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 September 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 November 7, 1995, 63,328,979 shares of the registrant's Common
Stock, $5.00 par value (the only class of common stock), were outstanding.
PAGE
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 . . . . . . . . 21
PART II - OTHER INFORMATION
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . 29
Item 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . . . . . . 29
SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
EXHIBIT INDEX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
EXHIBIT 12(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
EXHIBIT 12(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
EXHIBIT 15 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
PAGE
PART 1 - FINANCIAL INFORMATION
Item 1. Financial Statements
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Thousands of Dollars)
ASSETS
September 30, December 31,
1995 1994
(Unaudited)
Property, plant and equipment, at cost:
Electric . . . . . . . . . . . . . . . . . . . . . . $3,780,902 $3,641,711
Gas . . . . . . . . . . . . . . . . . . . . . . . . 909,840 867,239
Steam and other . . . . . . . . . . . . . . . . . . 88,651 86,458
Common to all departments . . . . . . . . . . . . . 381,057 369,070
Construction in progress . . . . . . . . . . . . . . 195,149 187,577
5,355,599 5,152,055
Less: accumulated depreciation . . . . . . . . . . . 1,952,296 1,860,653
Total property, plant and equipment . . . . . . . 3,403,303 3,291,402
Investments, at cost . . . . . . . . . . . . . . . . . 20,287 18,202
Current assets:
Cash and temporary cash investments . . . . . . . . 6,287 5,883
Accounts receivable, less reserve for
uncollectible accounts ($4,098 at September 30,
1995; $3,173 at December 31, 1994) . . . . . . . . 135,459 163,465
Accrued unbilled revenues . . . . . . . . . . . . . 83,870 86,106
Recoverable purchased gas and electric
energy costs - net . . . . . . . . . . . . . . . . - 37,979
Materials and supplies, at average cost . . . . . . 59,417 67,600
Fuel inventory, at average cost . . . . . . . . . . 34,486 31,370
Gas in underground storage, at cost (LIFO) . . . . . 44,483 42,355
Current portion of accumulated deferred income taxes 38,118 20,709
Regulatory assets recoverable within one year (Note 1) 39,708 39,985
Prepaid expenses and other . . . . . . . . . . . . . 14,531 16,312
Total current assets . . . . . . . . . . . . . . . 456,359 511,764
Deferred charges:
Regulatory assets (Note 1) . . . . . . . . . . . . . 326,381 335,893
Unamortized debt expense . . . . . . . . . . . . . . 10,477 11,073
Other . . . . . . . . . . . . . . . . . . . . . . . 50,362 39,498
Total deferred charges . . . . . . . . . . . . . . 387,220 386,464
$4,267,169 $4,207,832
The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.
1
PAGE
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Thousands of Dollars)
CAPITAL AND LIABILITIES
September 30, December 31,
1995 1994
(Unaudited)
Common stock . . . . . . . . . . . . . . . . . . . . . . $ 990,237 $ 959,268
Retained earnings . . . . . . . . . . . . . . . . . . . . 330,656 308,214
Total common equity . . . . . . . . . . . . . . . . . 1,320,893 1,267,482
Preferred stock:
Not subject to mandatory redemption . . . . . . . . . 140,008 140,008
Subject to mandatory redemption at par . . . . . . . . 41,289 42,665
Long-term debt . . . . . . . . . . . . . . . . . . . . . 1,080,442 1,155,427
2,582,632 2,605,582
Noncurrent liabilities:
Defueling and decommissioning liability (Note 2) . . . 23,934 40,605
Employees' postretirement benefits other
than pensions . . . . . . . . . . . . . . . . . . . 48,838 42,106
Employees' postemployment benefits . . . . . . . . . . 20,975 20,975
Total noncurrent liabilities . . . . . . . . . . . . 93,747 103,686
Current liabilities:
Notes payable and commercial paper . . . . . . . . . . 315,200 324,800
Long-term debt due within one year . . . . . . . . . . 83,287 25,153
Preferred stock subject to mandatory
redemption within one year . . . . . . . . . . . . . 2,576 2,576
Accounts payable . . . . . . . . . . . . . . . . . . . 129,049 177,031
Dividends payable . . . . . . . . . . . . . . . . . . 35,211 34,078
Recovered purchased gas and electric energy costs - net 15,719 -
Gas refund liability . . . . . . . . . . . . . . . . . 80,249 7,210
Customers' deposits . . . . . . . . . . . . . . . . . 17,585 17,099
Accrued taxes . . . . . . . . . . . . . . . . . . . . 50,206 54,148
Accrued interest . . . . . . . . . . . . . . . . . . . 21,613 32,265
Current portion of defueling and decommissioning
liability (Note 2) . . . . . . . . . . . . . . . . . 31,571 36,365
Other . . . . . . . . . . . . . . . . . . . . . . . . 46,870 55,430
Total current liabilities . . . . . . . . . . . . . 829,136 766,155
Deferred credits:
Customers' advances for construction . . . . . . . . . 109,834 96,442
Unamortized investment tax credits . . . . . . . . . . 114,801 118,532
Accumulated deferred income taxes . . . . . . . . . . 506,683 485,668
Other . . . . . . . . . . . . . . . . . . . . . . . . 30,336 31,767
Total deferred credits . . . . . . . . . . . . . . . 761,654 732,409
Commitments and contingencies (Notes 2 and 3) . . . . . .
$ 4,267,169 $4,207,832
The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.
