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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________
Commission file number 1-3280
Public Service Company of Colorado
(Exact name of registrant as specified in its charter)
Colorado 84-0296600
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
1225 17th Street, Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)
Registrant's Telephone Number, including area code: (303) 571-7511
--------------------------------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes x No
At May 8, 1996, 64,029,218 shares of the registrant's Common Stock, $5.00
par value (the only class of common stock), were outstanding.
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<PAGE>
Table of Contents
PART I - FINANCIAL INFORMATION
Item l. Financial Statements .............................................. 1
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations ............................................ 18
PART II - OTHER INFORMATION
Item 1. Legal Proceedings................................................. 22
Item 4. Submission of Matters to a Vote of Security Holders............... 22
Item 6. Exhibits and Reports on Form 8-K.................................. 22
SIGNATURE.................................................................. 23
EXHIBIT INDEX.............................................................. 24
EXHIBIT 12(a).............................................................. 25
EXHIBIT 12(b).............................................................. 26
EXHIBIT 15 ................................................................ 27
In addition to the historical information contained herein, this report
contains a number of "forward-looking statements", within the meaning of the
Securities Exchange Act of 1934. Such statements address future events and
conditions concerning capital expenditures, resolution and impact of litigation,
regulatory matters, liquidity and capital resources, and accounting matters.
Actual results in each case could differ materially from those projected in such
statements by reason of factors including, without limitation, electric utility
restructuring, future economic conditions; earnings retention and dividend
payout policies; developments in the legislative, regulatory and competitive
markets in which the Company operates; and other circumstances that could affect
anticipated revenues and costs, such as compliance with laws and regulations.
These and other factors are discussed in the Company's filings with the
Securities and Exchange Commission including this report.
i
<PAGE>
PART 1 - FINANCIAL INFORMATION
Item 1. Financial Statements
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Thousands of Dollars)
ASSETS
March 31, December 31,
1996 1995
---- ----
(Unaudited)
Property, plant and equipment, at cost:
Electric .......................................... $3,760,496 $3,751,321
Gas................................................ 995,639 989,215
Steam and other.................................... 89,101 88,446
Common to all departments.......................... 398,874 380,809
Construction in progress........................... 174,993 192,580
------- -------
5,419,103 5,402,371
Less: accumulated depreciation .................... 1,951,921 1,921,659
--------- ---------
Total property, plant and equipment.............. 3,467,182 3,480,712
--------- ---------
Investments, at cost, and receivables................. 35,553 24,282
------ ------
Current assets:
Cash and temporary cash investments................ 12,540 14,693
Accounts receivable, less reserve for uncollectible
accounts ($3,395 at March 31, 1996; $3,630
at December 31, 1995) ........................... 154,750 124,731
Accrued unbilled revenues ......................... 84,196 96,989
Materials and supplies, at average cost............ 52,678 56,525
Fuel inventory, at average cost.................... 34,322 35,654
Gas in underground storage, at cost (LIFO)......... 21,234 44,900
Current portion of accumulated deferred income taxes 28,568 19,229
Regulatory assets recoverable within one year (Note 1) 42,103 40,247
Prepaid expenses and other......................... 31,376 35,619
------ ------
Total current assets.............................. 461,767 468,587
------- -------
Deferred charges:
Regulatory assets (Note 1)......................... 314,425 321,797
Unamortized debt expense .......................... 10,055 10,460
Other.............................................. 51,290 48,457
------ ------
Total deferred charges............................ 375,770 380,714
------- -------
$4,340,272 $4,354,295
========== ==========
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 BALANCE SHEETS
(Thousands of Dollars)
CAPITAL AND LIABILITIES
March 31, December 31,
1996 1995
---- ----
(Unaudited)
Common stock.......................................... $1,013,364 $ 997,106
Retained earnings..................................... 374,477 346,539
------- -------
Total common equity............................... 1,387,841 1,343,645
Preferred stock:
Not subject to mandatory redemption................ 140,008 140,008
Subject to mandatory redemption at par............. 41,289 41,289
Long-term debt........................................ 1,193,862 1,195,553
--------- ---------
2,763,000 2,720,495
--------- ---------
Noncurrent liabilities:
Employees' postretirement benefits other than pensions 49,895 51,704
Employees' postemployment benefits................. 23,500 23,500
Defueling and decommissioning liability (Note 2)... - 23,115
------- ------
Total noncurrent liabilities...................... 73,395 98,319
------ ------
Current liabilities:
Notes payable and commercial paper ................ 267,920 288,050
Long-term debt due within one year................. 67,895 82,836
Preferred stock subject to mandatory redemption
within one year ................................. 2,576 2,576
Accounts payable................................... 140,577 156,109
Dividends payable.................................. 36,491 35,284
Recovered purchased gas and electric energy costs
- net (Note 1) .................................. 37,791 9,508
Customers' deposits................................ 17,662 17,462
Accrued taxes...................................... 103,102 55,393
Accrued interest................................... 22,383 32,071
Current portion of defueling and decommissioning
liability (Note 2) .............................. 25,895 24,055
Other.............................................. 57,692 78,451
------ ------
Total current liabilities......................... 779,984 781,795
------- -------
Deferred credits:
Customers' advances for construction............... 57,577 99,519
Unamortized investment tax credits ................ 111,943 113,184
Accumulated deferred income taxes ................ 523,341 508,143
Other.............................................. 31,032 32,840
------ ------
Total deferred credits............................ 723,893 753,686
Commitments and contingencies (Note 4)................ $4,340,272 $4,354,295
========== ==========
The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.
