PUBLIC SERVICE CO OF COLORADO, 10-Q, 1995-08-10

PUBLIC SERVICE CO OF COLORADO
10-Q, 1995-08-10
ELECTRIC & OTHER SERVICES COMBINED

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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 June 30, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________
to________________
Commission file number 1-3280

Public Service Company of Colorado
(Exact name of registrant as specified in its charter)

Colorado 84-0296600
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)

1225 17th Street, Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)

Registrant's Telephone Number, including area code: 303/571-7511

Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.Yes x No

At August 4, 1995, 63,109,140 shares of the registrant's Common
Stock, $5.00 par value (the only class of common stock), were outstanding.

<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 . . . . . . . . 18

PART II - OTHER INFORMATION

Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . 25

Item 4. Submission of Matters to a Vote of Security Holders . . . . . . 25

Item 5. Other Information . . . . . . . . . . . . . . . . . . . . . . . 25

Item 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . . . . . . 25

SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

EXHIBIT INDEX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

EXHIBIT 12(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

EXHIBIT 12(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

EXHIBIT 15 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
<PAGE>

PART 1 - FINANCIAL INFORMATION
Item 1. Financial Statements

PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Thousands of Dollars)

ASSETS

<TABLE>
<CAPTION>
June 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
Property, plant and equipment, at cost:
Electric . . . . . . . . . . . . . . . . . . . . . . . $ 3,711,283 $3,641,711
Gas . . . . . . . . . . . . . . . . . . . . . . . . . 891,691 867,239
Steam and other . . . . . . . . . . . . . . . . . . . 88,206 86,458
Common to all departments . . . . . . . . . . . . . . 387,734 369,070
Construction in progress . . . . . . . . . . . . . . . 202,895 187,577
5,281,809 5,152,055
Less: accumulated depreciation . . . . . . . . . . . . 1,923,397 1,860,653
Total property, plant and equipment . . . . . . . . 3,358,412 3,291,402

Investments, at cost . . . . . . . . . . . . . . . . . . 25,055 18,202

Current assets:
Cash and temporary cash investments . . . . . . . . . 5,791 5,883
Accounts receivable, less reserve for
uncollectible accounts ($4,022 at June 30, 1995;
$3,173 at December 31, 1994) . . . . . . . . . . . . 138,758 163,465
Accrued unbilled revenues . . . . . . . . . . . . . . 69,716 86,106
Recoverable purchased gas and electric
energy costs - net . . . . . . . . . . . . . . . . . - 37,979
Materials and supplies, at average cost . . . . . . . 66,572 67,600
Fuel inventory, at average cost . . . . . . . . . . . 36,501 31,370
Gas in underground storage, at cost (LIFO) . . . . . . 19,794 42,355
Current portion of accumulated deferred income taxes . 31,325 20,709
Regulatory assets recoverable within one year (Note 1) 39,728 39,985
Prepaid expenses and other . . . . . . . . . . . . . . 15,466 16,312
Total current assets . . . . . . . . . . . . . . . . 423,651 511,764

Deferred charges:
Regulatory assets (Note 1) . . . . . . . . . . . . . . 328,331 335,893
Unamortized debt expense . . . . . . . . . . . . . . . 10,720 11,073
Other . . . . . . . . . . . . . . . . . . . . . . . . 41,337 39,498
Total deferred charges . . . . . . . . . . . . . . . 380,388 386,464
$ 4,187,506 $4,207,832

The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.

</TABLE>

1
<PAGE>

PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Thousands of Dollars)

CAPITAL AND LIABILITIES

<TABLE>
<CAPTION>
June 30, December 31,
1995 1994
(Unaudited)
<S> <C> <C>
Common stock . . . . . . . . . . . . . . . . . . . . . . $ 982,886 $ 959,268
Retained earnings . . . . . . . . . . . . . . . . . . . . 320,048 308,214
Total common equity . . . . . . . . . . . . . . . . . 1,302,934 1,267,482

Preferred stock:
Not subject to mandatory redemption . . . . . . . . . 140,008 140,008
Subject to mandatory redemption at par . . . . . . . . 42,665 42,665
Long-term debt . . . . . . . . . . . . . . . . . . . . . 1,081,746 1,155,427
2,567,353 2,605,582

Noncurrent liabilities:
Defueling and decommissioning liability (Note 2) . . . 24,315 40,605
Employees' postretirement benefits other
than pensions . . . . . . . . . . . . . . . . . . . 45,799 42,106
Employees' postemployment benefits . . . . . . . . . . 20,975 20,975
Total noncurrent liabilities . . . . . . . . . . . . 91,089 103,686