2
PAGE
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(Unaudited)
(Thousands of Dollars except per share data)
Three Months Ended
September 30,
1995 1994
Operating revenues:
Electric . . . . . . . . . . . . . . . . . . . . . . . $ 378,241 $ 355,306
Gas . . . . . . . . . . . . . . . . . . . . . . . . . 81,946 68,940
Other . . . . . . . . . . . . . . . . . . . . . . . . 8,266 7,708
468,453 431,954
Operating expenses:
Fuel used in generation . . . . . . . . . . . . . . . 46,770 50,342
Purchased power . . . . . . . . . . . . . . . . . . . 123,634 109,556
Gas purchased for resale . . . . . . . . . . . . . . . 37,219 33,252
Other operating expenses . . . . . . . . . . . . . . . 84,181 88,714
Maintenance . . . . . . . . . . . . . . . . . . . . . 16,109 15,386
Defueling and decommissioning (Note 2) . . . . . . . . - 43,376
Depreciation and amortization . . . . . . . . . . . . 35,442 36,431
Taxes (other than income taxes) . . . . . . . . . . . 20,461 20,531
Income taxes (Note 5) . . . . . . . . . . . . . . . . 23,568 (13,235)
387,384 384,353
Operating income . . . . . . . . . . . . . . . . . . . . 81,069 47,601
Other income and deductions:
Allowance for equity funds used during construction . 952 708
Gain on sale of WestGas Gathering, Inc. (Note 6) . . . - 34,485
Miscellaneous income and deductions - net . . . . . . 469 (364)
1,421 34,829
Interest charges:
Interest on long-term debt . . . . . . . . . . . . . . 21,367 21,919
Amortization of debt discount and expense less premium 816 796
Other interest . . . . . . . . . . . . . . . . . . . . 15,312 11,480
Allowance for borrowed funds used during construction (824) (819)
36,671 33,376
Net income . . . . . . . . . . . . . . . . . . . . . . . 45,819 49,054
Dividend requirements on preferred stock . . . . . . . . 2,991 3,003
Earnings available for common stock . . . . . . . . . . . $ 42,828 $ 46,051
Weighted average common shares outstanding (thousands) . 63,077 61,779
Earnings per weighted average
share of common stock outstanding . . . . . . . . . . $ 0.68 $ 0.75
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
PAGE
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(Unaudited)
(Thousands of Dollars except per share data)
Nine Months Ended
September 30,
1995 1994
Operating revenues:
Electric . . . . . . . . . . . . . . . . . . . . . . . $ 1,086,340 $1,043,570
Gas . . . . . . . . . . . . . . . . . . . . . . . . . 474,815 454,261
Other . . . . . . . . . . . . . . . . . . . . . . . . 26,593 24,122
1,587,748 1,521,953
Operating expenses:
Fuel used in generation . . . . . . . . . . . . . . . 137,890 151,853
Purchased power . . . . . . . . . . . . . . . . . . . 363,095 319,420
Gas purchased for resale . . . . . . . . . . . . . . . 307,518 294,665
Other operating expenses . . . . . . . . . . . . . . . 260,729 278,618
Maintenance . . . . . . . . . . . . . . . . . . . . . 46,969 49,888
Defueling and decommissioning (Note 2) . . . . . . . . - 43,376
Depreciation and amortization . . . . . . . . . . . . 105,635 109,731
Taxes (other than income taxes) . . . . . . . . . . . 64,964 65,651
Income taxes (Note 5) . . . . . . . . . . . . . . . . 65,556 24,693
1,352,356 1,337,895
Operating income . . . . . . . . . . . . . . . . . . . . 235,392 184,058
Other income and deductions:
Allowance for equity funds used during construction . 2,810 2,851
Gain on sale of WestGas Gathering, Inc. (Note 6) . . . - 34,485
Miscellaneous income and deductions - net . . . . . . (3,313) (3,514)
(503) 33,822
Interest charges:
Interest on long-term debt . . . . . . . . . . . . . . 64,210 67,102
Amortization of debt discount and expense less premium 2,413 2,324
Other interest . . . . . . . . . . . . . . . . . . . . 43,023 31,466
Allowance for borrowed funds used during construction (2,475) (2,470)
107,171 98,422
Net income . . . . . . . . . . . . . . . . . . . . . . . 127,718 119,458
Dividend requirements on preferred stock . . . . . . . . 8,992 9,013
Earnings available for common stock . . . . . . . . . . . $ 118,726 $ 110,445
Weighted average common shares outstanding (thousands) . 62,812 61,374
Earnings per weighted average
share of common stock outstanding . . . . . . . . . . $ 1.89 $ 1.80
Dividends per share declared on common stock . . . . . . $ 1.53 $ 1.50
The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.
4
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PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
(Thousands of Dollars)
Nine Months Ended
September 30,
1995 1994
Operating activities:
Net income . . . . . . . . . . . . . . . . . . . . . . $ 127,718 $ 119,458
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization . . . . . . . . . . 108,611 111,927
Defueling and decommissioning expenses . . . . . . - 43,376
Gain on sale of WestGas Gathering, Inc. . . . . . - (34,485)
Amortization of investment tax credits . . . . . . (3,731) (4,210)
Deferred income taxes . . . . . . . . . . . . . . 13,369 20,185
Allowance for equity funds used during construction (2,810) (2,851)
Change in accounts receivable . . . . . . . . . . 28,006 35,414
Change in inventories . . . . . . . . . . . . . . 2,939 8,304
Change in other current assets . . . . . . . . . . 40,868 43,403
Change in accounts payable . . . . . . . . . . . . (47,982) (81,679)
Change in other current liabilities . . . . . . . 71,119 (41,623)
Change in deferred amounts . . . . . . . . . . . . (8,446) (38,732)
Change in noncurrent liabilities . . . . . . . . . (9,939) 12,145
Other . . . . . . . . . . . . . . . . . . . . . . (393) 62
Net cash provided by operating activities . . . 319,329 190,694
Investing activities:
Construction expenditures . . . . . . . . . . . . . . (209,096) (202,172)
Allowance for equity funds used during construction . 2,810 2,851
Proceeds from sale of WestGas Gathering, Inc. . . . . - 87,000
Proceeds from disposition of property, plant
and equipment . . . . . . . . . . . . . . . . . . . . 297 38,889
Purchase of other investments . . . . . . . . . . . . (7,280) (513)
Sale of other investments . . . . . . . . . . . . . . 5,588 1,521
Net cash used in investing activities . . . . . (207,681) (72,424)
Financing activities:
Proceeds from sale of common stock . . . . . . . . . . 21,145 30,799
Proceeds from sale of long-term debt . . . . . . . . . 22,135 244,448
Redemption of long-term debt . . . . . . . . . . . . . (39,405) (281,199)
Short-term borrowings - net . . . . . . . . . . . . . (9,600) (21,200)
Redemption of preferred stock . . . . . . . . . . . . (1,376) (213)
Dividends on common stock . . . . . . . . . . . . . . (95,141) (91,590)
Dividends on preferred stock . . . . . . . . . . . . . (9,002) (9,015)
Net cash used in financing activities . . . . . (111,244) (127,970)
Net increase (decrease) in cash and
temporary cash investments . . . . . . . . . . 404 (9,700)
Cash and temporary cash investments at
beginning of period . . . . . . . . . . . . . 5,883 18,038
Cash and temporary cash investments at
end of period . . . . . . . . . . . . . . . . $ 6,287 $ 8,338
The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.
5
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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.
See Note 4. Merger for discussion of the Company's agreement to merge with
Southwestern Public Service Company ("SPS").
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,
7
PAGE
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
financial position or cash flow.
The following regulatory assets are reflected in the Company's
consolidated condensed balance sheets:
September 30, December 31, Recovery
1995 1994 Through
(Thousands of Dollars)
Nuclear decommissioning costs (Note 2) $ 100,064 $ 107,374 2005
Income taxes . . . . . . . . . . . . . 116,068 125,832 2006
Employees' postretirement benefits
other than pensions . . . . . . . . . 45,094 37,573 2013
Early retirement costs . . . . . . . . 26,581 33,124 1998
Employees' postemployment benefits . . 20,975 20,975 Undetermined
Demand-side management costs . . . . . 28,376 20,831 2002
Unamortized debt reacquisition costs . 22,446 22,360 2024
Other . . . . . . . . . . . . . . . . . 6,486 7,809 1999
Total . . . . . . . . . . . . . . . . 366,089 375,878
Classified as current . . . . . . . . . 39,708 39,985
Classified as noncurrent . . . . . . . $ 326,381 $ 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
8
PAGE
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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 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
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. Prior to 1986, the Company's investment in Fort St. Vrain
had been 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. 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 in the process of repowering Fort St. Vrain following
the July 1, 1994 CPUC 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 totaling 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
9
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
the final radiation survey report of the repowering area prepared by the
Company. 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 September 30, 1995,
approximately $100.1 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 September 30, 1995,
approximately 87% of the decommissioning process has been performed with
final completion of such activities anticipated in mid-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.
