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 March 31, 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 May 5, 1995, 62,886,427 shares of the registrant's Common Stock,
$5.00 par value (the only class of common stock), were outstanding.
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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 . . . . . . . . 16
PART II - OTHER INFORMATION
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . 20
Item 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . . . . . . 20
SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
EXHIBIT INDEX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
EXHIBIT 12(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
EXHIBIT 12(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
EXHIBIT 15 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
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PART 1 - FINANCIAL INFORMATION
Item 1. Financial Statements
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Thousands of Dollars)
ASSETS
<TABLE>
<CAPTION>
March 31, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
Property, plant and equipment, at cost:
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,679,849 $ 3,641,711
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 877,767 867,239
Steam and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87,892 86,458
Common to all departments . . . . . . . . . . . . . . . . . . . . . . . . . . 384,851 369,070
Construction in progress . . . . . . . . . . . . . . . . . . . . . . . . . . 183,974 187,577
5,214,333 5,152,055
Less: accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . 1,892,200 1,860,653
Total property, plant and equipment . . . . . . . . . . . . . . . . . . . 3,322,133 3,291,402
Investments, at cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,013 18,202
Current assets:
Cash and temporary cash investments . . . . . . . . . . . . . . . . . . . . . 13,468 5,883
Accounts receivable, less reserve for
uncollectible accounts ($3,365 at March 31, 1995;
$3,173 at December 31, 1994) . . . . . . . . . . . . . . . . . . . . . . . 157,868 163,465
Accrued unbilled revenues . . . . . . . . . . . . . . . . . . . . . . . . . . 81,665 86,106
Recoverable purchased gas and electric
energy costs - net . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 37,979
Materials and supplies, at average cost . . . . . . . . . . . . . . . . . . . 65,321 67,600
Fuel inventory, at average cost . . . . . . . . . . . . . . . . . . . . . . . 34,346 31,370
Gas in underground storage, at cost (LIFO) . . . . . . . . . . . . . . . . . 16,807 42,355
Current portion of accumulated deferred income taxes . . . . . . . . . . . . 29,184 20,709
Regulatory assets recoverable within one year (Note 1) . . . . . . . . . . . 39,810 39,985
Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . . . 9,196 16,312
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . 447,665 511,764
Deferred charges:
Regulatory assets (Note 1) . . . . . . . . . . . . . . . . . . . . . . . . . 330,389 335,893
Unamortized debt expense . . . . . . . . . . . . . . . . . . . . . . . . . . 10,842 11,073
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44,524 39,498
Total deferred charges . . . . . . . . . . . . . . . . . . . . . . . . . . 385,755 386,464
$ 4,172,566 $ 4,207,832
The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.
</TABLE>
1
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PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Thousands of Dollars)
CAPITAL AND LIABILITIES
<TABLE>
<CAPTION>
March 31, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
Common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 975,914 $ 959,268
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 326,884 308,214
Total common equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,302,798 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,138,712 1,155,427
2,624,183 2,605,582
Noncurrent liabilities:
Defueling and decommissioning liability (Note 2) . . . . . . . . . . . . . . 35,246 40,605
Employees' postretirement benefits other
than pensions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47,103 42,106
Employees' postemployment benefits . . . . . . . . . . . . . . . . . . . . . 20,975 20,975
Total noncurrent liabilities . . . . . . . . . . . . . . . . . . . . . . . 103,324 103,686
Current liabilities:
Notes payable and commercial paper . . . . . . . . . . . . . . . . . . . . . 264,760 324,800
Long-term debt due within one year . . . . . . . . . . . . . . . . . . . . . 20,047 25,153
Preferred stock subject to mandatory
redemption within one year . . . . . . . . . . . . . . . . . . . . . . . 2,576 2,576
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138,522 177,031
Dividends payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34,974 34,078
Recovered purchased gas and electric energy costs - net . . . . . . . . . . . 10,176 -
Customers' deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,843 17,099
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109,120 54,148
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,038 32,265
Current portion of defueling and decommissioning
liability (Note 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35,909 36,365
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56,675 62,640
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . 712,640 766,155
Deferred credits:
Customers' advances for construction . . . . . . . . . . . . . . . . . . . . 100,800 96,442
Unamortized investment tax credits . . . . . . . . . . . . . . . . . . . . . 117,288 118,532
Accumulated deferred income taxes . . . . . . . . . . . . . . . . . . . . . . 482,058 485,668
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,273 31,767
Total deferred credits . . . . . . . . . . . . . . . . . . . . . . . . . . 732,419 732,409
Commitments and contingencies (Notes 2 and 3) . . . . . . . . . . . . . . . . . .
