter. The Company cannot predict the level of penalties, if any, or the remedies that the court may impose in the instance if the joint owners are unsuccessful in their appeal. In April 1992, the Company acquired interests in the two generating units at the Hayden station located near Hayden, Colorado. The Company currently is the operator of the Hayden station and owns an undivided interest in each of the two generating units at the station which in total average approximately 53%. Additional pollution control equipment may also be required to be installed at the station. The Company has not recorded any 16 NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Continued) amounts for potential loss contingencies related to this matter. 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. Employee Litigation Several employee lawsuits have been filed against the Company involving alleged sexual/age discrimination. 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, financial position or cash flow. 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. Of the 21 actions filed, the trial court directed verdicts for the Company in 19 cases. Two cases went to a jury which entered verdicts adverse to the Company. All 21 decisions are currently on appeal, but the Company believes its liability, if any, will not have a material impact on the Company's results of operations, financial position or cash flow. 4. Management's Representations In the opinion of the Company, the accompanying unaudited consolidated condensed financial statements include all adjustments necessary for the fair presentation of the financial position of the Company and its subsidiaries at June 30, 1995 and December 31, 1994, and the results of operations for the three and six months ended June 30, 1995 and 1994 and cash flows for the six months ended June 30, 1995 and 1994. The consolidated condensed financial information and notes thereto should be read in conjunction with the consolidated financial statements and notes for the years ended December 31, 1994, 1993 and 1992 included in the Company's 1994 Annual Report filed with the Securities and Exchange Commission on Form 10-K. Because of seasonal and other factors, the results of operations for the three and six month periods ended June 30, 1995 should not be taken as an indication of earnings for all or any part of the balance of the year. 17 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PUBLIC SERVICE COMPANY OF COLORADO We have reviewed the accompanying consolidated condensed balance sheet of Public Service Company of Colorado (a Colorado corporation) and subsidiaries as of June 30, 1995, and the related consolidated condensed statements of income for the three and six month periods ended June 30, 1995 and 1994 and the consolidated condensed statements of cash flows for the six month periods ended June 30, 1995 and 1994. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the financial statements referred to above for them to be in conformity with generally accepted accounting principles. We have previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheet of Public Service Company of Colorado and subsidiaries as of December 31, 1994 (not presented herein), and, in our report dated February 10, 1995, we expressed an unqualified opinion on that statement. In our opinion, the information set forth in the accompanying consolidated condensed balance sheet as of December 31, 1994, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. Our February 10, 1995 report contains an explanatory paragraph that describes the uncertainties related to the adequacy of the Company's recorded liability for defueling and decommissioning the Fort St. Vrain Nuclear Generating Station. As more fully discussed in Note 2 to the consolidated condensed financial statements, the adequacy of the Company's recorded liability for defueling and decommissioning its Fort St. Vrain Nuclear Generating Station (approximately $64.7 million at June 30, 1995) 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 condensed financial statements do not include any adjustments that might result from the outcome of these uncertainties. As more fully discussed in Note 3 to the consolidated condensed financial statements, the Company is a defendant in certain litigation pursuant to Section 304 of the Federal Clean Air Act, involving the Company and the other joint owners of the Hayden Steam Electric Generating Station. The U.S. District Court for the District of Colorado has issued an order providing the plaintiffs with summary judgment on certain claims. The Company has filed a petition for appeal of the decision, the outcome of which is uncertain at this time. Accordingly, no provision for any liabilities that may result from the resolution of this matter have been made in the accompanying consolidated condensed financial statements. 18 ARTHUR ANDERSEN LLP Denver, Colorado, August 4, 1995 19 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Three Months Ended June 30, 1995 Compared to the Three Months Ended June 30, 1994 Earnings Earnings per share were $0.40 for the second quarter of 1995, compared to $0.34 for the second quarter of 1994. The higher earnings were primarily attributed to lower operating and maintenance expenses resulting from cost containment efforts that were implemented in 1994. The Company eliminated approximately 550 management and staff level positions in connection with an internal restructuring and involuntary severance program which was implemented in late 1994. The cost savings from this program, estimated to be approximately $21 million on an annual basis, reduced employee labor and benefit costs for the second quarter of 1995 as discussed below. Through an early retirement/severance program, effective April 1, 1994, the Company reduced its workforce by approximately 550 employees. The salary savings from this program, estimated to be approximately $22 million on an annual basis, lowered employee labor and benefit costs for the first quarter of 1995. Electric Operations The following table details the changes in electric revenues and energy costs for the second quarter of 1995 compared to the same period in 1994.