During the third quarter of 1995, the Company and the
decommissioning contractors reached an agreement resolving all issues
related to the identification of radioactive material created by
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
activation in the lower portion of the reactor. As part of this
agreement, the Company will pay the contractors an additional $8 million.
While the Company has agreed to this change in work scope, a revision in
the defueling and decommissioning liability has not been required as the
most recent cost estimate, prior to such change, included a contingency
provision. Such provision was sufficient to cover the cost of the
additional scope change.
In the event additional costs are identified, which relate to an
issue excepted from the October 25, 1994 agreement, the decommissioning
contractors will perform all required activities on a cost basis. While
the October 25, 1994 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 a provision
to store additional spent fuel segments if storage space exists) and (b)
the disposal of segment 9 at a Federal repository, resolution of all spent
fuel disposal issues has been substantially delayed due to failure by the
DOE to meet legal requirements relating to storage. While the plant was
operating and as part of routine refueling procedures, three spent fuel
segments (segments 1 - 3) were transported to the Idaho facility. It is
currently estimated that the Federal repository will not be available
until 2010. The Company, however, has been pursuing with the DOE the
storage of all spent fuel segments at the Idaho facility.
During 1995, the Company and the DOE have had various discussions
regarding the issues related to the disposal of Fort St. Vrain s spent
nuclear fuel and, on October 18, 1995, the parties reached an agreement in
principle resolving such issues. In summary, the primary provisions of
the agreement include the following.
- Subject to certification by the Company regarding the contents of
the ISFSI, DOE will take title to fuel segments 4 - 9, which, as
noted above, currently reside in the facility.
- DOE will pay the Company $16 million of the costs of the ISFSI,
with title to the ISFSI passing to the DOE at such time as all
applicable legal requirements for title transfer (including NRC
licensing) are met. DOE will deposit $14 million of the $16 million
into an interest bearing trust/escrow account established by the
Company and approved by the DOE. The initial $2 million will be paid
to the Company on the effective date of the contract.
- Until the time title to the ISFSI transfers to the DOE, the
Company shall be entitled to payments of $2 million per year
(escalated annually pursuant to the Consumer Price Index) plus ISFSI
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(Continued)
operating and maintenance costs including licensing fees and other
regulatory costs, facility support and maintenance and reasonable
insurance costs. On the date title transfers, the Company will be
entitled to the remaining funds (principal and interest) in the
escrow account.
- The term of the agreement will be for a period of up to 15 years,
with one 5 year option to extend. If such option to extend is
exercised, the annual payments increase to $4 million (unescalated).
The DOE has the option to terminate the agreement after the first 8
years.
- The DOE will be responsible for the decommissioning of the ISFSI
with the Company being responsible for costs only up to the amount
currently contained in its existing NRC required escrow account.
Such amount at September 30, 1995 was approximately $1.7 million.
- The Company provides to DOE, among other things, a full and
complete release of claims against DOE arising out of the contracts
discussed above related to spent fuel storage.
While the Company and the DOE have reached this agreement in
principle resolving all issues between them related to the disposal of
Fort St. Vrain's spent nuclear fuel, a formal contract, prepared by an
assigned contracting officer of the DOE, must be executed among the
Company and the DOE to consummate such agreement. This process has been
initiated and it is expected to be completed as soon as practicable.
During 1994, as a result of increased uncertainties related to the
ultimate disposal of Fort St. Vrain's spent nuclear fuel, the Company
recognized 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
were 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 September 30, 1995,
approximately $306.3 million has been spent for such activities with the
remaining $55.5 million defueling and decommissioning liability reflected
on the consolidated condensed balance sheet ($16 million - defueling;
$39.5 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, (which the agreement in principle between the Company and the
DOE discussed above is intended to resolve) 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,
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(Continued)
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 September 30,
1995, the letter of credit had been reduced to $43 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.
As previously discussed, the Company has established a separate
decommissioning trust for the ISFSI which had funds of approximately $1.7
million at September 30, 1995. It is anticipated that this amount,
together with the expected earnings on the funds, will be sufficient to
decommission the ISFSI.
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.
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
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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
1995 Merger Rate Filings
In connection with the merger with SPS, on November 9, 1995 the
Company filed comprehensive proposals with the CPUC, the FERC and the
WPSC. The CPUC proposal included, among other things, implementing an
electric rate moratorium for five years, allowing for the sharing of
earnings in excess of 12.5% return on equity (determined utilizing the
combined operations of the electric, gas and steam departments) on a 50/50
basis between shareholders and customers, retaining the Company's Energy
Cost Adjustment ("ECA"), Gas Cost Adjustment ("GCA"), and Qualifying
Facility Capacity Cost Adjustment ("QFCCA") mechanisms, implementing
quality of service measures and recovering costs incurred in connection
with the merger (See Note 4).
The quality of service measures included in the CPUC proposal relate
to the following four areas: 1) customer complaints, 2) phone response
time to customer inquiries, 3) response time to customer initiated gas
odor complaints, and 4) electric service availability. In the event that
the Company does not meet the proposed quality of service measures,
earnings may be reduced by up to $4 million on an annual basis.
Additionally, the proposed sharing of earnings in excess of 12.5%
return on equity would supersede the QFCCA earnings test discussed below.
Electric and Gas Cost Adjustment Mechanisms
The Company's ECA was revised and a new QFCCA 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 is currently being defined by the CPUC.
At an October 16, 1995 meeting, the CPUC reached the following preliminary
conclusions related to the earnings test associated with the QFCCA: 1) an
earnings test will be implemented with a 50/50 sharing between the
ratepayers and shareholders of earnings in excess of 11%, the Company's
authorized rate of return on regulated common equity; 2) the calculation
will be based on the Company's electric department earnings only, and 3)
implementation will be on a prospective basis effective October 1, 1996,
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
utilizing a test period for the prior twelve months ended June 30, unless
superseded by a CPUC decision prior to the effective date. A final
decision on this matter is expected before year-end 1995.
During 1994, the CPUC initiated proceedings for reviewing the
justness and reasonableness of GCA and ECA mechanisms used by gas and
electric utilities within its jurisdiction. 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. With respect
to the ECA, in compliance with an order issued by the CPUC in March 1995,
the Company completed a filing on September 1, 1995 requesting the CPUC to
open a docket to investigate its ECA. The CPUC opened a docket and will
review whether the ECA should be maintained in its present form, altered
or eliminated. Hearings concerning the ECA will be held in April 1996.