Current liabilities:
Notes payable and commercial paper . . . . . . . . . . 286,300 324,800
Long-term debt due within one year . . . . . . . . . . 83,174 25,153
Preferred stock subject to mandatory
redemption within one year . . . . . . . . . . . . . 2,576 2,576
Accounts payable . . . . . . . . . . . . . . . . . . . 136,506 177,031
Dividends payable . . . . . . . . . . . . . . . . . . 35,091 34,078
Recovered purchased gas and electric energy costs - net 50,064 -
Customers' deposits . . . . . . . . . . . . . . . . . 17,955 17,099
Accrued taxes . . . . . . . . . . . . . . . . . . . . 36,641 54,148
Accrued interest . . . . . . . . . . . . . . . . . . . 31,164 32,265
Current portion of defueling and decommissioning
liability (Note 2) . . . . . . . . . . . . . . . . . 40,415 36,365
Other . . . . . . . . . . . . . . . . . . . . . . . . 64,447 62,640
Total current liabilities . . . . . . . . . . . . . 784,333 766,155

Deferred credits:
Customers' advances for construction . . . . . . . . . 104,948 96,442
Unamortized investment tax credits . . . . . . . . . . 116,045 118,532
Accumulated deferred income taxes . . . . . . . . . . 492,948 485,668
Other . . . . . . . . . . . . . . . . . . . . . . . . 30,790 31,767
Total deferred credits . . . . . . . . . . . . . . . 744,731 732,409

Commitments and contingencies (Notes 2 and 3) . . . . . .
$ 4,187,506 $4,207,832

The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.
</TABLE>

2
<PAGE>

PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(Unaudited)
(Thousands of Dollars except per share data)

<TABLE>
<CAPTION>
Three Months Ended June 30,
1995 1994
<S> <C> <C>
Operating revenues:
Electric . . . . . . . . . . . . . . . . . . . . . . . $ 341,516 $ 339,980
Gas . . . . . . . . . . . . . . . . . . . . . . . . . 148,312 130,317
Other . . . . . . . . . . . . . . . . . . . . . . . . 8,871 7,266
498,699 477,563
Operating expenses:
Fuel used in generation . . . . . . . . . . . . . . . 43,935 48,143
Purchased power . . . . . . . . . . . . . . . . . . . 117,983 103,396
Gas purchased for resale . . . . . . . . . . . . . . . 102,164 83,899
Other operating expenses . . . . . . . . . . . . . . . 86,734 95,640
Maintenance . . . . . . . . . . . . . . . . . . . . . 16,156 18,069
Depreciation and amortization . . . . . . . . . . . . 35,027 36,382
Taxes (other than income taxes) . . . . . . . . . . . 21,412 22,441
Income taxes . . . . . . . . . . . . . . . . . . . . . 12,654 11,566
436,065 419,536
Operating income . . . . . . . . . . . . . . . . . . . . 62,634 58,027

Other income and deductions:
Allowance for equity funds used during construction . 1,107 1,078
Miscellaneous income and deductions - net . . . . . . 101 (2,712)
1,208 (1,634)
Interest charges:
Interest on long-term debt . . . . . . . . . . . . . . 21,337 22,018
Amortization of debt discount and expense less premium 806 802
Other interest . . . . . . . . . . . . . . . . . . . . 14,403 10,590
Allowance for borrowed funds used during construction (959) (892)
35,587 32,518
Net income . . . . . . . . . . . . . . . . . . . . . . . 28,255 23,875
Dividend requirements on preferred stock . . . . . . . . 3,000 3,005
Earnings available for common stock . . . . . . . . . . . $ 25,255 $ 20,870

Weighted average common shares outstanding (thousands) . 62,846 61,425

Earnings per weighted average
share of common stock outstanding . . . . . . . . . . $ 0.40 $ 0.34

Dividends per share declared on common stock . . . . . . $ 0.51 $ 0.50

The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.
</TABLE>

3
<PAGE>

PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(Unaudited)
(Thousands of Dollars except per share data)