2
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PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(Unaudited)
(Thousands of Dollars Except per Share Data)
Three Months Ended
March 31,
1996 1995
---- ----
Operating revenues:
Electric.......................................... $370,117 $366,583
Gas............................................... 242,228 244,557
Other............................................. 10,572 9,456
------ -----
622,917 620,596
Operating expenses:
Fuel used in generation........................... 46,337 47,185
Purchased power................................... 122,435 121,478
Gas purchased for resale.......................... 160,724 168,135
Other operating expenses.......................... 76,646 89,814
Maintenance....................................... 14,372 14,704
Depreciation and amortization..................... 36,862 35,166
Taxes (other than income taxes)................... 22,305 23,091
Income taxes...................................... 41,146 29,334
------ ------
520,827 528,907
------- -------
Operating income..................................... 102,090 91,689
Other income and deductions:
Allowance for equity funds used during construction 511 751
Miscellaneous income and deductions - net......... (2,528) (3,883)
------ ------
(2,017) (3,132)
Interest charges:
Interest on long-term debt........................ 22,068 21,506
Amortization of debt discount and expense
less premium .................................... 977 791
Other interest.................................... 13,671 13,308
Allowance for borrowed funds used during
construction .................................... (1,072) (692)
------ ----
35,644 34,913
------ ------
Net income........................................... 64,429 53,644
Dividend requirements on preferred stock............. 2,972 3,001
----- -----
Earnings available for common stock.................. $ 61,457 $ 50,643
======== ========
Weighted average common shares outstanding (thousands) 63,679 62,513
====== ======
Earnings per weighted average
share of common stock outstanding................. $ 0.97 $ 0.81
======== ==========
Dividends per share declared on common stock......... $ 0.525 $ 0.51
======== ==========
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 CASH FLOWS
(Unaudited)
(Thousands of Dollars)
Three Months Ended
March 31,
1996 1995
---- ----
Operating activities:
Net income........................................ $64,429 $53,644
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization.................... 38,103 36,148
Amortization of investment tax credits........... (1,241) (1,244)
Deferred income taxes............................ 9,117 (8,725)
Allowance for equity funds used during construction (511) (751)
Change in accounts receivable.................... (30,019) 5,597
Change in inventories............................ 28,845 24,851
Change in other current assets................... 14,149 49,221
Change in accounts payable....................... (15,532) (38,509)
Change in other current liabilities.............. 35,537 59,067
Change in deferred amounts....................... (1,158) (1,012)
Change in noncurrent liabilities................. (19,819) (362)
Other............................................ 1,396 25
----- --
Net cash provided by operating activities..... 123,296 177,950
------- -------
Investing activities:
Construction expenditures......................... (62,616) (62,005)
Allowance for equity funds used during construction 511 751
Proceeds from (cost of) disposition of property,
plant and equipment ............................ 734 (1,059)
Purchase of other investments..................... (1,316) (454)
Sale of other investments......................... 2,034 1,618
------- -------
Net cash used in investing activities......... (60,653) (61,149)
------- -------
Financing activities:
Proceeds from sale of common stock................ 7,317 6,823
Redemption of long-term debt...................... (16,698) (21,921)
Short-term borrowings - net....................... (20,130) (60,040)
Dividends on common stock......................... (32,313) (31,077)
Dividends on preferred stock...................... (2,972) (3,001)
------ ------
Net cash used in financing activities......... (64,796) (109,216)
------- --------
Net (decrease) increase in cash and temporary
cash investments ........................... (2,153) 7,585
Cash and temporary cash investments at
beginning of period ........................ 14,693 5,883
------ -----
Cash and temporary cash investments at end
of period .................................. $ 12,540 $ 13,468
========= =========
The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.
4
<PAGE>
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)
1. Accounting Policies
Business, utility operations and regulation
The Company is an operating public utility engaged, together with its
utility 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. Approximately 90% of the
Company's electric and gas revenues are subject to CPUC jurisdiction. Cheyenne
Light, Fuel and Power Company ("Cheyenne") and WestGas Interstate, Inc. ("WGI")
are subject to the jurisdiction of the Public Service Commission of Wyoming
("WPSC") and the FERC, respectively.
Regulatory assets and liabilities
The Company and its regulated subsidiaries prepare their financial
statements in accordance with the provisions of Statement of Financial
Accounting Standards No. 71 - "Accounting for the Effects of Certain Types of
Regulation" ("SFAS 71"). In general, SFAS 71 recognizes that accounting for rate
regulated enterprises should reflect the relationship of costs and revenues
introduced by rate regulation. As a result, a regulated utility may defer
recognition of a cost (a regulatory asset) or recognize an obligation (a
regulatory liability) if it is probable that, through the ratemaking process,
there will be a corresponding increase or decrease in revenues.
In response to the increasingly competitive environment for utilities, the
regulatory climate also is changing. The Company continues to participate in
regulatory and legislative proceedings which could change or impact current
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 adopted this standard on
January 1, 1996, the effective date of the new statement, and such adoption did
not have a material impact on the Company's results of operations, financial
position or cash flows.
5
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
The following regulatory assets are reflected in the Company's
consolidated condensed balance sheets:
March 31, December 31, Recovery
1996 1995 Through
---- ---- -------
(Thousands of Dollars)
Nuclear decommissioning costs (Note 2).... $ 95,766 $ 97,801 2005
Income taxes ............................. 107,359 110,617 2006
Employees' postretirement benefits
other than pensions..................... 49,312 47,600 2013
Early retirement costs.................... 22,151 24,366 1998
Employees' postemployment benefits........ 23,404 23,500 Undetermined
Demand-side management costs.............. 31,527 30,188 2002
Unamortized debt reacquisition costs...... 21,433 21,940 2024
Other..................................... 5,576 6,032 1999
------- ------
Total................................... 356,528 362,044
Classified as current..................... 42,103 40,247
------- -------
Classified as noncurrent.................. $314,425 $321,797
======== ========
Certain costs associated with the Company's Demand Side Management ("DSM")
programs are deferred and recovered in rates over five to seven year periods
through the Demand Side Management Cost Adjustment ("DSMCA"), which was
implemented July 1, 1993. Non-labor incremental expenses, carrying costs
associated with deferred DSM costs and incentives associated with approved DSM
programs are recovered on an annual basis.
Costs incurred to reacquire debt prior to scheduled maturity dates are
deferred and amortized over the life of the debt issued to finance the
reacquisition or as approved by the regulator.
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. The cumulative effects are recognized as a current
asset or liability until adjusted by refunds or collections through future
billings to customers.
Other
Property, plant and equipment includes approximately $18.4 million and
$25.4 million, respectively, for costs associated with the engineering design of
the future Pawnee 2 generating station and certain water rights located in
southeastern Colorado, also obtained for a future generating station. The
Company is earning a return on these investments based on the Company's weighted
average cost of debt and preferred stock in accordance with a CPUC rate order.
Statements of Cash Flows - Non-cash Transactions
Shares of common stock (274,934 in 1996 and 310,546 in 1995), valued at
the market price on date of issuance (approximately $9 million in 1996 and $10
million in 1995), were issued to the Employees' Savings and Stock Ownership Plan
of Public Service Company of Colorado and Participating Subsidiary Companies.
The estimated issuance values were recognized in other operating expenses during
the respective preceding years. Shares of common stock (6,470 in 1996 and 3,891
in 1995), valued at the market price on the date of issuance ($0.2 million in
6
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
1996 and $0.1 million in 1995), were issued to certain executives pursuant to
the applicable provisions of the executive compensation plans. These stock
issuances were non-cash transactions and are not reflected in the consolidated
condensed statements of cash flows.
General
See Note 1. of the Notes to Consolidated Financial Statements in the
Company's 1995 Annual Report on Form 10-K for a summary of the Company's
significant accounting policies.