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 (approximately $6.7 million). Through September 30, 1995,
approximately $1.4 million has been collected. To date, the Company has
recognized approximately $8.9 million of revenue related to these credits
($7.5 million unbilled). If the OCC is successful in its appeal, the
Company could be required to reverse these unbilled revenues and refund to
customers the amounts previously collected. This matter will be decided
in late 1995 or early 1996 by the Denver District Court based on the
written pleadings submitted in October 1995.
Incentive Regulation and Demand Side Management
A docket to investigate alternative annual revenue reconciliation
mechanisms and incentive mechanisms related to the Company's demand side
management ("DSM") programs remains open with the CPUC. A technical
working group was formed in 1994 to study and analyze various mechanisms
for 1996 through 1998, which would replace existing DSM incentives until
another mechanism or regulatory approach is approved by the CPUC. 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. Direct
testimony and exhibits were filed by the Company on June 15, 1995.
Hearings occurred in September 1995 and the Company subsequently filed a
statement of position with the CPUC on October 10, 1995. At its October
27, 1995 open meeting, the CPUC determined: 1) not to go forward with any
of the proposed mechanisms, 2) to reduce the recovery period for certain
costs of the Company's DSM programs from seven to five years, 3) not to
set DSM targets for 1997 and 1998, and 4) not to adopt a penalty for
failure to achieve DSM targets. A final order is expected prior to year-
end 1995.
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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 and, on
August 21, 1995, the CPUC issued a final decision approving the agreement.
The new gas rates were implemented effective October 1, 1995. A decision
on the Phase II proceedings related to electric rates was issued on
November 2, 1995 with new rates expected to be effective in early 1996.
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 place 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 ("PSCo Tariffs"). Concurrently with the
comparability filing, e prime, a non-regulated energy services subsidiary
of the Company, filed a power marketer application with the FERC.
Subsequently on August 18, 1995, Cheyenne filed transmission tariffs with
the FERC that are intended to meet the NOPR comparability of service
requirements ("Cheyenne Tariffs"). In an order issued on October 13,
1995, the FERC accepted the PSCo Tariffs and the Cheyenne Tariffs, subject
to modification based on the outcome of the NOPR proceeding, effective as
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
of August 25, 1995. The FERC also set the rates in the PSCo Tariffs and
Cheyenne Tariffs for hearing. The FERC has not yet acted on the e prime
power marketer application.
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
Overview
As described below, the Company has been or is currently involved
with the clean-up of contamination from certain hazardous substances. In
all situations, the Company is pursuing or intends to pursue insurance
claims and believes it will recover some portion of these costs through
such claims. Additionally, where applicable, the Company intends to
pursue recovery from other potentially responsible parties. To the extent
such costs are not recovered, the Company currently believes it is
probable that such costs will be recovered through the rate regulatory
process. However, as part of its merger filings (see discussion in
Regulatory Matters - 1995 Merger Rate Filings) the Company has proposed
implementing an electric rate moratorium for five years, and if its
regulatory authorities accept this proposal, the likelihood of the
recovery of such clean-up costs through the regulatory process may be
diminished.
Environmental Site Cleanup
Under the Comprehensive Environmental Response, Compensation and
Liability Act, the Environmental Protection Agency ("EPA") has identified,
and a Phase II environmental assessment has revealed, low level,
widespread contamination from hazardous substances at the Barter Metals
Company properties located in central Denver. For an estimated 30 years,
the Company sold scrap metal and electrical equipment to Barter for
reprocessing. The Company has completed the cleanup of this site which
began in November 1992. The cost of such clean-up was approximately $8.8
million as of September 30, 1995. On March 16, 1995, in a lawsuit by the
Company against its insurance providers the Denver District Court entered
judgment in favor of the Company in the amount of $5.6 million for certain
clean up costs at Barter. One of the insurance providers and the Company
have appealed the Court's judgment to the Colorado Court of Appeals. The
insurance provider has posted supersedeas bonds in the amount of $9.7
million ($7.7 million attributable to the Barter judgment), but the
Company has objected to certain conditions in the bonds which remain to be
resolved. Previously, the Company has received certain insurance
settlement proceeds from other insurance providers for Barter and other
contaminated sites and a portion of those funds remains to be allocated to
this site by the trial court. In addition, the Company expects to recoup
additional expenditures by sale of the Barter property.
Polychlorinated biphenyl ("PCB") presence was 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
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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 offer of settlement
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.
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 $29 million. The Company
is studying its options to reduce SO2 emissions and currently does not
anticipate that these regulations will significantly impact its
operations.
In April 1992, the Company acquired interests in the two generating
units at the Hayden Steam Electric Generating 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%.
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 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
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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 EPA's 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 entered partial summary judgment on liability issues 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. On August
21, 1995, the joint owners' petition for permission to appeal was denied.
Subsequent to the denial of the joint owners' petition, the U.S. District
Court dismissed the plaintiffs claims described in item 2) above. The
joint owners are pursuing a settlement with the conservation organization
as well as considering further appeals. If settlement is not reached,
court hearings for injunctive relief, scheduled for May 1996, and the
determination of penalties, not yet scheduled, will be held.
At this time, the Company is not able to estimate 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
if settlement is not reached or if the joint owners are unsuccessful in a
subsequent appeal.
Additional pollution control equipment and practices may also be
required at the station. The additional equipment and practices would be
designed to address particulate matter, sulfur dioxide and nitrogen oxide
emission concerns raised by this litigation and by the Mt. Zirkel
Wilderness Area Reasonable Attribution Study previously reported, which is
not yet complete. The Company is evaluating the economic impact of adding
such pollution control equipment and practices on future plant operations.
The Company has received and responded to a request from the EPA for
information relating to the operation of the plant, including information
with respect to opacity emissions.
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 (see the discussion of merger
related regulatory issues included in "Environmental Issues-Overview").
19
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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 in favor of 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.
Union Contract
In August 1995, the Company notified the International Brotherhood
of Electrical Workers, Local 111, that it was cancelling the current
bargaining agreements with Local 111 upon the contracts' expiration in
early December 1995. The Company is currently negotiating with union
leadership and expects to reach new agreements acceptable to the Company
and the union. Approximately 2,150 employees or 45% of the Company's
total workforce, are represented by Local 111.
4. Merger
On August 22, 1995, the Company, SPS, and M-P New Co., a newly
formed Delaware corporation, entered into an Agreement and Plan of
Reorganization ("Merger Agreement") providing for a business combination
as peer firms involving the Company and SPS in a "merger of equals"
transaction (the "Merger"). M-P New Co. will be a registered public
utility holding company which will be the parent company for the Company
and SPS.
The Merger, which was unanimously approved by the Boards of
Directors of the constituent companies, is expected to occur shortly after
all of the conditions to the consummation of the Merger, including
obtaining applicable regulatory and shareholder approvals, are met or
waived. The shareholder meetings to vote upon the Merger will be convened
as soon as practicable and are expected to be held in the first quarter of
1996. The regulatory approval process is expected to take approximately
12 to 16 months from the date the Merger Agreement was announced.