<TABLE>
<CAPTION>
Six Months Ended June 30,
1995 1994
<S> <C> <C>
Operating revenues:
Electric . . . . . . . . . . . . . . . . . . . . . . . $ 708,099 $ 688,264
Gas . . . . . . . . . . . . . . . . . . . . . . . . . 392,869 385,321
Other . . . . . . . . . . . . . . . . . . . . . . . . 18,327 16,414
1,119,295 1,089,999
Operating expenses:
Fuel used in generation . . . . . . . . . . . . . . . 91,120 101,511
Purchased power . . . . . . . . . . . . . . . . . . . 239,461 209,864
Gas purchased for resale . . . . . . . . . . . . . . . 270,299 261,413
Other operating expenses . . . . . . . . . . . . . . . 176,548 189,904
Maintenance . . . . . . . . . . . . . . . . . . . . . 30,860 34,502
Depreciation and amortization . . . . . . . . . . . . 70,193 73,300
Taxes (other than income taxes) . . . . . . . . . . . 44,503 45,120
Income taxes . . . . . . . . . . . . . . . . . . . . . 41,988 37,928
964,972 953,542
Operating income . . . . . . . . . . . . . . . . . . . . 154,323 136,457

Other income and deductions:
Allowance for equity funds used during construction . 1,858 2,143
Miscellaneous income and deductions - net . . . . . . (3,782) (3,150)
(1,924) (1,007)
Interest charges:
Interest on long-term debt . . . . . . . . . . . . . . 42,843 45,183
Amortization of debt discount and expense less premium 1,597 1,528
Other interest . . . . . . . . . . . . . . . . . . . . 27,711 19,986
Allowance for borrowed funds used during construction (1,651) (1,651)
70,500 65,046
Net income . . . . . . . . . . . . . . . . . . . . . . . 81,899 70,404
Dividend requirements on preferred stock . . . . . . . . 6,001 6,010
Earnings available for common stock . . . . . . . . . . . $ 75,898 $ 64,394

Weighted average common shares outstanding (thousands) . 62,680 61,172

Earnings per weighted average
share of common stock outstanding . . . . . . . . . . $ 1.21 $ 1.05

Dividends per share declared on common stock . . . . . . $ 1.02 $ 1.00

The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.
</TABLE>

4
<PAGE>

PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
(Thousands of Dollars)

<TABLE>
<CAPTION>
Six Months Ended June 30,
1995 1994

<S> <C> <C>
Operating activities:
Net income . . . . . . . . . . . . . . . . . . . . . . $ 81,899 $ 70,404
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization . . . . . . . . . . 72,159 74,647
Amortization of investment tax credits . . . . . . (2,487) (2,516)
Deferred income taxes . . . . . . . . . . . . . . 3,179 17,726
Allowance for equity funds used during construction (1,858) (2,143)
Change in accounts receivable . . . . . . . . . . 24,707 22,958
Change in inventories . . . . . . . . . . . . . . 18,458 30,552
Change in other current assets . . . . . . . . . . 54,574 54,015
Change in accounts payable . . . . . . . . . . . . (40,525) (78,958)
Change in other current liabilities . . . . . . . 47,991 321
Change in deferred amounts . . . . . . . . . . . . 710 (46,930)
Change in noncurrent liabilities . . . . . . . . . (12,596) 7,607
Other . . . . . . . . . . . . . . . . . . . . . . 65 32
Net cash provided by operating activities . . . 246,276 147,715

Investing activities:
Construction expenditures . . . . . . . . . . . . . . (119,605) (128,756)
Allowance for equity funds used during construction . 1,858 2,143
Proceeds from (cost of) disposition of property,
plant and equipment . . . . . . . . . . . . . . . . . (11,933) 26,433
Purchase of other investments . . . . . . . . . . . . (7,283) (938)
Sale of other investments . . . . . . . . . . . . . . 365 530
Net cash used in investing activities . . . . . (136,598) (100,588)

Financing activities:
Proceeds from sale of common stock . . . . . . . . . . 13,796 22,273
Proceeds from sale of long-term debt . . . . . . . . . 22,135 244,448
Redemption of long-term debt . . . . . . . . . . . . . (38,149) (280,579)
Short-term borrowings - net . . . . . . . . . . . . . (38,500) 23,400
Dividends on common stock . . . . . . . . . . . . . . (63,051) (60,807)
Dividends on preferred stock . . . . . . . . . . . . . (6,001) (6,010)
Net cash used in financing activities . . . . . (109,770) (57,275)
Net decrease in cash and temporary
cash investments . . . . . . . . . . . . . . . (92) (10,148)
Cash and temporary cash investments at
beginning of period . . . . . . . . . . . . . 5,883 18,038
Cash and temporary cash investments at
end of period . . . . . . . . . . . . . . . . $ 5,791 $ 7,890

The accompanying notes to consolidated condensed financial statements
are an integral part of these financial statements.
</TABLE>

5
<PAGE>

PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)

1. Accounting Policies

Business and regulation

The Company is an operating public utility engaged, together with
its subsidiaries, principally in the generation, purchase, transmission,
distribution and sale of electricity and in the purchase, transmission,
distribution, sale and transportation of natural gas. The Company is
subject to the jurisdiction of The Public Utilities Commission of the
State of Colorado ("CPUC") with respect to its retail electric and gas
operations and the Federal Energy Regulatory Commission ("FERC") with
respect to its wholesale electric operations and accounting policies and
practices. Cheyenne Light, Fuel and Power Company ("Cheyenne") and
WestGas InterState, Inc. ("WGI") are subject to the jurisdictions of the
Public Service Commission of Wyoming ("WPSC") and the FERC, respectively.