2. Fort St. Vrain
Overview
In 1989, the Company announced its decision to end nuclear operations at
the Fort St. Vrain Nuclear Generating Station ("Fort St. Vrain") and to proceed
with the defueling and decommissioning of the reactor. While the defueling of
the reactor to the Independent Spent Fuel Storage Facility ("ISFSI") was
completed in June 1992, several issues related to the ultimate storage/disposal
of Fort St. Vrain's spent nuclear fuel remained unresolved. However, as
described below, on February 9, 1996, the Company and the Department of Energy
("DOE") entered into a contract resolving all issues related to this matter.
Additionally, on March 22, 1996, the Company and the decommissioning contractors
engaged to complete such activities, announced the completion of the physical
decommissioning work at the facility with only Nuclear Regulatory Commission
("NRC") site release remaining to be addressed. It is expected that NRC site
release activities will be completed in 1996 resulting in the Company's Part 50
license being terminated.
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 certificate of public convenience and necessity,
which was received in July 1994, 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
1999 and Phase 2 - 239 Mw in 2000. The repowering of Phase 1A has been completed
with the commencement of commercial operation on May 1, 1996. The phased
repowering allows the Company flexibility in timing the addition of this
generation supply to meet future load growth.
Defueling
On February 9, 1996, the Company and the DOE entered into an agreement
relating to the disposal of Fort St. Vrain's spent nuclear fuel. Previously, the
Company had entered into two separate agreements with the DOE for the
disposal/storage of Fort St. Vrain's six segments of spent nuclear fuel which
are currently stored in the ISFSI located at the plant site. In summary, the
primary provisions of the agreement include the following.
- On February 9, 1996, the DOE assumed title to fuel segments 4 - 9,
which, as noted above, currently are stored in the facility.
- The DOE agreed to pay the Company $16 million for settlement of claims
associated with the ISFSI. Title to the ISFSI will pass to the DOE at such
time as all applicable legal requirements for title transfer (including
NRC approval) are met. The DOE deposited $14 million of the $16 million
into an interest bearing escrow account. The initial $2 million was paid
to the Company on February 13, 1996.
- Until the time title to the ISFSI transfers to the DOE, the Company will
be entitled to payments of $2 million per year initially to come from the
escrow account (escalated annually based on the Consumer Price Index) plus
ISFSI operating and maintenance costs including licensing fees and other
regulatory costs, facility support 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 and the agreement will be
terminated.
7
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
- 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.
- Upon termination or expiration of the agreement, the DOE will be
responsible for the defueling and decommissioning of the ISFSI with the
Company being responsible for costs only up to the amount contained in its
existing NRC required decommissioning escrow account. Such amount at March
31, 1996 was approximately $1.7 million.
- The Company provided to the DOE a full and complete release of claims
against the DOE arising out of prior contracts discussed above related to
spent fuel disputes.
As a result of the DOE settlement, coupled with a complete review of
expected remaining decommissioning costs and establishment of the anticipated
refund to customers discussed below, pre-tax earnings for the three months ended
March 31, 1996 were positively impacted by approximately $16 million. In
accordance with the 1991 CPUC approval to recover certain decommissioning costs
described below, 50% of any cash amounts received from the DOE as part of a
settlement, net of costs incurred by the Company, including legal fees, is to be
refunded or credited to customers. While final determination of the amount to be
refunded to customers has not yet been completed, the Company established an $8
million liability for such refunds at March 31, 1996 on the consolidated
condensed balance sheet.
Decommissioning
Following the 1991 CPUC approval, effective July 1, 1993 the Company began
collecting from customers decommissioning costs which are expected to total
approximately $124.4 million (plus a 9% carrying cost). Such amount, which is
expected to be collected over a twelve year period, represented the
inflation-adjusted estimated remaining cost of decommissioning activities not
previously recognized as expense at the time of CPUC approval. At March 31,
1996, approximately $95.8 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.
As previously noted, on March 22, 1996, the Company and the
decommissioning contractors announced that the physical decommissioning
activities at the facility have been completed with only NRC site release to be
addressed. At March 31,1996, approximately $324.2 million had been spent for
defueling and decommissioning activities with a remaining $25.9 million
defueling and decommissioning liability reflected on the consolidated condensed
balance sheet. The Company believes this remaining decommissioning liability is
adequate to complete all final decommissioning activities.
Funding
Under NRC regulations, the Company is required to make filings with, and
obtain the approval of, the NRC regarding certain aspects of the Company's
decommissioning proposals, including funding. On January 27, 1992, the NRC
accepted the Company's funding aspects of the decommissioning plan. The Company
has also obtained an unsecured irrevocable letter of credit totaling $125
million that meets the NRC's stipulated funding guidelines including those
proposed on August 21, 1991 that address decommissioning funding requirements
for nuclear power reactors that have been prematurely shut down. In accordance
with the NRC funding guidelines, the Company is allowed to reduce the balance of
the letter of credit based upon milestone payments made under the fixed-price
decommissioning contract. As a result of such payments, at March 31, 1996, the
letter of credit had been reduced to $34 million.
8
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
Nuclear Insurance
During commercial operation and defueling, the Company participated in a
federally mandated program to provide funding in the event public liability
claims arose from a nuclear incident which exceeded available commercial
insurance capacity. Under the requirements of the Price-Anderson Act, the
Company remains subject to potential assessments of up to $79 million per
incident, in amounts not to exceed $10 million per incident per year. The
Company was granted an NRC waiver from participation in this program on February
17, 1994 and, therefore, remains subject to assessments levied in response to
incidents prior to such date. The Company continues to maintain primary
commercial nuclear liability insurance of $100 million for the Fort St. Vrain
site and the adjoining ISFSI.
On June 7, 1995, the NRC granted the Company an exemption from the
requirement to purchase nuclear property damage and decontamination coverage
following an environmental assessment and finding of no significant impact. The
Company maintains coverage of $10 million to provide property damage and
decontamination protection in the event of an accident involving the ISFSI.
3. Merger
On August 22, 1995, the Company, Southwestern Public Service Company
("SPS"), a New Mexico corporation, and New Century Energies, Inc. ("NCE"), 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"). Based on outstanding common stock of the Company and SPS at March 31,
1996, the Merger would result in the common shareholders of the Company owning
62% of the common equity of NCE and the common shareholders of SPS owning 38% of
the common equity of NCE. In January 1996, NCE filed its application with the
Securities and Exchange Commission ("SEC") to be a registered public utility
holding company and the parent company for the Company and SPS.