Under the terms of the Merger Agreement, each outstanding share of
the Company's Common Stock will be canceled and converted into the right
to receive one share of M-P New Co. Common Stock, and each outstanding
share of SPS Common Stock will be canceled and converted into the right to
receive 0.95 of one share of M-P New Co. Common Stock. As of August 4,
1995, the Company had 63.1 million common shares outstanding and SPS had
40.9 million common shares outstanding. Based on such capitalization, the
Merger would result in the common shareholders of the Company owning 61.9%
of the common equity of M-P New Co. and the common shareholders of SPS
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
owning 38.1% of the common equity of M-P New Co. The Merger Agreement and
the Merger will not affect the debt, including mortgage bonds, and shares
of preferred stock of the Company and SPS which are outstanding at the
time of the Merger.
It is anticipated that M-P New Co. will adopt the SPS dividend
payment level, adjusted for the exchange ratio, resulting in a pro forma
dividend of $2.32 per share on an annual basis, following completion of
the Merger. The actual dividend level will be dependent upon M-P New
Co.'s results of operations, financial position, cash flows and other
factors, and will be evaluated by the Board of Directors.
Based on 1994 results, M-P New Co. will have combined annual
revenues of approximately $3 billion and total assets of approximately $6
billion. The Company and SPS project synergy savings of approximately
$770 million in the first 10 years after the transaction is completed.
PSCo and SPS estimate that approximately 50 percent of the total projected
savings would result from labor cost savings through the elimination of
duplicate functions. It is expected that employee reductions would be
approximately 8% of the combined work force, or approximately 550 to 600
positions. The remainder would fall under non-labor savings, which would
include approximately 20 percent through deferral of additional capacity
and 20 percent from efficiencies in fuel procurement. The proposed
allocation of the net savings between ratepayers and shareholders was
submitted to regulatory agencies in connection with the November 9, 1995
merger rate filings as discussed in Note 3. A transition management team,
consisting of executives from each company, has been formed and is working
toward the common goal of creating one company with integrated operations
to achieve a more efficient and economic utilization of facilities and
resources. It is managements' intention that the new company begin
realizing certain savings upon the consummation of the Merger and,
accordingly, costs associated with the Merger and the transition planning
and implementation are expected to negatively impact earnings for the
remainder of 1995 and 1996. During the third quarter of 1995, the Company
recognized approximately $1.8 million of costs associated with the Merger.
The Merger is expected to qualify as a tax-free reorganization and as a
pooling of interests for accounting purposes.
The Company recognizes that the divestiture of its existing gas
business or certain non-utility ventures is a possibility under the new
registered holding company structure, but will seek approval from the
Securities and Exchange Commission ("SEC") to maintain these businesses.
If divestiture is ultimately required, the SEC has historically allowed
companies sufficient time to accomplish divestitures in a manner that
protects shareholder value. Additionally, in the event that divestiture
of the gas business is required, the Company will pursue an alternative
corporate organizational structure that will permit retention of the gas
business.
5. Income Taxes
During the third quarter 1994, as a result of the completion of a
detailed analysis of its income tax accounts, the Company recorded a
decrease in its income tax liabilities which served to reduce income tax
expense by approximately $21.3 million or 34 cents per share. The
detailed analysis was completed in conjunction with the Company's
21
PAGE
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
implementation of the full normalization method of accounting for income
taxes as provided for in a recent rate order from the CPUC.
6. Sale of WestGas Gathering, Inc.
During the third quarter 1994, the Company sold all of the
outstanding common stock of its wholly-owned subsidiary, WestGas
Gathering, Inc. ("WGG") and certain related operating assets of the
Company which are used by WGG for approximately $87 million. The Company
recognized a pre-tax gain of approximately $34.5 million ($19.5 million
after-tax or approximately 31 cents per share). During the first quarter
of 1995, the Company recognized $2.1 million of this gain as an amount to
be refunded to the ratepayers in accordance with a 1995 settlement
agreement which addressed the regulatory treatment of the gain.
7. 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 September 30, 1995 and December 31, 1994,
and the results of operations for the three and nine months ended
September 30, 1995 and 1994 and cash flows for the nine months ended
September 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 nine month periods ended September 30, 1995 should not be
taken as an indication of earnings for all or any part of the balance of
the year.
22
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 September 30, 1995, and the related consolidated
condensed statements of income for the three and nine month periods ended
September 30, 1995 and 1994 and the consolidated condensed statements of
cash flows for the nine month periods ended September 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 $55.5 million at September 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
joint owners are pursuing a settlement as well as considering further
23
PAGE
appeals, the outcomes of which are uncertain. 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.
ARTHUR ANDERSEN LLP
Denver, Colorado,
November 10, 1995
24
PAGE
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Three Months Ended September 30, 1995 Compared to the Three Months Ended
September 30, 1994
Earnings
Earnings per share were $0.68 for the third quarter of 1995,
compared to $0.75 for the third quarter of 1994. While the third quarter
1995 earnings declined slightly, higher electric and gas sales and lower
operating and maintenance expenses positively impacted the quarter.
Unseasonably cool weather during September 1995, coupled with moderate
customer growth were the primary factors contributing to the higher sales.
Earnings for the third quarter of 1994 included the net effects of three
one-time items which served to increase earnings for that period by
approximately $0.22 per share. These one-time items included: 1) the
$34.5 million gain on the sale of WGG and certain related operating
assets, 2) a tax accrual adjustment of $21.3 million which positively
impacted earnings, and 3) additional expenses aggregating $43.4 million
primarily for increased costs associated with the defueling and
decommissioning of the Fort St. Vrain generating station.
Electric Operations
The following table details the changes in electric operating
revenues and energy costs for the third quarter of 1995 as compared to the
same period in 1994.
Increase (Decrease)
(Thousands of Dollars)
Electric operating revenues:
Retail . . . . . . . . . . . . . . . . . . . . . . . $ 23,469
Wholesale . . . . . . . . . . . . . . . . . . . . . (2,157)
Other (including unbilled revenues) . . . . . . . . 1,623
Total revenues . . . . . . . . . . . . . . . . . . 22,935
Fuel used in generation . . . . . . . . . . . . . . . (3,572)
Purchased power . . . . . . . . . . . . . . . . . . . 14,078
Net increase in electric margin . . . . . . . . . . $ 12,429
25
The following schedule compares electric Kwh sales for the third
quarters of 1995 and 1994.