Regulatory assets and liabilities

The Company and its regulated subsidiaries prepare their financial
statements in accordance with the provisions of Statement of Financial
Accounting Standards No. 71 - "Accounting for the Effects of Certain Types
of Regulation" ("SFAS 71"). In general, SFAS 71 recognizes that
accounting for rate regulated enterprises should reflect the relationship
of costs and revenues introduced by rate regulation. As a result, a
regulated utility may defer recognition of a cost (a regulatory asset) or
recognize an obligation (a regulatory liability) if it is probable that,
through the ratemaking process, there will be a corresponding increase or
decrease in revenues.

In response to the increasingly competitive environment for
utilities, the regulatory climate also is changing. Currently, the
Company is participating in several CPUC dockets that address this change,
and it is in the process of investigating various incentive/performance-
based alternative forms of regulation. However, the Company believes it
will continue to be subject to rate regulation that will allow for the
recovery of all of its deferred costs. Although the Company does not
currently anticipate such an event, to the extent the Company concludes in
the future that collection of such revenues (or payment of liabilities) is
no longer probable, through changes in regulation and/or the Company's
competitive position, the Company may be required to recognize as expense,
at a minimum, all deferred costs currently recognized as regulatory assets
on the consolidated condensed balance sheet.

In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 121 "Accounting for the
Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of"
("SFAS 121"). SFAS 121 imposes stricter criteria for the continued
recognition of regulatory assets on the balance sheet by requiring that
such assets be probable of future recovery at each balance sheet date. The
Company anticipates adopting this standard on January 1, 1996, the
effective date of the new statement, and does not expect that adoption
will have a material impact on the Company's results of operations,
financial position or cash flow.

6
<PAGE>

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)

The following regulatory assets are reflected in the Company's
consolidated condensed balance sheets:
<TABLE>
<CAPTION>
June 30, December 31, Recovery
1995 1994 Through
(Thousands of Dollars)
<S> <C> <C> <C>
Nuclear decommissioning costs (Note 2) $ 102,427 $ 107,374 2005
Income taxes . . . . . . . . . . . . . 119,317 125,832 2006
Employees' postretirement benefits other
than pensions . . . . . . . . . . . . 42,586 37,573 2013
Early retirement costs . . . . . . . . 28,606 33,124 1998
Employees' postemployment benefits . . 20,975 20,975 Undetermined
Demand-side management costs . . . . . 24,263 20,831 2002
Unamortized debt reacquisition costs . 22,952 22,360 2024
Other . . . . . . . . . . . . . . . . . 6,933 7,809 1999
Total . . . . . . . . . . . . . . . . 368,059 375,878
Classified as current . . . . . . . . . 39,728 39,985
Classified as noncurrent . . . . . . . $ 328,331 $ 335,893
</TABLE>

Recovered/Recoverable purchased gas and electric energy costs - net

The Company and Cheyenne tariffs contain clauses which allow recovery of
certain purchased gas and electric energy costs in excess of the level of such
costs included in base rates. These cost adjustment tariffs are revised
periodically, as prescribed by the appropriate regulatory agencies, for any
difference between the total amount collected under the clauses and the
recoverable costs incurred. A substantial portion of this deferred amount
represents the costs incurred to provide gas and electric energy which
customers have used but for which they have not yet been billed. The
cumulative effects are recognized as a current asset or liability until
adjusted by refunds or collections through future billings to customers.

Other

Property, plant and equipment includes approximately $18.4 million and
$25.4 million, respectively, for costs associated with the engineering design
of the future Pawnee II generating station and certain water rights located in
southeastern Colorado, also obtained for a future generating station.
Effective with the December 1, 1993 CPUC rate order, the Company is earning a
return on these investments based on the Company's weighted average cost of
debt and preferred stock.