$ 4,172,566 $ 4,207,832
The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.
</TABLE>
2
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PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(Unaudited)
(Thousands of Dollars except per share data)
<TABLE>
<CAPTION>
Three Months Ended March 31,
1995 1994
<S> <C> <C>
Operating revenues:
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 366,583 $ 348,284
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 244,557 255,004
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,456 9,148
620,596 612,436
Operating expenses:
Fuel used in generation . . . . . . . . . . . . . . . . . . . . . . . . . . . 47,185 53,368
Purchased power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121,478 106,468
Gas purchased for resale . . . . . . . . . . . . . . . . . . . . . . . . . . 168,135 177,514
Other operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . 89,814 94,264
Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,704 16,433
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . 35,166 36,918
Taxes (other than income taxes) . . . . . . . . . . . . . . . . . . . . . . . 23,091 22,679
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29,334 26,362
528,907 534,006
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91,689 78,430
Other income and deductions:
Allowance for equity funds used during construction . . . . . . . . . . . . . 751 1,065
Miscellaneous income and deductions - net . . . . . . . . . . . . . . . . . (3,883) (438)
(3,132) 627
Interest charges:
Interest on long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . 21,506 23,165
Amortization of debt discount and expense less premium . . . . . . . . . . . 791 726
Other interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,308 9,396
Allowance for borrowed funds used during construction . . . . . . . . . . . . (692) (759)
34,913 32,528
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53,644 46,529
Dividend requirements on preferred stock . . . . . . . . . . . . . . . . . . . . 3,001 3,005
Earnings available for common stock . . . . . . . . . . . . . . . . . . . . . . . $ 50,643 $ 43,524
Weighted average common shares outstanding (thousands) . . . . . . . . . . . . . 62,513 60,919
Earnings per weighted average
share of common stock outstanding . . . . . . . . . . . . . . . . . . . . . . $ 0.81 $ 0.71
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.
</TABLE>
3
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PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
(Thousands of Dollars)
<TABLE>
<CAPTION>
Three Months Ended March 31,
1995 1994
<S> <C> <C>
Operating activities:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 53,644 $ 46,529
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . 36,148 37,083
Amortization of investment tax credits . . . . . . . . . . . . . . . . (1,244) (1,267)
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . (8,725) 10,180
Allowance for equity funds used during construction . . . . . . . . . . (751) (1,065)
Change in accounts receivable . . . . . . . . . . . . . . . . . . . . . 5,597 (4,031)
Change in inventories . . . . . . . . . . . . . . . . . . . . . . . . . 24,851 31,491
Change in other current assets . . . . . . . . . . . . . . . . . . . . 49,221 31,630
Change in accounts payable . . . . . . . . . . . . . . . . . . . . . . (38,509) (48,531)
Change in other current liabilities . . . . . . . . . . . . . . . . . . 59,067 40,604
Change in deferred amounts . . . . . . . . . . . . . . . . . . . . . . (1,012) (53,381)
Change in noncurrent liabilities . . . . . . . . . . . . . . . . . . . (362) 22,196
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 17
Net cash provided by operating activities . . . . . . . . . . . . . 177,950 111,455
Investing activities:
Construction expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . (62,005) (57,757)
Allowance for equity funds used during construction . . . . . . . . . . . . . 751 1,065
Proceeds from (cost of) disposition of property, plant and equipment . . . . (1,059) 27,888
Purchase of other investments . . . . . . . . . . . . . . . . . . . . . . . . (454) (117)
Sale of other investments . . . . . . . . . . . . . . . . . . . . . . . . . . 1,618 1,695
Net cash used in investing activities . . . . . . . . . . . . . . . (61,149) (27,226)
Financing activities:
Proceeds from sale of common stock . . . . . . . . . . . . . . . . . . . . . 6,823 10,851
Proceeds from sale of long-term debt . . . . . . . . . . . . . . . . . . . . - 217,093
Redemption of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . (21,921) (244,851)
Short-term borrowings - net . . . . . . . . . . . . . . . . . . . . . . . . . (60,040) (37,065)
Dividends on common stock . . . . . . . . . . . . . . . . . . . . . . . . . . (31,077) (30,229)
Dividends on preferred stock . . . . . . . . . . . . . . . . . . . . . . . . (3,001) (3,005)
Net cash used in financing activities . . . . . . . . . . . . . . . (109,216) (87,206)
Net increase (decrease) in cash and temporary
cash investments . . . . . . . . . . . . . . . . . . . . . . . . . 7,585 (2,977)
Cash and temporary cash investments at
beginning of period . . . . . . . . . . . . . . . . . . . . . . . . 5,883 18,038
Cash and temporary cash investments at
end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 13,468 $ 15,061
The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.
</TABLE>
4
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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 Statements 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.
5
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
The following regulatory assets are reflected in the Company's
consolidated condensed balance sheets:
<TABLE>
<CAPTION>
March 31, December 31, Recovery
1995 1994 Through
(Thousands of Dollars)
<S> <C> <C> <C>
Nuclear decommissioning costs (Note 2) $ 104,874 $ 107,374 2005
Income taxes . . . . . . . . . . . . . 122,472 125,832 2006
Employees' postretirement benefits other
than pensions . . . . . . . . . . . . 40,079 37,573 2013
Early retirement costs . . . . . . . . 30,865 33,124 1998
Employees' postemployment benefits . . 20,975 20,975 Undetermined
Demand-side management costs . . . . . 21,691 20,831 2001
Unamortized debt reacquisition costs . 21,869 22,360 2024
Other . . . . . . . . . . . . . . . . . 7,374 7,809 1999
Total . . . . . . . . . . . . . . . . 370,199 375,878
Classified as current . . . . . . . . . 39,810 39,985
Classified as noncurrent . . . . . . . $ 330,389 $ 335,893
</TABLE>
Certain costs associated with the Company's Demand Side Management
("DSM") programs are deferred and recovered in rates over a seven-year
period through the Demand Side Management Cost Adjustment ("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
6
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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. 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 issuance (approximately $0.1 million
in 1995 and $0.2 million in 1994), were issued to certain executives.
These estimated issuance values were recognized in other operating
expenses during the respective preceding years. 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.
7
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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.
The final radiation survey report of the repowering area has been
completed and submitted to the Nuclear Regulatory Commission ("NRC"). The
Company reported survey data meets unrestricted release criteria
permitting such area to be released. The Company believes the final
radiation survey report will be approved by the NRC in the second quarter
of 1995.
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 March 31, 1995, approximately
$104.9 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 annual 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 March 31, 1995, approximately 75% of the
decommissioning process has been performed with final completion of such
activities anticipated in the second quarter of 1996.
8
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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.
Most recently, 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.
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
9
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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.
Most recently, the DOE has required that an Environmental Impact
Statement ("EIS") be completed relative to, among other things, the
receipt and storage of spent fuel at the Idaho facility. In April 1995,
the DOE issued an EIS and anticipates a final record of decision in June
1995. 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.