Electric Sales
(Millions of Kwh)
1995 1994 %
Change *
Residential . . . . . . . . . . . . . . . 1,563.6 1,491.7 4.8%
Commercial and Industrial . . . . . . . . 4,045.1 3,896.4 3.8%
Public Authorities . . . . . . . . . . . 47.8 48.6
(1.5%)
Other Utilities . . . . . . . . . . . . . 715.1 768.0
(6.9%)
6,371.6 6,204.7 2.7%
* Percentages are calculated using unrounded amounts
Retail electric revenues increased approximately $23.5 million
during the three months ended September 30, 1995, when compared to the
three months ended September 30, 1994, primarily due to an overall 4.0%
increase in retail sales resulting from moderate customer growth with
demand for electricity reaching a record peak of 4,380 megawatts on August
11, 1995. Additionally, the recovery of higher costs for purchased power
through various cost adjustment mechanisms described below also
contributed to the higher revenues. Wholesale electric revenues declined
$2.2 million, when compared to the same period in the prior year,
primarily due to a 6.9% decrease in electric 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 third quarters of 1995 and 1994 had little
impact on net income. The CPUC requested that a filing be prepared by the
Company to 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). On September 1,
1995, in response to a CPUC order, the Company made a filing with the CPUC
related to retaining the ECA.
Fuel used in generation expense decreased $3.6 million, or 7.1%,
during the third quarter of 1995, as compared to the same period in 1994,
primarily due to a 2% decrease in generation, coupled with a slight
reduction in the cost per Kwh. Lower coal costs resulted primarily from
the renegotiation of certain coal purchase contracts. Purchased power
expense increased $14.1 million, or 12.9%, for the three months ended
26
September 30, 1995, when compared to the same period in 1994, primarily
due to increased purchases from qualifying facilities as mandated by the
CPUC. 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 is being addressed 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 during the third quarter of 1995 as compared
to the same period in 1994.
Increase (Decrease)
(Thousands of Dollars)
Gas operating revenues . . . . . . . . . . . . . . . $ 13,006
Less: transport, gathering, and processing revenues . (1,765)
Revenues from gas sales . . . . . . . . . . . . . . 14,771
Gas purchased for resale . . . . . . . . . . . . . . 3,967
Net increase in gas sales margin . . . . . . . . . . $ 10,804
The following schedule compares gas deliveries for the third
quarters of 1995 and 1994.
Gas Deliveries
(Millions of Mcf)
1995 1994 % Change *
Residential . . . . . . . . . . . . . . . 7.8 6.8 14.8%
Commercial and Industrial . . . . . . . . 6.6 5.4 24.8%
Total Gas Sales . . . . . . . . . . . . 14.4 12.2 18.5%
Gathered and Processed . . . . . . . . . 0.4 7.6 (95.1%)
Transported and Other . . . . . . . . . . 20.6 16.2 27.3%
35.4 36.0 (1.5%)
* Percentages are calculated using unrounded amounts
27
PAGE
The $10.8 million increase in gas sales margin during the third
quarter of 1995, as compared to the same period of the prior year, is
primarily due to the effects of cooler weather associated with a major
snow storm in September 1995 and moderate customer growth. Gas sales were
up 18.5% and unbilled revenues were $8.7 million higher in the current
period.
A decline in transport, gathering and processing revenues reduced
gas sales margin by $1.8 million during the third quarter of 1995 as
compared to the same period of the prior year. The sale of WGG in August
1994 resulted in a $2.4 million reduction in gathering revenues and a 7.8
MMcf reduction in gathering deliveries during the current period (See Note
6. Sale of Westgas Gathering, Inc. in Item 1. FINANCIAL STATEMENTS).
These lower revenues, however, have been offset, in part, by revenues 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 third quarters of 1995 and 1994
had little impact on net income. The increase in gas purchased for resale
during the third quarter of 1995, compared to the third quarter of 1994,
is due to the higher retail gas sales, but reflects a 12.8% decrease in
the per unit cost of gas.
Non-Fuel Operating Expenses
Other operating and maintenance expenses decreased $3.8 million
during the third 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 $3
million reduction) and the recognition of approximately $1.5 million of
involuntary severance costs in the third quarter of 1994. These decreases
were offset, in part, by the recognition in the third quarter of 1995 of
approximately $1.8 million of expenses related to the merger with SPS.
During the third quarter of 1994, the Company recognized additional
expenses aggregating approximately $43.4 million ($26.7 million after-tax
or 43 cents per share) for increased costs associated with the defueling
and decommissioning of Fort St. Vrain and the impairment of certain Fort
St. Vrain related property and inventory (See Note 2. Fort St. Vrain in
Item 1. FINANCIAL STATEMENTS).
Depreciation and amortization expense decreased $1 million or 2.7%
during the third 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.
28
PAGE
Income taxes increased $36.8 million in the third quarter of 1995,
as compared to the third quarter of 1994, primarily due to higher pre-tax
income in 1995 and the effects of two items recorded in 1994. These 1994
items were: 1) an income tax adjustment following the completion of a
detailed analysis of the Company's income tax liabilities associated with
the adoption of full normalization (reduced income tax expense by
approximately $21.3 million) and, 2) the true-up of the tax accrual
related to the filing of the 1993 tax return (approximately $5.1 million).
Other income and deductions - net decreased $33.7 million during the
third quarter of 1995, when compared to the same period of the prior year,
primarily due to the gain on the sale of WGG recorded in 1994. On August
31, 1994, the Company sold all of the outstanding common stock of WGG and
certain related operating properties for a purchase price of approximately
$87 millon. The Company recognized a pre-tax gain of approximately $34.5
million ($19.5 million after-tax or approximately 31 cents per share).
Interest charges increased $3.3 million during the third quarter of
1995, when compared to the same period in 1994, primarily due to the
recognition of interest costs related to the pending refund of the over
collection of expenses under the Company's cost adjustment mechanisms and
higher interest rates associated with short-term borrowings.
Nine Months Ended September 30, 1995 Compared to the Nine Months Ended
September 30, 1994
Earnings
Earnings per share were $1.89 for the first nine months of 1995,
compared to $1.80 for the first nine months of 1994. The improved
earnings in 1995 are primarily attributed to increased electric and gas
margins resulting from higher sales and lower operating and maintenance
expenses associated with the cost containment efforts that were
implemented in 1994 as discussed below. Earnings in 1994 were also
favorably impacted by the net effects of three one-time items which
increased earnings for that period by approximately $0.22 per share as
discussed in the third quarter earnings summary.
29
PAGE
Electric Operations
The following table details the changes in electric operating
revenues and energy costs for the first nine months of 1995 as compared to
the same period in 1994.
Increase (Decrease)
(Thousands of Dollars)
Electric operating revenues:
Retail . . . . . . . . . . . . . . . . . . . . . . . $ 56,885
Wholesale . . . . . . . . . . . . . . . . . . . . . (5,828)
Other (including unbilled revenues) . . . . . . . . (8,287)
Total revenues . . . . . . . . . . . . . . . . . . 42,770
Fuel used in generation . . . . . . . . . . . . . . . (13,963)
Purchased power . . . . . . . . . . . . . . . . . . . 43,675
Net increase in electric margin . . . . . . . . . . $ 13,058
The following schedule compares electric Kwh sales for the first
nine months of 1995 and 1994.