Increase (Decrease) (Thousands of Dollars) Electric revenues: Retail . . . . . . . . . . . . . . . . . . . . . . . $ 14,870 Wholesale . . . . . . . . . . . . . . . . . . . . . (47) Other (including unbilled revenues) . . . . . . . . (13,287) Total revenues . . . . . . . . . . . . . . . . . . 1,536 Fuel used in generation . . . . . . . . . . . . . . . (4,208) Purchased power . . . . . . . . . . . . . . . . . . . 14,587 Net decrease in electric margin . . . . . . . . . . $ (8,843)
The following schedule compares electric Kwh sales for the second quarter of 1995 and 1994.
Electric Sales (Millions of Kwh) 1995 1994 % Change * Residential . . . . . . . . . . . . . . . 1,455.1 1,387.8 4.8% Commercial and Industrial . . . . . . . . 3,584.9 3,524.1 1.7% Public Authorities . . . . . . . . . . . 40.2 40.3 (0.3%) Other Utilities . . . . . . . . . . . . . 682.8 674.1 1.3% 5,763.0 5,626.3 2.4% * Percentages are calculated using unrounded amounts
20 Retail electric revenues increased approximately $14.9 million during the three months ended June 30, 1995, when compared to the three months ended June 30, 1994, primarily due to increases in billed sales resulting from moderate customer growth and the recovery of net higher costs for purchased power and fuel used in generation. Other electric revenues decreased approximately $13.3 million primarily due to: 1) the recognition of lower unbilled revenues in the current period resulting from the effects of unseasonably cool weather during June 1995, as compared to the record hot weather in June 1994, and 2) the recognition of approximately $5 million in unbilled revenues related to certain energy efficiency credits, following the CPUC's second quarter 1994 decision allowing for the future recovery of such credits. (see Note 3. Commitments and Contingencies - Regulatory Matters in Item 1. FINANCIAL STATEMENTS). 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 costs and allow recovery of such costs on a timely basis. A substantial portion of these net higher costs have been billed to customers, however, the changes in revenues associated with these mechanisms during the second quarters of 1995 and 1994 had little impact on net income. The Company is required to make a filing with the CPUC related to its ECA by September 1, 1995, at which time the CPUC will review whether the ECA should be maintained in its present form, altered or eliminated (See Note 3. Commitments and Contingencies - Regulatory Matters in Item 1. FINANCIAL STATEMENTS). Fuel used in generation expense decreased $4.2 million, or 8.7%, during the second quarter of 1995, compared to the same period in 1994, primarily due to lower generation levels, coupled with a slight reduction in the cost per Kwh which is primarily due to lower transportation costs from the renegotiation of certain coal transportation contracts. Purchased power expense increased $14.6 million, or 14.1%, for the three months ended June 30, 1995, when compared to the same period in 1994, primarily due to increased purchases from qualifying facilities. The cost per Kwh of electric energy purchased from qualifying facilities is over 50% higher than the purchased power costs from other suppliers, further contributing to the increase in purchased power expense. A majority of purchased power costs associated with qualifying facilities is collected through the QFCCA, a cost adjustment mechanism; however, the future recovery of costs under the QFCCA may be subject to an earnings test, which has not yet been defined by the CPUC (See Note 3. Commitments and Contingencies - Regulatory Matters in Item 1. FINANCIAL STATEMENTS). Gas Operations The following table details the changes in gas revenues and gas purchased for resale during the second quarter of 1995 compared to the same period in 1994.