Modifications to the Idaho facility will be required to accommodate the
new spent fuel shipping casks. These modifications would be completed
subsequent to the finalization 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 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 March 31, 1995, approximately
$290.6 million has been spent for such activities with the remaining $71.2
million defueling and decommissioning liability reflected on the
consolidated condensed balance sheet ($24.7 million - defueling; $46.5
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 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
10
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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 March 31,
1995, the letter of credit had been reduced to $61 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 March
31, 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 assessments 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.
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
11
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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 $282 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. 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
August 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") with collection estimated to
begin July 1, 1995. At March 31, 1995, the Company has recognized
approximately $7.5 million of unbilled revenue related to these credits.
12
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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.
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 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 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 mechanisms. On March 29, 1995, the CPUC issued a revised
procedural schedule requiring direct testimony and exhibits to be filed by
June 15, 1995, with hearings scheduled for September 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
effective December 1, 1993. The OCC 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. On April 11, 1995, the Denver District Court
affirmed the CPUC's decision on this matter.
On August 1, 1994, the Company filed its Phase II testimony. The
13
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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.
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 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 exiting 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.
The Company is currently evaluating the NOPR to determine its impact
on the Company and its customers. Comments on the NOPR are due August 7,
1995. 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
14
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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
second 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 January 31, 1995 through future insurance
claims. The insurance provider has appealed the jury decision.
Previously, the Company had received approximately $1.8 million of
insurance 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 March 31, 1995 have not exceeded
$2 million. The amusement park is scheduled to begin 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
15
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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 SO 2
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
penalties and injunctive relief. At this time the Company is not able to
estimate the amount, if any, of its potential liability. The Company
believes additional particulate control equipment will be necessary, but
final determination has not been made. Discovery has been completed, oral
arguments on summary judgment motions are scheduled for mid-May 1995 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.
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
16
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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 March 31, 1995 and December 31, 1994, and
the results of operations and cash flows for the three months ended March
31, 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 month period ended March 31, 1995 should not be taken as an
indication of earnings for all or any part of the balance of the year.
17
<PAGE>
<PAGE>
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 March 31, 1995, and the related consolidated condensed
statements of income and cash flows for the three month periods ended
March 31, 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 $71.2 million at March 31, 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.
ARTHUR ANDERSEN LLP
Denver, Colorado,
May 5, 1995
18
<PAGE>
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Earnings
Earnings per share were $0.81 for the first quarter of 1995,
compared to $0.71 for the first quarter of 1994. The higher earnings
resulted primarily from higher retail electric Kwh sales and lower
operating expenses. The lower operating expenses have resulted from cost
reduction strategies implemented in 1994. During the first quarter of
1994, an early retirement/severance program was offered with approximately
550 employees electing to participate, effective April 1, 1994. Annual
salary savings are expected to be approximately $22 million. In addition,
in conjunction with an internal restructuring, an involuntary severance
program was implemented in late 1994 in which approximately 550 management
and staff level positions were eliminated resulting in an additional
estimated annual salary savings of approximately $21 million. These
programs have substantially reduced employee labor and benefit costs for
the first quarter of 1995 as discussed below.
Electric Operations
The following table details the changes in electric revenues and
energy costs for the first three months of 1995 compared to the same
period in 1994.
<TABLE>
<CAPTION>
Increase (Decrease)
(Thousands of Dollars)
<S> <C>
Electric revenues:
Retail . . . . . . . . . . . . . . . . . . . . . . . $ 18,546
Wholesale . . . . . . . . . . . . . . . . . . . . . (3,624)
Other . . . . . . . . . . . . . . . . . . . . . . . 3,377
Total revenues . . . . . . . . . . . . . . . . . . 18,299
Fuel used in generation . . . . . . . . . . . . . . . (6,183)
Purchased power . . . . . . . . . . . . . . . . . . . 15,010
Net increase in electric margin . . . . . . . . . . $ 9,472
</TABLE>
19
<PAGE>
<PAGE>
The following schedule compares electric Kwh sales for the first
quarter of 1995 and 1994.