Electric Sales
(Millions of Kwh)
1995 1994 % Change *
Residential . . . . . . . . . . . . . . . 4,746.2 4,592.8 3.3%
Commercial and Industrial . . . . . . . . 11,320.2 10,983.0 3.1%
Public Authorities . . . . . . . . . . . 136.5 135.4 0.8%
Other Utilities . . . . . . . . . . . . . 2,192.1 2,325.3 (5.7%)
18,395.0 18,036.5 2.0%
* Percentages are calculated using unrounded amounts
Retail electric revenues increased $56.9 million for the nine months
ended September 30, 1995, when compared to the nine months ended September
30, 1994, primarily due to an overall 3.1% increase in retail sales
resulting from moderate customer growth and the recovery of higher costs
for purchased power. Wholesale electric revenues decreased $5.8 million
for the nine months ended September 30, 1995, when compared to the same
period in the prior year, primarily due to a 5.7% 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 $8.3 million
primarily due to lower revenue from transmission and other services and
the recognition in 1994 of approximately $5 million in unbilled revenues
30
PAGE
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 nine months of 1995 and 1994 had little
impact on net income.
Fuel used in generation expense decreased $14.0 million, or 9.2%,
during the first nine months in 1995, compared to the same period in 1994,
primarily due to a slight reduction in the cost per Kwh which is primarily
due to lower coal and coal transportation costs from the renegotiation of
certain contracts coupled with a 2.5% decrease in generation. Purchased
power expense increased approximately $43.7 million, or 13.7%, during the
nine months ended September 30, 1995, when compared to the same period in
1994, primarily due to increased purchases from qualifying facilities as
mandated by the CPUC. 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 is being addressed 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 nine months of 1995 as compared
to the same period in 1994.
Increase (Decrease)
(Thousands of Dollars)
Gas operating revenues . . . . . . . . . . . . . . . $ 20,554
Less: transport, gathering, and processing revenues . (6,176)
Revenues from gas sales . . . . . . . . . . . . . . 26,730
Gas purchased for resale . . . . . . . . . . . . . . 12,853
Net increase in gas sales margin . . . . . . . . . . $ 13,877
31
PAGE
The following schedule compares gas deliveries for the first nine
months of 1995 and 1994.
Gas Deliveries
(Millions of Mcf)
1995 1994 % Change *
Residential . . . . . . . . . . . . . . . 72.6 68.4 6.1%
Commercial and Industrial . . . . . . . . 44.3 42.5 4.2%
Other Utilities . . . . . . . . . . . . . 0.4 0.5 (21.7%)
Total Gas Sales . . . . . . . . . . . . 117.3 111.4 5.3%
Gathered and Processed . . . . . . . . . 1.1 29.2 (96.1%)
Transported and Other . . . . . . . . . . 69.3 57.0 21.6%
187.7 197.6 (5.0)
* Percentages are calculated using unrounded amounts
Gas operating revenues and gas purchased for resale increased during
the first nine months of 1995, as compared to the same period in the prior
year, primarily due to a 5.3% increase in total gas sales resulting from
cooler weather during the spring and fall of 1995 offset, in part, by
lower gathering and processed gas deliveries. The sale of WGG during 1994
resulted in a $7.9 million reduction in gathering revenues and a 28.1 MMcf
reduction in gathering deliveries for the current period (See Note 6. Sale
of Westgas Gathering, Inc. in Item 1. FINANCIAL STATEMENTS). 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 costs on a timely basis. As a result, the changes in revenues
associated with these mechanisms in the first nine months of 1995 and 1994
had little impact on net income. The increase in gas purchased for resale
for the first nine months of 1995, compared to the first nine months of
1994, is offset, in part, by a 3.3% decrease in the per unit cost of gas.
Non-Fuel Operating Expenses
Other operating and maintenance expenses decreased $20.8 million
during the first nine months of 1995, when compared to the same period in
1994, primarily due to lower labor and employee benefit costs resulting
from the cost containment efforts which included the restructuring and
employee downsizing accomplished in 1994 (approximately a $19 million
32
PAGE
reduction) and the recognition of approximately $6.9 million of
involuntary severance costs in 1994. This restructuring and downsizing
was completed in two phases: 1) effective April 1, 1994, the Company
reduced its workforce by approximately 550 employees through an early
retirement/severance program, and 2) in late 1994, the Company eliminated
approximately 550 management and staff level positions in connection with
an internal restructuring and involuntary severance program.
In addition, lower maintenance expenses at the Company's steam
generation facilities also contributed to the decrease in other operating
and maintenance expenses. These decreases were offset, in part, by a $2.2
million increase in the amortization of the early retirement/severance
program costs, the $2.5 million write-off of certain software costs due to
cancellation of a materials management project and $1.8 million of merger
related costs. The total cost of the 1994 early retirement/severance
program was approximately $39.7 million. These costs have been deferred
and effective April 1, 1994, are being amortized to expense over
approximately 4.5 years in accordance with rate regulatory treatment.
During the third quarter of 1994, the Company recognized additional
expenses aggregating approximately $43.4 million for increased costs
associated with the defueling and decommissioning of Fort St. Vrain and
the impairment of certain Fort St. Vrain related property and inventory
(See Note 2. Fort St. Vrain in Item 1. FINANCIAL STATEMENTS).
Depreciation and amortization expense decreased $4.1 million during
the first nine months of 1995, when compared to the same period in 1994,
primarily due to the effects of using a longer estimated depreciable life
for the Company's electric steam production facilities, consistent with
the Company's most recent depreciation study.
The $40.9 million increase in income taxes for the first nine months
of September 1995, as compared to the same period in 1994, is primarily
due to higher pre-tax income and the effects of two items recorded in 1994
which lowered expense during that period. These items were: 1) an
adjustment associated with the adoption of full normalization
(approximately $21.3 million), and 2) the true-up of the tax accrual
related to the filing of the 1993 tax return (approximately $5.1 million).
This increase was offset, in part, by additional tax benefits recorded in
1995 related to certain non-regulated investment activities.
Other income and deductions - net decreased $34.3 million during the
first nine months of 1995, when compared to the same period of the prior
year, primarily due to the 1994 gain on the sale of WGG. On August 31,
1994, the Company sold all of the outstanding common stock of WGG and
certain related operating properties for a purchase price of approximately
$87 millon and recognized a pre-tax gain of approximately $34.5 million.
In the first quarter of 1995, the Company recognized $2.1 million of this
gain as an amount to be refunded to the ratepayers in accordance with a
1995 settlement agreement.
Interest charges increased $8.7 million during the first nine months
33
PAGE
of 1995, when compared to the same period in 1994, primarily due to higher
interest rates and an increased level of short-term borrowings as well as
the recognition of interest costs related to the pending refund of the
over collection of expenses under the Company's cost adjustment
mechanisms.
Financial Position
The decline in accounts receivable and accounts payable at September
30, 1995, as compared to the corresponding amounts at December 31, 1994,
is primarily attributable to the seasonality of the Company's gas
purchases and sales.