Increase (Decrease) (Thousands of Dollars) Total gas operating revenues . . . . . . . . . . . . $ 17,995 Less: transport, gathering, and processing revenues . (1,871) Revenues from gas sales . . . . . . . . . . . . . . 19,866 Gas purchased for resale . . . . . . . . . . . . . . 18,265 Net increase in gas sales margin . . . . . . . . . . $ 1,601
21 The following schedule compares gas deliveries for the second quarter of 1995 and 1994.
Gas Deliveries (Millions of Mcf) 1995 1994 % Change * Residential . . . . . . . . . . . . . . . 23.9 19.1 25.1% Commercial and Industrial . . . . . . . . 14.4 12.2 18.4% Other Utilities . . . . . . . . . . . . . 0.2 0.2 16.9% Total Gas Sales . . . . . . . . . . . . 38.5 31.5 22.5% Gathered and Processed . . . . . . . . . 0.3 10.8 (96.9%) Transported and Other . . . . . . . . . . 24.5 18.1 35.4% 63.3 60.4 5.0% * Percentages are calculated using unrounded amounts
The $1.6 million increase in gas sales margin during the second quarter of 1995, as compared to the same period of the prior year, is primarily due to the unseasonably cool weather during the second quarter of 1995 and moderate customer growth. A portion of the increase in billed sales resulting from the colder weather was offset by lower unbilled revenue ($4.7 million) during the second quarter of 1995. A decline in transport, gathering and processing revenues reduced gas sales margin by $1.9 million during the second quarter of 1995, as compared to the same period of the prior year. The sale of WestGas Gathering, Inc. in August 1994 resulted in a $2.9 million reduction in gathering revenues during the current period. These lower revenues, however, have been offset, in part, by revenue from higher transport deliveries. The growth in transportation services is primarily due to serving new qualifying facility customers and certain other pipeline customers on a short-term interruptible basis. The Company and Cheyenne 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 the second quarters of 1995 and 1994 had little impact on net income. The increase in gas purchased for resale for the second quarter of 1995, compared to the second quarter of 1994, is due to the higher gas sales, but reflects a 12.5% decrease in the per unit cost of gas. Non-Fuel Operating Expenses Other operating and maintenance expenses decreased $10.8 million during the second quarter of 1995, when compared to the same period in 1994, primarily due to lower labor and employee benefit costs resulting from the employee downsizing accomplished in late 1994 (approximately a $5 million reduction) and the recognition of approximately $5.4 million of involuntary severance costs in the second quarter of 1994. Lower maintenance expenses at the Company's steam generation facilities also contributed to this decrease. Depreciation and amortization expense decreased $1.4 million during the second quarter of 1995, when compared to the same period in 1994, primarily due to the effects of using a longer estimated depreciable life of the Company's electric steam production facilities, consistent with the Company's most recent depreciation study. 22 In December 1991, the Company recorded a $3.0 million incentive award granted by the CPUC for the Company's efforts to secure gas refunds for customers from one of its natural gas suppliers. However, on July 11, 1994, the Colorado Supreme Court reversed the incentive granted by the CPUC. Accordingly, the change in other income and deductions - net for the second quarter of 1995, compared to the second quarter of 1994, is primarily due to the 1994 reversal of this incentive award. Interest charges increased $3.1 million during the second quarter of 1995, when compared to the same period in 1994, primarily due to higher interest rates associated with short-term borrowings and the recognition of interest costs related to the over collection of expenses under the Company's cost adjustment mechanisms. 23 Six Months Ended June 30, 1995 Compared to the Six Months Ended June 30, 1994 Earnings Earnings per share were $1.21 for the first six months of 1995, compared to $1.05 for the first six months of 1994. The higher earnings were primarily attributed to lower operating and maintenance expenses. The lower operating expenses are the result of cost containment efforts that were implemented in 1994, as discussed earlier in the second quarter earnings summary. The reduced employee labor and benefit costs for the first six months of 1995 are discussed below. Electric Operations The following table details the changes in electric revenues and energy costs for the first six months of 1995 compared to the same period in 1994.
Increase (Decrease) (Thousands of Dollars) Electric revenues: Retail . . . . . . . . . . . . . . . . . . . . . . . $ 33,416 Wholesale . . . . . . . . . . . . . . . . . . . . . (3,671) Other (including unbilled revenues) . . . . . . . . (9,910) Total revenues . . . . . . . . . . . . . . . . . . 19,835 Fuel used in generation . . . . . . . . . . . . . . . (10,391) Purchased power . . . . . . . . . . . . . . . . . . . 29,597 Net increase in electric margin . . . . . . . . . . $ 629
The following schedule compares electric Kwh sales for the first six months of 1995 and 1994.