The shareholders of the Company and SPS approved the Merger Agreement on
January 31, 1996. Additionally, the Merger is subject to customary closing
conditions, including the receipt of all necessary governmental approvals and
the making of all necessary governmental filings, including approvals and
findings of state utility regulators in Colorado, Texas, New Mexico, Wyoming and
Kansas as well as the approval of the FERC, the NRC, the SEC, the Federal Trade
Commission and the U.S. Department of Justice. Applications to the state
regulatory commissions and the FERC have been completed. The required
authorizations from the Kansas Corporation Commission and the NRC have been
obtained. It is currently expected that the Merger will be completed in the
latter half of 1996; however, the timing of the effective date of the Merger is
primarily dependent upon the regulatory process (see Note 4).
A transition management team, consisting of executives from each company,
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 management's intention that the consolidated 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 during 1996 and 1997. During the
first quarter of 1996, the Company recognized approximately $2.8 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 is seeking approval from the 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.
9
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
4. Commitments and Contingencies
Regulatory Matters
1995 Merger Rate Filings
In connection with the Merger with SPS, in November 1995 the Company filed
comprehensive proposals with the CPUC, the FERC and the WPSC to obtain approval
of such Merger and the associated comprehensive proposals from such regulatory
agencies. 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 by 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 Facilities Capacity Cost
Adjustment ("QFCCA") mechanisms, implementing quality of service measures and
recovering costs incurred in connection with the Merger (see Note 3). 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. The CPUC has scheduled hearings on this matter for July 1996
and the WPSC has scheduled hearings for May 30-31, 1996. The FERC has not yet
scheduled any proceedings related to the proposed Merger. However, during
January 1996, the FERC issued a Notice of Inquiry concerning its merger policy
under the Federal Power Act to determine whether the criteria and policies for
evaluating mergers needs to be revised.
Electric and Gas Cost Adjustment Mechanisms
The Company's QFCCA allows for the recovery of purchased capacity costs
from new Qualifying Facility ("QF") projects not reflected in base rates. In
January 1996, the CPUC issued a final decision which required the following: 1)
an earnings test 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, utilizing a test period for the
prior twelve months ended June 30, 1996, unless superseded by a CPUC decision
prior to the effective date. The Company intends to address this issue in
connection with the merger rate filing discussed above.
During 1994 and 1995, the CPUC conducted several proceedings to review
issues related to the ECA. Most recently, the CPUC opened a docket to review
whether the ECA should be maintained in its present form, altered or eliminated,
and on January 8, 1996, combined this docket with the merger docket discussed
above.
The CPUC approved the recovery of certain energy efficiency credits from
retail jurisdiction customers through the DSMCA in June 1994. In December 1994,
the Colorado Office of Consumer Counsel ("OCC") filed an appeal of the CPUC's
decision in the District Court in and for the City and County of Denver ("Denver
District Court"). The Denver District Court approved the collection of these
credits in June 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. To date, the Company has recognized
approximately $10.4 million of revenue related to these credits ($5.4 million
unbilled). On April 9, 1996, the Denver District Court issued an order affirming
the CPUC's decision.
Rate Cases
In November 1993, the CPUC issued a final written decision regarding the
Company's 1993 rate case, lowering the Company's annual base rate revenue
requirement by approximately $5.2 million. The Phase II proceedings related to
this rate case addressed cost allocation issues and specific rate changes for
10
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
the various customer classes based on the results of the Phase I decision. The
CPUC approved a settlement agreement related to gas rates and the new gas rates
were implemented effective October 1, 1995. A final decision on rehearing,
reargument and reconsideration for the Phase II proceedings related to electric
rates was issued in February 1996 and new rates became effective in early May
1996.
The Company filed a rate case with the FERC on December 29, 1995,
requesting a slight overall rate increase (less than 1%) from its wholesale
electric customers. This filing, among other things, requested approval for
recovery of Other Postretirement Employee Benefits ("OPEB") costs under
Statement of Financial Accounting Standards No. 106 - "Employers' Accounting for
Postretirement Benefits Other Than Pensions" ("SFAS 106"), postemployment
benefit costs under Statement of Financial Accounting Standards No. 112 -
"Employers' Accounting for Postemployment Benefits" ("SFAS 112") and new
depreciation rates based on the Company's most recent depreciation study. On
March 29, 1996, the FERC issued an order accepting for filing and suspending
certain proposed rate changes and establishing hearing procedures.
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 (collectively, the "Mega-NOPR"). In the Mega-NOPR, the Commission
intended to facilitate competition in wholesale bulk power markets by requiring
that jurisdictional electric utilities, including the Company, provide
transmission services on an open-access and comparable basis. A key feature of
comparable service, as proposed in the Mega-NOPR, was that each utility
establish separate rates for its transmission and generation services for new
wholesale services, and provide transmission services for its own operations,
including certain ancillary services, consistent with the terms of its
comparable tariffs.
In the Mega-NOPR, the FERC proposed pro forma network and point-to-point
transmission tariffs. The FERC also proposed rules for the recovery by utilities
of legitimate and verifiable stranded costs incurred when existing wholesale
requirements customer and retail customers leave utilities' generation systems
through FERC jurisdictional open-access tariffs and obtain their electric power
from other energy suppliers.
On June 26, 1995, the Company filed transmission tariffs with the FERC
that were intended to meet the comparability of service requirements as set out
in the Mega-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. On August 18, 1995, Cheyenne filed
transmission tariffs with the FERC that were intended to meet the Mega-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 Mega-NOPR
proceeding, effective August 25, 1995. The FERC also set the rates in the PSCo
Tariffs and Cheyenne Tariffs for hearing. On January 26, 1996, the Company and
Cheyenne filed revised tariffs containing terms and conditions which were
intended to more closely conform to the FERC's pro forma tariffs as set out in
the Mega-NOPR.
On March 29, 1996, the FERC accepted the revised PSCo and Cheyenne Tariffs
for filing, made the terms and conditions subject to the outcome of the
Mega-NOPR, and made the rates subject to the outcome of the earlier proceeding.
In the same order, the FERC accepted e prime's request for authorization to act
as a power marketer, subject to certain conditions. On April 8, 1996, the
Company and Cheyenne filed an Offer of Settlement in the rate proceeding, which
is currently pending. On April 15, 1996, e prime filed a compliance filing and a
request for rehearing on one of the conditions approved by the FERC in its order
authorizing e prime to act as a marketer. Both filings are pending.