<TABLE>
<CAPTION>
Electric Sales
(Millions of Kwh)
1995 1994 % Change *
<S> <C> <C> <C>
Residential . . . . . . . . . . . . . . . 1,727.6 1,713.4 0.8%
Commercial and Industrial . . . . . . . . 3,690.2 3,562.4 3.6%
Public Authorities . . . . . . . . . . . 48.4 46.5 4.0%
Other Utilities . . . . . . . . . . . . . 794.2 883.2 (10.1%)
6,260.4 6,205.5 0.9%
* Percentages are calculated using unrounded amounts
</TABLE>
Electric operating revenues increased $18.3 million for the three
months ended March 31, 1995, when compared to the three months ended March
31, 1994, primarily due to a 3.6% increase in commercial and industrial
Kwh sales resulting from moderate customer growth. The increase in retail
electric revenues was offset, in part, by a 10.1% 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.
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 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 4. Commitments and Contingencies -Regulatory
Matters in Item 1. FINANCIAL STATEMENTS).
Fuel used in generation expense decreased $6.2 million, or 11.6%,
for the first three months in 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 $15.0 million, or 14.1%, for the three
months ended March 31, 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
approximately 58% 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 4.
Commitments and Contingencies - Regulatory Matters in Item 1. FINANCIAL
20
<PAGE>
<PAGE>
STATEMENTS).
Gas Operations
The following table details the change in gas revenues and gas
purchased for resale for the first three months of 1995 compared to the
same period in 1994.
<TABLE>
<CAPTION> Increase (Decrease)
(Thousands of Dollars)
<S> <C>
Total gas revenues . . . . . . . . . . . . . . . . . $(10,447)
Less: transport, gathering, and processing revenues . (2,540)
Revenues from gas sales . . . . . . . . . . . . . . (7,907)
Gas purchased for resale . . . . . . . . . . . . . . (9,379)
Net increase in gas sales margin . . . . . . . . . . $ 1,472
</TABLE>
The following schedule compares gas deliveries for the first quarter
of 1995 and 1994.
<TABLE>
<CAPTION>
Gas Deliveries
(Millions of Mcf)
1995 1994 % Change *
<S> <C> <C> <C>
Residential . . . . . . . . . . . . . . . 40.8 42.5 (3.9%)
Commercial and Industrial . . . . . . . . 23.3 25.1 (7.0%)
Other Utilities . . . . . . . . . . . . . 0.2 0.2 (27.8%)
Total Gas Sales . . . . . . . . . . . . 64.3 67.8 (5.1%)
Gathered and Processed . . . . . . . . . 0.4 10.8 (96.0%)
Transported and Other . . . . . . . . . . 24.2 22.7 6.4%
88.9 101.3 (12.2%)
* Percentages are calculated using unrounded amounts
</TABLE>
Gas operating revenues and gas purchased for resale decreased the
first three months of 1995, as compared to the same period in the prior
year, primarily due to a 12.2% decrease in total gas deliveries. The sale
of WestGas Gathering, Inc. during 1994 has resulted in a $2.5 million
decline in gathering revenues for the current period. These lower
revenues, however, have been offset, in part, by higher transport
deliveries. The growth in transportation services is primarily due to
servicing new qualifying facility customers.
The Company and its regulated subsidiary 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
quarters of 1995 and 1994 had little impact on net income. The decrease
21
<PAGE>
<PAGE>
in gas purchased for resale for the first quarter in 1995, compared to the
first quarter in 1994, is partially due to a 6.1% decrease in the per-unit
cost of gas.
Non-Fuel Operating Expenses
Other operating and maintenance expenses decreased $6.2 million
during the first quarter of 1995, when compared to the same period in
1994, primarily due to lower labor and employee benefit costs resulting
from the 1994 restructuring efforts totaling approximately $12 million.
These decreases were offset, in part, by the $2.2 million amortization of
the early retirement/severance program costs and the $2.5 million write-
off of certain software costs.
Depreciation and amortization expense decreased $1.8 million during
the first 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.