The gas refund liability increased from December 31, 1994 primarily
due to lower than anticipated natural gas prices and supplier refunds.
Gas refunds to customers of approximately $81 million, including interest,
will be made during the fourth quarter of 1994.
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 $129 million during
the first nine months of 1995, when compared to the first nine months of
1994, primarily due to higher earnings and the over recovery of natural
gas costs as discussed above. Increases in the recovery of purchased gas
and electric energy costs ($23.6 million) and lower decommissioning
expenditures ($13.3 million) also contributed to the increase in cash
provided by operating activities.
At September 30, 1995, the Company's remaining decommissioning
liability, excluding defueling, was approximately $31.6 million. The
expenditures related to this obligation are expected to be incurred over
the next year with final completion of such activities anticipated in mid-
1996. The annual decommissioning amount being recovered from customers is
approximately $13.9 million which will continue through June 2005. At
September 30, 1995, approximately $100 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 $135 million during the
first nine months of 1995, when compared to the same period in 1994,
primarily due to a decrease in proceeds received from the sale of assets.
In 1994, the Company sold WGG and Fuelco properties. An increase in
construction
34
PAGE
expenditures ($6.9 million) and the purchase of Young Gas Storage Company
in 1995 ($6 million) also contributed to the use of cash for investing
activities.
Cash used in financing activities decreased approximately $16.7
million during the first nine months of 1995, when compared to the same
period in 1994, primarily due to decreased repayments of short-term
borrowings during the current year ($11.6 million). Long-term debt
refinancing activity in the first nine months of 1995, as compared to the
same period in the prior year, 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 $19.5 million. Proceeds from the sale of
common stock under the Company's dividend reinvestment and stock purchase
plan decreased in the first nine months of 1995 to $21.1 million as
compared to the proceeds of approximately $30.8 million from issuances
under such plan in the first nine months of 1994 which increased the cash
used in financing activities.
Merger
On August 22, 1995, in response to an increasingly competitive
operating environment, the Company and SPS announced that the companies
have entered into a definitive Merger Agreement. This "merger of equals"
is expected to occur shortly after all of the conditions to the
consummation of the Merger, including obtaining applicable regulatory and
shareholder approvals, are met or waived. This process is expected to
take 12 to 16 months to complete from the date the Merger Agreement was
announced. See Note 4. Merger in Item 1. FINANCIAL STATEMENTS for more
discussion regarding the Merger and matters which may impact future
results of operations, financial position and cash flows.
Common Stock Dividend
On September 26, 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 third quarter last 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.
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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 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 32
herein.
12(b) - Computation of Ratio of Consolidated Earnings to
Consolidated Combined Fixed Charges and Preferred Stock
Dividends is set forth at page 33 herein.
15 - Letter from Arthur Andersen LLP regarding unaudited
interim information is set forth at page 34 herein.
27 - Financial Data Schedule UT
(b) Reports on Form 8-K
The following report on Form 8-K has been filed:
A report on Form 8-K dated August 22, 1995, was filed on
August 23, 1995. The item reported was Item 5. Other Events,
which presented information on: 1) an Agreement and Plan of
Reorganization dated August 22, 1995, by and among Public
Service Company of Colorado, Southwestern Public Service
Company, and M-P New Co., a newly formed Delaware corporation,
to serve as the holding company, 2) a joint press release
announcing the proposed merger, and 3) an amendment, dated
August 22, 1995 to the Rights Agreement dated as of February
26, 1991 between Public Service Company of Colorado and
Mellon Bank, N.A.
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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: November 13, 1995
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PAGE
EXHIBIT INDEX
12(a) - Computation of Ratio of Consolidated Earnings to
Consolidated Fixed Charges is set forth at page 32
herein.
12(b) - Computation of Ratio of Consolidated Earnings to
Consolidated Combined Fixed Charges and Preferred Stock
Dividends is set forth at page 33 herein.
15 - Letter from Arthur Andersen LLP regarding unaudited
interim information is set forth at page 34 herein.
27 - Financial Data Schedule UT
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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)
Nine Months Ended
September 30,
1995 1994
(Thousands of Dollars,
except ratios)
Fixed charges:
Interest on long-term debt . . . . . . . . . . . . . . $ 64,210 $ 67,102
Interest on borrowings against
corporate-owned life insurance contracts . . . . . . 25,580 21,891
Other interest . . . . . . . . . . . . . . . . . . . . 17,443 9,575
Amortization of debt discount and expense less premium 2,413 2,324
Interest component of rental expense . . . . . . . . . 5,025 5,255
Total . . . . . . . . . . . . . . . . . . . . . . $ 114,671 $ 106,147
Earnings (before fixed charges and taxes on income):
Net income . . . . . . . . . . . . . . . . . . . . . . $ 127,718 $ 119,458
Fixed charges as above . . . . . . . . . . . . . . . . 114,671 106,147
Provisions for Federal and state taxes on income,
net of investment tax credit amortization . . . . . . 65,556 24,693
Total . . . . . . . . . . . . . . . . . . . . . . . $ 307,975 $ 250,298
Ratio of earnings to fixed charges . . . . . . . . . . . 2.69 2.36
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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)
Nine Months Ended
September 30,
1995 1994
(Thousands of Dollars,
except ratios)
Fixed charges and preferred stock dividends:
Interest on long-term debt . . . . . . . . . . . . . . $ 64,210 $ 67,102
Interest on borrowings against
corporate-owned life insurance contracts . . . . . . 25,580 21,891
Other interest . . . . . . . . . . . . . . . . . . . . 17,443 9,575
Amortization of debt discount and expense less premium 2,413 2,324
Interest component of rental expense . . . . . . . . . 5,025 5,255
Preferred stock dividend requirement . . . . . . . . . 8,992 9,013
Additional preferred stock dividend requirement . . . . 4,616 1,879
Total . . . . . . . . . . . . . . . . . . . . . . $ 128,279 $ 117,039
Earnings (before fixed charges and taxes on income):
Net income . . . . . . . . . . . . . . . . . . . . . . $ 127,718 $ 119,458
Interest on long-term debt . . . . . . . . . . . . . . 64,210 67,102
Interest on borrowings against
corporate-owned life insurance contracts . . . . . . 25,580 21,891
Other interest . . . . . . . . . . . . . . . . . . . . 17,443 9,575
Amortization of debt discount and expense less premium 2,413 2,324
Interest component of rental expense . . . . . . . . . 5,025 5,255
Provisions for Federal and state taxes on income,
net of investment tax credit amortization . . . . . . 65,556 24,693
Total . . . . . . . . . . . . . . . . . . . . . . . $ 307,945 $ 250,298
Ratio of earnings to fixed charges and preferred stock
dividends . . . . . . . . . . . . . . . . . . . . . . . 2.40 2.14
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EXHIBIT 15
November 10, 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. 33-62233)
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 September 30, 1995, which includes our
report dated November 10, 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
41