On April 24, 1996, the FERC issued its Final Order on the Mega-NOPR
("Order No. 888"). In Order No. 888, the FERC adopted its proposal in the
Mega-NOPR with certain modifications. As required by Order No. 888,
jurisdictional utilities owning, controlling, or operating transmission
facilities must file non-discriminatory open-access tariffs that satisfy the
11
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
comparability standard-- i.e., that offer transmission services consistent with
what is provided for in their own operations. The FERC is requiring that all
such utilities file the single pro forma tariff (combined network and
point-to-point tariff) within sixty days of publication of the final rule in the
Federal Register. As proposed in the Mega-NOPR, the FERC, in Order No. 888, is
requiring that utilities must use the pro forma tariff for new requirements
services and, after year-end, for new economy transactions under existing
coordination agreements. Order No. 888 also requires that power pools, including
the Inland Power Pool of which the Company is a member, file an open-access
tariff for pool transactions.
Order No. 888 also provides for the recovery of legitimate, prudent, and
verifiable stranded investment costs in accordance with the proposal outlined in
the Mega-NOPR. The FERC will permit utilities to seek extra contractual recovery
of stranded costs associated with wholesale requirements contracts executed
prior to July 11, 1994. The FERC is to be the primary forum for utilities
seeking to recover stranded costs arising where retail customers become
wholesale transmission customers of a utility. In addition, the FERC will allow
utilities to seek to recover stranded costs resulting from retail wheeling, but
only in circumstances where a state regulator does not have authority to address
retail stranded costs at the time that retail wheeling is required.
In Order No. 888, the FERC determined not to allow for the general
abrogation of existing requirements contracts, but stated that it would permit
customers and utilities to seek modification or termination of certain contracts
on a case-by-case basis, and subject to appropriate stranded cost recovery.
On April 24, 1996, the FERC issued a Final Rule on its rulemaking Open
Access Same-time Information Systems ("OASIS") ("Order No. 889"). The intent of
the rule is to ensure that owners of transmission facilities, including the
Company and its affiliates, do not have an unfair competitive advantage in using
transmission facilities to market their power. Order No. 889 requires the
marketing area of a utility to obtain information about their transmission
system for their own wholesale power transactions from the utility's OASIS in
the same way as their competition does, and that utilities completely separate
their wholesale power marketing and transmission operations functions.
Simultaneously with its issuance of Order Nos. 888 and 889, the FERC also
issued a NOPR on Capacity Reservation Open Access Transmission Tariffs. This
proposed rule specifies filing requirements to be followed by public utilities
in making transmission tariff filings based on capacity reservations for all
transmission users. If adopted, the capacity reservation open access tariff
would replace the pro forma tariff implemented in Order No. 888. Comments on
this rulemaking must be filed by August 1, 1996.
Merger Notice of Inquiry
On February 7, 1996, the FERC issued a Notice of Inquiry in which it
requested comments on whether it should revise its criteria and policies for
evaluating proposed public utility mergers in light of the fundamental changes
in the electric industry and the regulations of the industry. The Company
submitted comments to such proceeding, which were due on May 7, 1996.
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
12
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
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. 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.
Environmental Site Cleanup
Under the Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), the U.S. 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 at a cost of approximately $9 million. On
January 3, 1996, in a lawsuit by the Company against its insurance providers,
the Denver District Court entered final judgment in favor of the Company in the
amount of $5.6 million for certain clean up costs at Barter. Several appeals and
cross appeals have been filed by the one of the insurance providers and the
Company in 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). 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 and from other potentially
responsible parties.
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 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. In December 1995, complaints
were filed by the Company against all applicable insurance carriers in the
Denver District Court.
The Ramp Industries disposal facility, located in Denver, Colorado has
been designated by the EPA as a Superfund hazardous waste site pursuant to
CERCLA and, on November 29, 1995, the Company received from the EPA a Notice of
Potential Liability and Request for Information related to such site. The EPA is
conducting an investigation of the contamination at this site and is in the
process of identifying the nature and quantities of hazardous wastes delivered
to, processed and currently stored at the site by Potentially Responsible
Parties ("PRPs"). The Company has responded to the EPA's request. The estimated
cost to investigate and remediate site contamination is not available as the EPA
is in the initial stages of its investigation. At this time, the Company cannot
estimate the amount, if any, of its potential liability related to this matter.
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.
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
13
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
reduce NOx emissions in order to comply with Phase II requirements. The
estimated costs for future plant modifications total approximately $51.4
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 alleged 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 ("CDPHE"), and 3) the
owners failed to operate the station in a manner consistent with good air
pollution control practices. The complaint seeks, among other things, civil
monetary penalties and injunctive relief. The joint owners of the station
contest all of these claims and contend that there were no violations of the
opacity limitation, because pursuant to the Colorado state implementation plan,
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 plaintiff's claims
described in item 2) above. As described below, the joint owners are currently
involved in settlement discussions with the conservation organization, the CDPHE
and the EPA. The Company has made substantial progress in the settlement
discussions. Any settlement would be contained in a consent decree that would be
subject to public comment and U. S. District Court approval. However, if
settlement is not reached, court hearings for injunctive relief and the
determination of penalties in connection with the litigation will be held.
Further appeals could be pursued by the joint owners if settlement is not
achieved.
In December 1995, the conservation organization filed a motion for summary
judgment which would require the joint owners to come into compliance with the
opacity requirements identified in the August 1993 complaint within 60 days or
submit a plan for the installation of additional pollution control equipment.
Additionally, the Company had received and responded to a request from the
EPA for information related to the plant and, on January 18, 1996, the EPA
issued a notice of violation stating that the plant had exceeded the 20% opacity
limitations in excess of 10,000 additional six-minute intervals during the
period extending from mid-1993 to mid-1995. It is expected that the issues
related to this notice of violation will be resolved as part of the settlement
discussions previously mentioned.
In early May 1996, the joint owners and the conservation organization
agreed to a stay of further court proceedings as a result of progress achieved
in settlement discussions. As part of the settlement discussions, payments to
the U.S. Treasury and certain contributions by the joint owners in an aggregate
amount of $4,250,000 are being considered. The Company would be responsible for
approximately 53% of such costs and, in anticipation of a settlement, the
Company made adequate provision for such amounts in the first quarter of 1996.
The Company cannot predict the level of penalties, if any, or the remedies that
the court or the EPA may impose if settlement is not reached or if the joint
14
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
owners are unsuccessful in a subsequent appeal. In the complaint, the plaintiff
had 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.
Moreover, it is expected that as part of the settlement discussed above,
additional pollution control equipment and practices will be required at the
station. The joint owners and the conservation organization have signed a
stipulation that, at a minimum, baghouses will be installed at the Hayden
station. Furthermore, the additional equipment and practices would be designed
to address particulate matter, SO2 and NOx emission concerns raised by this
litigation and by the Mt. Zirkel Wilderness Area Reasonable Attribution Study,
which is expected to be finalized during 1996. The timing of the installation of
the baghouses will be determined as part of the settlement, if achieved, or in
the litigation process.