The increase in income tax expense for the first quarter of 1995,
compared to the same period in 1994, is primarily attributable to higher
pre-tax income.
Other income and deductions decreased $3.8 million during the first
quarter of 1995, when compared to the first quarter of 1994, primarily 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 recent settlement agreement, as well as from lower interest income
($0.6 million) and additional charitable contributions ($0.7 million).
Interest charges increased $2.4 million for the first quarter of
1995, when compared to the same period in 1994, primarily due to higher
interest rates for 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 $66.5 million during
the first quarter of 1995, when compared to the first quarter of 1994,
primarily due to higher earnings, lower decommissioning expenditures ($8.2
million) and a significant increase in the recovery of purchased gas and
electric energy costs ($25.5 million). At March 31, 1995, the Company's
decommissioning liability was approximately $46.7 million. The majority
of 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
22
<PAGE>
<PAGE>
recovered from customers is approximately $13.9 million which will
continue through June, 2005. At March 31, 1995, approximately $104.9
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 $33.9 million during the
first quarter of 1995, when compared to the same period in 1994, primarily
due to increased construction expenditures in 1995 ($4.2 million) and the
receipts from the sale of certain Fuelco properties during 1994 ($27.5
million).
Cash used in financing activities increased approximately $22.0
million during the first quarter of 1995, when compared to the same period
in 1994, primarily due to increased repayments of short-term borrowings
($23.0 million). Additionally, proceeds from the sale of common stock
under the Company's dividend reinvestment and stock purchase plan
decreased in the first quarter of 1995 to $6.8 million as compared to the
proceeds of approximately $10.9 million from issuances under such plan in
the first quarter of 1994.
Common Stock Dividend
On March 28, 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 quarter. The Company's common stock dividend
level is dependent upon the Company's results of operations, financial
position, cash flow and other factors. It will continue to be evaluated
quarterly by the Board of Directors.
23
<PAGE>
<PAGE>
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Part 1. Issues relating to the Company's 1993 rate case and
environmental site cleanup are discussed in Note 3.
Commitments and Contingencies in Item 1, Part 1.
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 23
herein.
12(b) - Computation of Ratio of Consolidated Earnings to
Consolidated Combined Fixed Charges and Preferred Stock
Dividends is set forth at page 24 herein.
15 - Letter from Arthur Andersen LLP regarding unaudited
interim information is set forth at page 25 herein.
27 - Financial Data Schedule UT
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the first quarter of 1995.
24
<PAGE>
<PAGE>
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: May 10, 1995
25
<PAGE>
<PAGE>
EXHIBIT INDEX
12(a) - Computation of Ratio of Consolidated Earnings to
Consolidated Fixed Charges is set forth at page 23
herein.
12(b) - Computation of Ratio of Consolidated Earnings to
Consolidated Combined Fixed Charges and Preferred Stock
Dividends is set forth at page 24 herein.
15 - Letter from Arthur Andersen LLP regarding unaudited
interim information is set forth at page 25 herein.