Electric Sales (Millions of Kwh) 1995 1994 % Change * Residential . . . . . . . . . . . . . . . 3,182.6 3,101.2 2.6% Commercial and Industrial . . . . . . . . 7,275.1 7,086.5 2.7% Public Authorities . . . . . . . . . . . 88.6 86.8 2.0% Other Utilities . . . . . . . . . . . . . 1,477.0 1,557.3 (5.2%) 12,023.3 11,831.8 1.6% * Percentages are calculated using unrounded amounts
Retail electric revenues increased $33.4 million for the six months ended June 30, 1995, when compared to the six months ended June 30, 1994, primarily due to increases in billed sales resulting from moderate customer growth and the recovery of net higher costs for purchased power and fuel. Wholesale electric revenues decreased $3.7 million for the six months ended June 30, 1995, when compared to the same period in the prior year, primarily due to a 5.2% decrease in wholesale Kwh sales. The demand for wholesale energy has been negatively impacted by an available supply of low-cost non- firm energy in the region. Other electric revenues decreased approximately $9.9 million primarily due to: 1) the recognition of lower unbilled revenues in the current period 24 resulting from the effects of unseasonably cool weather during June 1995, as compared to the record hot weather in June 1994, and 2) the recognition of approximately $5 million in unbilled revenues related to certain energy efficiency credits, following the CPUC's second quarter 1994 decision allowing for the future recovery of such credits. (see Note 3. Commitments and Contingencies - Regulatory Matters in Item 1. FINANCIAL STATEMENTS). 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 costs and allow recovery of such costs on a timely basis. A substantial portion of these net higher costs have been billed to customers, however, the changes in revenues associated with these mechanisms during the first six months of 1995 and 1994 had little impact on net income. Fuel used in generation expense decreased $10.4 million, or 10.2%, during the first six months in 1995, compared to the same period in 1994, primarily due to a 2.4% decrease in generation, coupled with a slight reduction in the cost per Kwh which is primarily due to lower transportation costs from the renegotiation of certain coal transportation contracts. Purchased power expense increased approximately $29.6 million, or 14.1%, during the six months ended June 30, 1995, when compared to the same period in 1994, primarily due to increased purchases from qualifying facilities. The cost per Kwh of electric energy purchased from qualifying facilities is over 50% higher than the purchased power costs from other suppliers, further contributing to the increase in purchased power expense. A majority of purchased power costs associated with qualifying facilities is collected through the QFCCA, a cost adjustment mechanism; however, the future recovery of costs under the QFCCA may be subject to an earnings test, which has not yet been defined by the CPUC (See Note 3. Commitments and Contingencies - Regulatory Matters in Item 1. FINANCIAL STATEMENTS). Gas Operations The following table details the changes in gas operating revenues and gas purchased for resale for the first six months of 1995 compared to the same period in 1994.
Increase (Decrease) (Thousands of Dollars) Total gas operating revenues . . . . . . . . . . . . $ 7,548 Less: transport, gathering, and processing revenues . (4,411) Revenues from gas sales . . . . . . . . . . . . . . 11,959 Gas purchased for resale . . . . . . . . . . . . . . 8,886 Net increase in gas sales margin . . . . . . . . . . $ 3,073