The Company believes that, consistent with historical regulatory
treatment, any costs for pollution control equipment to comply with pollution
control regulations would be recovered from its customers. However, no assurance
can be given that this practice will continue in the future.
Employee Litigation
Several employee lawsuits have been filed against the Company involving
alleged sexual/age/race/disability discrimination. The Company is actively
contesting all such lawsuits and believes the ultimate outcome will not have a
material impact on the Company's results of operations, financial position or
cash flows.
In one of the cases, 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 flows.
Union Contracts
In early December 1995, the Company's contracts with the International
Brotherhood of Electrical Workers, Local 111 expired. Previously, an arbitrator
had rejected the Company's attempt to cancel the contract. The parties were
unable to reach agreement on the contract issues reopened through the
negotiation process and, as a result, entered into binding arbitration on March
20, 1996, as required under the provisions of the contracts. Contract provisions
to be determined by this binding arbitration process are limited to the length
of the contract extension and wages. A decision from the arbitrator is expected
in the second quarter of 1996. In addition, the International Brotherhood of
Electrical Workers, Local 111 has filed several grievances relating to the
employment of certain non-union personnel to perform services for the Company,
which matters are currently in arbitration. Approximately 2,150 employees, or
45% of the Company's total workforce, are represented by Local 111.
15
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)
5. Management's Representations
In the opinion of the Company, the accompanying unaudited consolidated
condensed financial statements include all adjustments necessary for the fair
presentation of the financial position of the Company and its subsidiaries at
March 31, 1996 and December 31, 1995, and the results of operations and cash
flows for the three months ended March 31, 1996 and 1995. 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, 1995, 1994 and 1993 included in the Company's 1995 Annual Report
filed with the Securities and Exchange Commission on Form 10-K.
Because of seasonal and other factors, the results of operations for the
three month period ended March 31, 1996 should not be taken as an indication of
earnings for all or any part of the balance of the year.
16
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF
PUBLIC SERVICE COMPANY OF COLORADO
We have reviewed the accompanying consolidated condensed balance sheet of Public
Service Company of Colorado (a Colorado corporation) and subsidiaries as of
March 31, 1996, and the related consolidated condensed statements of income and
cash flows for the three month periods ended March 31, 1996 and 1995. 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, 1995 (not presented herein), and, in our
report dated February 15, 1996, 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, 1995, is fairly stated,
in all material respects, in relation to the consolidated balance sheet from
which it has been derived.
ARTHUR ANDERSEN LLP
Denver, Colorado,
May 10, 1996
17
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Earnings
Earnings per share were $0.97 for the first quarter of 1996 as compared to
$0.81 for the first quarter of 1995. The higher earnings were primarily
attributable to increased electric and gas margins due to higher retail sales
and lower operating and maintenance expenses resulting from the favorable impact
of the February 9, 1996 settlement agreement with the DOE resolving all spent
nuclear fuel storage and disposal issues at Fort St. Vrain (See Note 2. Fort St.
Vrain in Item 1. FINANCIAL STATEMENTS).
Electric Operations
The following table details the change in electric operating revenues and
energy costs for the first three months of 1996 as compared to the same period
in 1995.
Increase (Decrease)
-------------------
(Thousands of Dollars)
Electric operating revenues:
Retail............................................... $ 11,896
Wholesale............................................ (533)
Other (including unbilled revenues).................. (7,829)
------
Total revenues...................................... 3,534
Fuel used in generation............................... (848)
Purchased power....................................... 957
---
Net increase in electric margin..................... $ 3,425
========
The following table compares electric Kwh sales by major customer classes
for the first quarter of 1996 and 1995.
Millions of Kwh Sales
1996 1995 % Change *
---- ---- ----------
Residential ................................ 1,833 1,728 6.1%
Commercial and Industrial ................. 3,776 3,690 2.3
Public Authority ........................... 51 48 6.2
-- --
Total Retail.............................. 5,660 5,466 3.5
Wholesale................................... 792 794 (0.3)
--- ---
Total.................................... 6,452 6,260 3.1
===== =====
* Percentages are calculated using unrounded amounts
Electric operating revenues increased in the first quarter of 1996, when
compared to the first quarter of 1995, primarily due to higher electric Kwh
retail sales resulting from residential customer growth offset, in part, by
lower unbilled revenues ($7.1 million).
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. As a
result, the changes in revenues associated with these mechanisms during the
first quarters of 1996 and 1995 had little impact on net income. A majority of
purchased power costs associated with QFs have historically been collected
through the QFCCA, a cost adjustment mechanism; however, the future recovery of
costs under the QFCCA has been modified by the CPUC and will be subject to an
earnings test, beginning October 1, 1996. The Company intends to address this
issue in connection with the merger rate filing. This earnings test, if not
changed or eliminated, may negatively impact the ability of the Company to earn
a rate of return on common equity in excess of its current 11% allowed return in
the electric department (see Note 4. Commitments and Contingencies-Regulatory
Matters in Item 1. FINANCIAL STATEMENTS).
18
<PAGE>
Fuel used in generation expense decreased approximately $848,000 or 1.8%
during the first quarter of 1996, as compared to the same quarter in 1995, due
to slightly lower coal costs from the renegotiation of certain contracts as
generation levels were about the same for both periods.
Purchased power expense increased approximately $957,000 or 0.8% in the
first three months of 1996 as compared to the same period in 1995, primarily due
to an increase in economy purchases from other utilities to meet customer
demand.
Gas Operations
The following table details the change in gas operating revenues and gas
purchased for resale for the first three months of 1996 as compared to the same
period in 1995.
Increase (Decrease)
-------------------
(Thousands of Dollars)
Gas operating revenues................................ $ (2,329)
Less: gathering, processing and transportation revenues 31
--
Revenues from gas sales.............................. (2,360)
Gas purchased for resale.............................. (7,411)
------
Net increase in gas sales margin..................... $ 5,051
========
The following table compares gas Mcf deliveries by major customer classes
for the first quarter of 1996 and 1995.
Millions of Mcf Deliveries
1996 1995 % Change *
---- ---- ----------
Residential................................ 46.3 40.8 13.5%
Commercial and Industrial.................. 27.2 23.5 15.5
---- ----
Total Sales.............................. 73.5 64.3 14.2
Gathering and Processing................... 0.2 0.4 (46.2)
Transportation............................. 25.5 24.2 5.3
----- -----
Total.................................... 99.2 88.9 11.5
===== ====
* Percentages are calculated using unrounded amounts
Gas sales margin increased in the first quarter of 1996, when compared to
the first quarter of 1995, primarily due to higher retail gas sales resulting
from colder weather in the current period and moderate customer growth. The
weather was approximately 18.5% colder during the first quarter of 1996 as
compared to the same period in 1995. While total gas sales increased 14.2%,
revenues from gas sales decreased in the first three months of 1996, as compared
to the same period in 1995, primarily due to the effects of lower gas costs
which are recoverable through GCA mechanisms.