27 - Financial Data Schedule UT
26
<PAGE>
<PAGE>
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)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
1995 1994
(Thousands of Dollars,
except ratios)
<S> <C> <C>
Fixed charges:
Interest on long-term debt . . . . . . . . . . . . . . $ 21,506 $ 23,165
Interest on borrowings against
corporate-owned life insurance contracts . . . . . . 7,969 6,802
Other interest . . . . . . . . . . . . . . . . . . . . 5,339 2,594
Amortization of debt discount and expense less premium 791 726
Interest component of rental expense . . . . . . . . . 1,690 1,880
Total . . . . . . . . . . . . . . . . . . . . . . $ 37,295 $ 35,167
Earnings (before fixed charges and taxes on income):
Net income . . . . . . . . . . . . . . . . . . . . . . $ 53,644 $ 46,529
Fixed charges as above . . . . . . . . . . . . . . . . 37,295 35,167
Provisions for Federal and state taxes on income,
net of investment tax credit amortization . . . . . . 29,334 26,362
Total . . . . . . . . . . . . . . . . . . . . . . . $ 120,273 $ 108,058
Ratio of earnings to fixed charges . . . . . . . . . . . 3.22 3.07
</TABLE>
27
<PAGE>
<PAGE>
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)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
1995 1994
(Thousands of Dollars,
except ratios)
<S> <C> <C>
Fixed charges and preferred stock dividends:
Interest on long-term debt . . . . . . . . . . . . . . $ 21,506 $ 23,165
Interest on borrowings against
corporate-owned life insurance contracts . . . . . . 7,969 6,802
Other interest . . . . . . . . . . . . . . . . . . . . 5,339 2,594
Amortization of debt discount and expense less premium 791 726
Interest component of rental expense . . . . . . . . . 1,690 1,880
Preferred stock dividend requirement . . . . . . . . . 3,001 3,005
Additional preferred stock dividend requirement . . . . 1,641 1,703
Total . . . . . . . . . . . . . . . . . . . . . . $ 41,937 $ 39,875
Earnings (before fixed charges and taxes on income):
Net income . . . . . . . . . . . . . . . . . . . . . . $ 53,644 $ 46,529
Interest on long-term debt . . . . . . . . . . . . . . 21,506 23,165
Interest on borrowings against
corporate-owned life insurance contracts . . . . . . 7,969 6,802
Other interest . . . . . . . . . . . . . . . . . . . . 5,339 2,594
Amortization of debt discount and expense less premium 791 726
Interest component of rental expense . . . . . . . . . 1,690 1,880
Provisions for Federal and state taxes on income,
net of investment tax credit amortization . . . . . . 29,334 26,362
Total . . . . . . . . . . . . . . . . . . . . . . . $ 120,273 $ 108,058
Ratio of earnings to fixed charges and preferred stock
dividends . . . . . . . . . . . . . . . . . . . . . . . 2.87 2.71
</TABLE>
28
<PAGE>
<PAGE>
EXHIBIT 15
May 5, 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 March 31, 1995, which includes our report
dated May 5, 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
29
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PUBLIC
SERVICE COMPANY OF COLORADO AND SUBSIDIAIRES CONSOLIDATED CONDENSED BALANCE
SHEET AS OF MARCH 31, 1995 AND CONSOLIDATED CONDENSED STATEMENTS OF INCOME AND
CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 1995 AND IS QUALIFIED IN ITS
ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> MAR-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,322,133
<OTHER-PROPERTY-AND-INVEST> 17,013
<TOTAL-CURRENT-ASSETS> 447,665
<TOTAL-DEFERRED-CHARGES> 385,755
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,172,566
<COMMON> 313,465
<CAPITAL-SURPLUS-PAID-IN> 662,449
<RETAINED-EARNINGS> 326,884
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,302,798
42,665
140,008
<LONG-TERM-DEBT-NET> 1,138,712
<SHORT-TERM-NOTES> 40,360
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 224,400
<LONG-TERM-DEBT-CURRENT-PORT> 20,047
2,576
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,261,000
<TOT-CAPITALIZATION-AND-LIAB> 4,172,566
<GROSS-OPERATING-REVENUE> 620,596
<INCOME-TAX-EXPENSE> 29,334
<OTHER-OPERATING-EXPENSES> 89,814
<TOTAL-OPERATING-EXPENSES> 528,907
<OPERATING-INCOME-LOSS> 91,689
<OTHER-INCOME-NET> (3,132)
<INCOME-BEFORE-INTEREST-EXPEN> 88,557
<TOTAL-INTEREST-EXPENSE> 34,913
<NET-INCOME> 53,644
3,001
<EARNINGS-AVAILABLE-FOR-COMM> 50,643
<COMMON-STOCK-DIVIDENDS> 31,973
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 177,950
<EPS-PRIMARY> 0.81
<EPS-DILUTED> 0.81
</TABLE>