25 The following schedule compares gas deliveries for the first six months of 1995 and 1994.
Gas Deliveries (Millions of Mcf) 1995 1994 % Change * Residential . . . . . . . . . . . . . . . 64.7 61.6 5.1% Commercial and Industrial . . . . . . . . 37.7 37.3 1.3% Other Utilities . . . . . . . . . . . . . 0.4 0.4 (7.9%) Total Gas Sales . . . . . . . . . . . . 102.8 99.3 3.6% Gathered and Processed . . . . . . . . . 0.8 21.6 (96.5%) Transported and Other . . . . . . . . . . 48.7 40.8 19.3% 152.3 161.7 (5.8%) * Percentages are calculated using unrounded amounts
Gas operating revenues and gas purchased for resale increased during the first six months of 1995, as compared to the same period in the prior year, primarily due to a 3.6% increase in total gas sales resulting from cooler weather during March to June 1995. These increases were offset, in part, by the 96.5% decrease in gathering and processed gas deliveries. The sale of WestGas Gathering, Inc. during 1994 resulted in a $5.5 million reduction in gathering revenues and a 20.7 MMcf reduction in gathering deliveries for the current period. These lower revenues, however, have been offset, in part, by revenues from higher transport deliveries primarily due to servicing new qualifying facility customers. The Company and Cheyenne 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 the first six months of 1995 and 1994 had little impact on net income. The increase in gas purchased for resale for the first six months of 1995, compared to the first six months of 1994, is offset, in part, by a 6.5% decrease in the per unit cost of gas. Non-Fuel Operating Expenses Other operating and maintenance expenses decreased $17.0 million during the first six months of 1995, when compared to the same period in 1994, primarily due to lower labor and employee benefit costs resulting from the restructuring and employee downsizing accomplished in 1994 (approximately a $16 million reduction) and the recognition of approximately $5.4 million of involuntary severance costs in the second quarter of 1994. Lower maintenance expenses at the Company's steam generation facilities also contributed to this decrease. These decreases were offset, in part, by $2.3 million of additional amortization of the early retirement/severance program costs for the six months ended June 30, 1995 and the $2.5 million write-off of certain software costs. Depreciation and amortization expense decreased $3.1 million during the first six months of 1995, when compared to the same period in 1994, primarily due to the effects of using a longer estimated depreciable life of the Company's electric steam production facilities, consistent with the Company's most recent depreciation study. The $4.1 million increase in income tax expense for the first six months of 1995, compared to the same period in 1994, is primarily attributable to higher pre-tax income, but includes additional tax benefits related to certain 26 non-regulated investment activities. Other income and deductions - net decreased $0.9 million during the first six months of 1995, when compared to the same period in 1994, due to the recognition of $2.1 million of the gain on the sale of WestGas Gathering, Inc. as an amount to be refunded to ratepayers in accordance with a first quarter of 1995 settlement agreement as well as from higher contributions, lower interest income and reductions in non-utility income. These decreases were offset, in part, by the reversal of a $3.0 million gas incentive award in the second quarter of 1994, as previously discussed. Interest charges increased $5.5 million during the first six months of 1995, when compared to the same period in 1994, primarily due to higher interest rates associated with short-term borrowings. Commitments and Contingencies Issues relating to Fort St. Vrain, regulatory and environmental matters are discussed in Notes 2 and 3 in Item 1. FINANCIAL STATEMENTS. Liquidity and Capital Resources Cash Flows Cash provided by operating activities increased $98.5 million during the first six months of 1995, when compared to the first six months of 1994, primarily due to higher earnings, lower decommissioning expenditures ($9.3 million) and a significant increase in the recovery of purchased gas and electric energy costs ($46.2 million). At June 30, 1995, the Company's decommissioning liability, excluding defueling, was approximately $40.4 million. The expenditures related to this obligation are expected to be incurred over the next year with final completion of such activities anticipated in the second quarter of 1996. The annual decommissioning amount being recovered from customers is approximately $13.9 million which will continue through June, 2005. At June 30, 1995, approximately $102.4 million remains to be collected from customers and is reflected as a regulatory asset on the consolidated condensed balance sheet. Accordingly, operating cash flows will continue to be negatively impacted until the decommissioning of Fort St. Vrain is complete. Cash used in investing activities increased $36.0 million during the first six months of 1995, when compared to the same period in 1994, primarily due to the June 1995 purchase of Young Gas Storage Company ($6.0 million) (see Item 5. Other Information), the receipts from the sale of certain Fuelco properties during early 1994 ($27.5 million) offset, in part, by a decrease in construction expenditures in 1995 ($9.2 million). Cash used in financing activities increased approximately $52.5 million during the first six months of 1995, when compared to the same period in 1994, primarily due to increased repayments of short-term borrowings during the current year ($61.9 million) compared to additional short-term borrowings in 1994. Proceeds from the sale of common stock under the Company's dividend reinvestment and stock purchase plan decreased in the first six months of 1995 to $13.8 million as compared to the proceeds of approximately $22.3 million from issuances under such plan in the first six months of 1994. Long-term debt refinancing activity in the first six months of 1995,as compared to 1994, has decreased as a result of higher interest rates. Net decreases in the maturities of long-term debt and issuances of long-term debt have reduced, in part, the net amount of cash used in financing activities by $20.1 million. 27 Common Stock Dividend On June 27, 1995, the Company's Board of Directors declared a quarterly dividend on its common stock of $0.51 per share, up from $0.50 per share for the previous year. The Company's common stock dividend level is dependent upon the Company's results of operations, financial position, cash flow and other factors, and will continue to be evaluated quarterly by the Board of Directors. 28 PART II - OTHER INFORMATION Item 1. Legal Proceedings Part 1. Issues relating to the recovery of energy efficiency credits, environmental site cleanup and other environmental matters are discussed in Note 3. Commitments and Contingencies in Item 1, Part 1. Item 4. Submission of Matters to a Vote of Security Holders (a) The 1995 Annual Meeting of Shareholders of the Company took place on May 11, 1995. (b) Two matters were voted upon at the meeting: 1) the election of directors; and 2) the appointment of Arthur Andersen LLP as the Company's independent public accountants.
With respect to the election of directors, the votes were as follows: Wayne H. Brunetti 52,247,763 shares for 1,884,998 shares withheld Collis P. Chandler, Jr. 52,517,907 shares for 1,614,854 shares withheld Doris M. Drury, PhD 52,441,491 shares for 1,691,270 shares withheld Thomas T. Farley 52,529,641 shares for 1,603,120 shares withheld Gayle L. Greer 52,356,778 shares for 1,775,983 shares withheld A. Barry Hirschfeld 52,434,448 shares for 1,698,313 shares withheld D. D. Hock 52,143,290 shares for 1,989,471 shares withheld George B. McKinley 52,466,502 shares for 1,666,259 shares withheld Will F. Nicholson, Jr. 52,516,579 shares for 1,616,182 shares withheld J. Michael Powers 52,552,211 shares for 1,580,550 shares withheld Thomas E. Rodriguez 52,470,590 shares for 1,662,171 shares withheld Rodney E. Slifer 52,563,926 shares for 1,568,835 shares withheld W. Thomas Stephens 52,555,822 shares for 1,576,939 shares withheld Robert G. Tointon 52,537,269 shares for 1,595,492 shares withheld With respect to the appointment of Arthur Andersen LLP, the vote was: 52,443,250 shares for; 911,779 shares against; 777,732 shares abstain. There were zero broker non-votes.
Item 5. Other Information On June 27, 1995, the Company purchased all of the outstanding common stock of Young Gas Storage Company (YGSC) for $6 million. YGSC owns a 47.5% interest in a partnership which owns and operates gas storage facilities located in northeastern Colorado. Item 6. Exhibits and Reports on Form 8-K (a) Exhibits 12(a) - Computation of Ratio of Consolidated Earnings to Consolidated Fixed Charges is set forth at page 29 herein. 12(b) - Computation of Ratio of Consolidated Earnings to Consolidated Combined Fixed Charges and Preferred Stock Dividends is set forth at page 30 herein. 29 15 - Letter from Arthur Andersen LLP regarding unaudited interim information is set forth at page 31 herein. 27 - Financial Data Schedule UT (b) Reports on Form 8-K No reports on Form 8-K were filed during the second quarter of 1995. 