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 during the first quarters of 1996 and 1995 had little impact on net
income.
The fluctuations in gas sales impact the amount of gas the Company must
purchase and, therefore, affect total gas purchased for resale along with
increases and decreases in the per-unit cost of gas. The $7.4 million decrease
in gas purchased for resale for the first quarter of 1996 as compared to the
first quarter of 1995, is primarily due to lower per unit cost of gas offset, in
part, by the increase in gas purchases.
19
<PAGE>
Non-Fuel Operating Expenses
Other operating and maintenance expenses decreased $13.5 million or 12.9%
during the first quarter of 1996, when compared to the same quarter in 1995,
primarily due to the favorable impact of the February 9, 1996 settlement
agreement with the DOE resolving all spent nuclear fuel storage and disposal
issues at Fort St. Vrain (approximately $16 million) offset, in part, by costs
incurred during the first quarter of 1996 associated with the Merger ($2.8
million) and the settlement of certain environmental issues related to the
operations of the Hayden station. These items are discussed further in Note 2.
Fort St. Vrain, Note 3. Merger and Note 4. Commitments and Contingencies -
Environmental Issues, respectively, in Item 1. FINANCIAL STATEMENTS.
Depreciation and amortization expense increased approximately $1.7 million
or 4.8% in the first quarter of 1996, as compared to the same period in 1995,
primarily due to higher depreciation expense from property additions.
Taxes (other than income taxes) decreased $786,000 or 3.4% during the
first quarter of 1996, when compared to the same period in 1995, primarily due
to decreased payroll related taxes resulting from a reduced workforce and lower
property taxes.
The increase in income taxes for the first quarter of 1996, as compared to
the same period in 1995, is primarily due to higher pre-tax income, the tax
effects of certain merger costs incurred in 1996 which are non-deductible for
income tax purposes and the accrual of additional tax liabilities for prior
years.
The change in miscellaneous income and deductions - net was primarily due
to the 1995 recognition of a $2.1 million refund obligation related to the sale
of WestGas Gathering, Inc. in accordance with a 1995 settlement agreement with
the OCC.
Financial Position
The increase in accounts receivable at March 31, 1996, as compared to the
amount at December 31, 1995, was due to the impact of a gas refund made late in
1995. The majority of this gas refund was applied directly to customers'
accounts during the fourth quarter of 1995 which served to lower accounts
receivable at December 31, 1995.
Recovered purchased gas and electric energy costs - net increased
approximately $28.3 million at March 31, 1996 as compared to December 31, 1995,
primarily due to lower gas costs charged by the Company's suppliers. Effective
April 2, 1996, as approved by the CPUC, natural gas rates were reduced by
approximately $44 million on an annual basis which will serve to minimize any
future overrecovery of purchased gas costs. This reduction will have no impact
on net income. The decrease in accounts payable is also primarily attributable
to lower gas costs.
The decrease in noncurrent defueling and decommissioning liability of
$23.1 million was primarily due to expenditures during the first quarter of 1996
and the February 9, 1996 settlement agreement with the DOE resolving all spent
nuclear fuel storage and disposal issues at Fort St. Vrain (See Note 2. Fort St.
Vrain in Item 1. FINANCIAL STATEMENTS). Customer advances for construction
decreased by approximately $41.9 million due to a 1996 transfer of amounts to
property, plant and equipment, which served to reduce such investments, after
determining that these amounts would not be refunded to customers in the future.
Recently Issued Accounting Standards Adopted
In March 1995, the FASB issued SFAS 121, which requires the Company to
review long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. This statement also imposes stricter criteria for continued
recognition of regulatory assets by requiring that such assets be probable of
future recovery at each balance sheet date. The Company adopted this standard on
20
<PAGE>
January 1, 1996, the effective date of this new statement, and such adoption did
not have a material impact on the Company's results of operations, financial
position or cash flows.
Commitments and Contingencies
Issues relating to the Merger with SPS, and regulatory and environmental
matters are discussed in Notes 3 and 4, respectively, in Item 1. FINANCIAL
STATEMENTS. These matters and the future resolution thereof, may impact the
Company's future results of operations, financial position and cash flows.
Common Stock Dividend
In the first quarter of 1996, the Company increased the quarterly dividend
on its common stock from $0.51 per share to $0.525 per share. The Company's
common stock dividend level is dependent upon the Company's results of
operations, financial position, cash flows and other factors. The Board of
Directors will continue to evaluate the common stock dividend level on a
quarterly basis.
Liquidity and Capital Resources
Cash Flows - Three Months Ended March 31
1996 1995
---- ----
Net cash provided by operating activities (in millions) $123.3 $ 178.0
Cash provided by operating activities decreased approximately $54.7
million in the first quarter of 1996 when compared to the first quarter of 1995
primarily due to an increase in accounts receivable ($35.6 million) and a
decrease in the recovery of purchased gas and electric energy costs ($19.9
million). The increase in accounts receivable was due to a gas refund made late
in 1995 which was applied directly to customers' accounts resulting in lower
cash receipts during the first quarter of 1996. The decrease in recovered
purchased gas and electric energy costs was due to a reduction in the level of
over collection of these costs in the first quarter of 1996, as compared to the
first quarter of 1995, thereby also lowering cash receipts during the first
quarter of 1996.
At March 31, 1996, the Company's decommissioning liability, excluding
defueling, was approximately $23.9 million. The expenditures related to this
obligation are expected to be incurred during the remainder of 1996. The annual
decommissioning amount being recovered from customers is approximately $13.9
million which will continue through June 2005. At March 31, 1996, approximately
$95.8 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 completed later in 1996.
1996 1995
---- ----
Net cash used in investing activities (in millions) $(60.7) $(61.1)
Cash used in investing activities, which substantially consists of
construction expenditures, decreased only slightly for the first quarter of
1996, when compared to the same period in 1995, reflecting a consistent level of
capital expenditures between the quarters.
1996 1995
---- ----
Net cash used in financing activities (in millions) $(64.8) $(109.2)
Cash used in financing activities decreased (indicating there were more
borrowings) in the first quarter of 1996, when compared to the first quarter of
1995, primarily due to increases in short-term borrowings ($39.9 million) to
meet operating cash requirements as discussed above.
21
<PAGE>
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Part 1. Issues relating to decommissioning and defueling are discussed in
Note 2. Fort St. Vrain and issues relating to the recovery of energy
efficiency credits, environmental site cleanup and other
environmental matters, employee litigation and union contracts are
discussed in Note 4. Commitments and Contingencies in Item 1, Part
1.
Item 4. Submission of Matters to a Vote of Security Holders
On January 31, 1996, the Company held a Special Meeting of Shareholders at
which shareholders were asked to approve the Merger Agreement pursuant to which
the holders of Company common stock and holders of SPS common stock will become
holders of the common stock of NCE upon the completion of the Merger. The Merger
was approved by the shareholders. Of the shares voted, 50,934,837, 1,366,283,
and 824,460 votes were cast for, against and abstained, respectively (see Note
3. Merger in Item 1, Part 1). Approximately 72% of the Company's outstanding
shares of common and preferred stock were voted in favor of the Merger. An
affirmative vote of two-thirds of the outstanding shares was required for
approval.
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 25 herein.
12(b) Computation of Ratio of Consolidated Earnings to Consolidated
Combined Fixed Charges and Preferred Stock Dividends is set forth at
page 26 herein.
15 Letter from Arthur Andersen LLP regarding unaudited interim information
is set forth at page 27 herein.
27 Financial Data Schedule UT
(b) Reports on Form 8-K
A report on Form 8-K, dated January 18, 1996, was filed on January 29,
1996. The item reported was Item 5 - Other Events, which presented updated
information related to litigation, a notice of violation issued by the EPA and
environmental matters associated with the operations of the Hayden Steam
Electric Generating Station.
A report on Form 8-K, dated January 31, 1996, was filed on February 1,
1996. The item reported was Item 5 - Other Events, which reported that on
January 31, 1996, at separate meetings of shareholders, the holders of Company
Common Stock, Company Preferred Stock, and SPS Common Stock approved the Merger
Agreement.
22
<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
By /s/ R. C. Kelly
---------------------------------
R. C. KELLY
Senior Vice President,
Finance, Treasurer and
Chief Financial Officer
Dated: May 14, 1996
23
<PAGE>
EXHIBIT INDEX
12(a) Computation of Ratio of Consolidated Earnings to Consolidated
Fixed Charges is set forth at page 25 herein.
12(b) Computation of Ratio of Consolidated Earnings to Consolidated
Combined Fixed Charges and Preferred Stock Dividends is set forth
at page 26 herein.
15 Letter from Arthur Andersen LLP regarding unaudited interim information
is set forth at page 27 herein.
27 Financial Data Schedule UT.
24
<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)
Three Months Ended
March 31,
1996 1995
---- ----
(Thousands of Dollars, except ratios)
Fixed charges:
Interest on long-term debt................... $ 22,068 $ 21,506
Interest on borrowings against corporate-owned
life insurance contracts................... 9,258 7,969
Other interest............................... 4,413 5,339
Amortization of debt discount and expense less
premium ................................... 977 791
Interest component of rental expense......... 2,746 1,690
----- -----
Total ..................................... $ 39,462 $ 37,295
======== ========
Earnings (before fixed charges and taxes on income):
Net income................................... $ 64,429 $ 53,644
Fixed charges as above....................... 39,462 37,295
Provisions for Federal and state taxes on income,
net of investment tax credit amortization.... 41,146 29,334
------ ------
Total...................................... $145,037 $120,273
======== ========
Ratio of earnings to fixed charges.............. 3.68 3.22
==== ====
25
<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)
Three Months Ended
March 31,
1996 1995
---- ----
(Thousands of Dollars, except ratios)
Fixed charges and preferred stock dividends:
Interest on long-term debt.................. $ 22,068 $ 21,506
Interest on borrowings against corporate-owned
life insurance contracts.................. 9,258 7,969
Other interest.............................. 4,413 5,339
Amortization of debt discount and expense less
premium .................................. 977 791
Interest component of rental expense........ 2,746 1,690
Preferred stock dividend requirement........ 2,972 3,001
Additional preferred stock dividend requirement 1,898 1,641
----- -----
Total .................................... $ 44,332 $ 41,937
======== ========
Earnings (before fixed charges and taxes on income):
Net income.................................. $ 64,429 $ 53,644
Interest on long-term debt.................. 22,068 21,506
Interest on borrowings against corporate-owned
life insurance contracts.................. 9,258 7,969
Other interest.............................. 4,413 5,339
Amortization of debt discount and expense less
premium .................................. 977 791
Interest component of rental expense........ 2,746 1,690
Provisions for Federal and state taxes on
income, net of investment tax credit
amortization ............................. 41,146 29,334
------ ------
Total..................................... $145,037 $120,273
======== ========
Ratio of earnings to fixed charges
and preferred stock dividends................ 3.27 2.87
==== ====
26
<PAGE>
EXHIBIT 15
May 10, 1996
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 March 31, 1996, which includes our report dated
May 10, 1996, 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
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial
information extracted from Public Service Company
of Colorado and Subsidiaries consolidated balance
sheet as of March 31,1996 and consolidated statements
of income and cash flows for the three months ended
March 31, 1996
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> MAR-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,467,182
<OTHER-PROPERTY-AND-INVEST> 35,553
<TOTAL-CURRENT-ASSETS> 461,767
<TOTAL-DEFERRED-CHARGES> 375,770
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,340,272
<COMMON> 319,235
<CAPITAL-SURPLUS-PAID-IN> 694,129
<RETAINED-EARNINGS> 374,477
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,387,841
41,289
140,008
<LONG-TERM-DEBT-NET> 1,193,862
<SHORT-TERM-NOTES> 68,425
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 199,495
<LONG-TERM-DEBT-CURRENT-PORT> 67,895
2,576
<CAPITAL-LEASE-OBLIGATIONS> 48,000
<LEASES-CURRENT> 4,577
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,238,881
<TOT-CAPITALIZATION-AND-LIAB> 4,340,272
<GROSS-OPERATING-REVENUE> 622,917
<INCOME-TAX-EXPENSE> 41,146
<OTHER-OPERATING-EXPENSES> 76,646
<TOTAL-OPERATING-EXPENSES> 520,827
<OPERATING-INCOME-LOSS> 102,090
<OTHER-INCOME-NET> (2,017)
<INCOME-BEFORE-INTEREST-EXPEN> 100,073
<TOTAL-INTEREST-EXPENSE> 35,644
<NET-INCOME> 64,429
2,972
<EARNINGS-AVAILABLE-FOR-COMM> 61,457
<COMMON-STOCK-DIVIDENDS> 33,520
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 123,296
<EPS-PRIMARY> 0.525
<EPS-DILUTED> 0.525
</TABLE>