30 SIGNATURE 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. PUBLIC SERVICE COMPANY OF COLORADO /s/ R. C. KELLY __________________________ R. C. Kelly Senior Vice President, Finance, Treasurer and Chief Financial Officer Dated: August 10, 1995 31 EXHIBIT INDEX 12(a) - Computation of Ratio of Consolidated Earnings to Consolidated Fixed Charges is set forth at page 29 herein. 12(b) - Computation of Ratio of Consolidated Earnings to Consolidated Combined Fixed Charges and Preferred Stock Dividends is set forth at page 30 herein. 15 - Letter from Arthur Andersen LLP regarding unaudited interim information is set forth at page 31 herein. 27 - Financial Data Schedule UT 32 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)
Six Months Ended June 30, 1995 1994 (Thousands of Dollars, except ratios) Fixed charges: Interest on long-term debt . . . . . . . . . . . . . . $ 42,843 $ 45,183 Interest on borrowings against corporate-owned life insurance contracts . . . . . . 16,601 14,206 Other interest . . . . . . . . . . . . . . . . . . . . 11,110 5,780 Amortization of debt discount and expense less premium 1,597 1,528 Interest component of rental expense . . . . . . . . . 3,403 3,690 Total . . . . . . . . . . . . . . . . . . . . . . $ 75,554 $ 70,387 Earnings (before fixed charges and taxes on income): Net income . . . . . . . . . . . . . . . . . . . . . . $ 81,899 $ 70,404 Fixed charges as above . . . . . . . . . . . . . . . . 75,554 70,387 Provisions for Federal and state taxes on income, net of investment tax credit amortization . . . . . . 41,988 37,928 Total . . . . . . . . . . . . . . . . . . . . . . . $ 199,441 $ 178,719 Ratio of earnings to fixed charges . . . . . . . . . . . 2.64 2.54
33 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)
Six Months Ended June 30, 1995 1994 (Thousands of Dollars, except ratios) Fixed charges and preferred stock dividends: Interest on long-term debt . . . . . . . . . . . . . . $ 42,843 $ 45,183 Interest on borrowings against corporate-owned life insurance contracts . . . . . . 16,601 14,206 Other interest . . . . . . . . . . . . . . . . . . . . 11,110 5,780 Amortization of debt discount and expense less premium 1,597 1,528 Interest component of rental expense . . . . . . . . . 3,403 3,690 Preferred stock dividend requirement . . . . . . . . . 6,001 6,010 Additional preferred stock dividend requirement . . . . 3,076 3,238 Total . . . . . . . . . . . . . . . . . . . . . . $ 84,631 $ 79,635 Earnings (before fixed charges and taxes on income): Net income . . . . . . . . . . . . . . . . . . . . . . $ 81,899 $ 70,404 Interest on long-term debt . . . . . . . . . . . . . . 42,843 45,183 Interest on borrowings against corporate-owned life insurance contracts . . . . . . 16,601 14,206 Other interest . . . . . . . . . . . . . . . . . . . . 11,110 5,780 Amortization of debt discount and expense less premium 1,597 1,528 Interest component of rental expense . . . . . . . . . 3,403 3,690 Provisions for Federal and state taxes on income, net of investment tax credit amortization . . . . . . 41,988 37,928 Total . . . . . . . . . . . . . . . . . . . . . . . $ 199,441 $ 178,719 Ratio of earnings to fixed charges and preferred stock dividends . . . . . . . . . . . . . . . . . . . . . . . 2.36 2.24
34 EXHIBIT 15 August 4, 1995 Public Service Company of Colorado: We are aware that Public Service Company of Colorado has incorporated by reference in its 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, its Form 10-Q for the quarter ended June 30, 1995, which includes our report dated August 4, 1995, covering the unaudited consolidated condensed financial statements contained therein. Pursuant to Regulation C of the Securities Act of 1933, that report is not considered a part of the registration statement prepared or certified by our firm or a report prepared or certified by our firm within the meaning of Sections 7 and 11 of the Act. Very truly yours, ARTHUR ANDERSEN LLP 35 EX-27 2
UT This Schedule contains summary Financial information extracted from Public Service Company of Colorado and Subsidiaries consolidated condensed balance sheet as of June 30, 1995 and consolidated condensed statements of income and cash flows for the six months ended June 30, 1995 and is qualified in its entirety by reference to such financial statements. 6-MOS DEC-31-1994 JUN-30-1995 PER-BOOK 3,358,412 25,055 423,651 380,388 0 4,187,506 314,617 668,269 320,048 1,302,934 42,665 140,008 1,081,746 40,200 0 246,100 83,174 2,576 0 0 1,248,103 4,187,506 1,119,295 41,988 176,548 964,972 154,323 (1,924) 152,399 70,500 81,899 6,001 75,898 64,064 0 246,276 1.21 1.21