Statements of Cash Flows - Non cash Transactions

Shares of common stock (310,546 in 1995 and 334,223 in 1994), valued at
the market price on date of issuance (approximately $9.7 million in 1995 and
$10.1 million in 1994), were issued to the Employees' Savings and Stock
Ownership Plan of Public Service Company of Colorado and Participating
Subsidiary Companies. These estimated issuance values were recognized in
other operating expenses during the respective preceding years.

As part of the Company's Omnibus Incentive Plan, shares of common stock
(3,891 in 1995 and 7,892 in 1994), valued at the market price on date of

7
<PAGE>

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)

issuance (approximately $0.1 million in 1995 and $0.2 million in 1994), were
issued to certain executives.

These stock issuances were not cash transactions and are not reflected
in the consolidated condensed statements of cash flows.

2. Fort St. Vrain

Overview

During 1986, the Company entered into a Stipulation and Settlement
Agreement with the CPUC, the Office of Consumer Counsel ("OCC") and the other
parties involved in litigation and administrative proceedings related to Fort
St. Vrain's history of limited operations. As a result, the Company's
investment in Fort St. Vrain was removed from rate base and certain charges
were recognized including the write-down of a substantial portion of such
investment and the recognition of the then estimated future unrecoverable
defueling and decommissioning expenses.

In 1989, the Company announced its decision to end nuclear operations at
Fort St. Vrain. The decision was based on the financial impact of an
anticipated lengthy outage necessary to repair the plant's steam generator
system coupled with the plant's history of reduced levels of generation. The
Company has completed defueling from the reactor to the Independent Spent Fuel
Storage Installation ("ISFSI") as discussed below in the section entitled
"Defueling" and is currently decommissioning the facility as described below
in the section entitled "Decommissioning."

The Company is pursuing the repowering of Fort St. Vrain as described
below and, on July 1, 1994, the CPUC issued a decision granting the Company's
application for a Certificate of Public Convenience and Necessity ("CPCN") for
Phase 1 and Phase 2. The decision approved, with certain modifications, a
Stipulation and Settlement Agreement (the "Settlement") among the Company, the
OCC and various other parties regarding the CPCN.

Repowering

Fort St. Vrain is being repowered as a gas fired combined cycle steam
plant consisting of two combustion turbines and two heat recovery steam
generators totalling 471 Mw. The CPCN provides for the repowering of Fort St.
Vrain in a phased approach as follows: Phase 1A - 130 Mw in 1996, Phase 1B -
102 Mw in 1998 and Phase 2 - 239 Mw in 1999. The phased repowering allows the
Company flexibility in timing the addition of this generation supply to meet
future load growth.

The Settlement provides for approximately $67.4 million of existing Fort
St. Vrain assets to be returned to rate base in future electric rate cases
following the completion of each phase or phases of the repowering. The
Settlement allows for the following assignment of existing assets: Phase 1A -
$28.9 million, Phase 1B - $27.6 million and Phase 2 - $10.9 million. Because
of the receipt of the CPCN related to the repowering of Fort St. Vrain, the
Company believes the recovery of this remaining investment in the facility is
probable.

On July 17, 1995, the Nuclear Regulatory Commission ("NRC") approved the
final radiation survey report of the repowering area prepared by the Company.

8
<PAGE>

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)

The Company reported that the survey data met unrestricted release criteria
permitting such area to be released.

Decommissioning

The Company has been pursuing the early dismantlement/decommissioning of
Fort St. Vrain following the 1991 CPUC approval of the recovery from customers
of approximately $124.4 million (plus a 9% carrying cost) for such activities,
as well as the 1992 NRC approval of the Company's early
dismantlement/decommissioning plan. The decommissioning amount being
recovered from customers, which began July 1, 1993 and extends over a twelve-
year period, represented the inflation-adjusted estimated remaining cost of
the early dismantlement/decommissioning activities not previously recognized
as expense at the time of CPUC approval. At June 30, 1995, approximately
$102.4 million of such amount remains to be collected from customers and,
therefore, is reflected as a regulatory asset on the consolidated condensed
balance sheet. The amount recovered from customers each year is approximately
$13.9 million.

The Company has contracted with Westinghouse Electric Corporation and
MK-Ferguson, a division of Morrison Knudsen Corporation, for the early
dismantlement/decommissioning of Fort St. Vrain. At June 30, 1995,
approximately 85% of the decommissioning process has been performed with final
completion of such activities anticipated in the second quarter of 1996.

The decommissioning contract stipulates a fixed price, based on a
defined work scope; however, such price has been and could be further modified
due to changes in work scope or applicable regulations. Since the initiation
of decommissioning activities, the decommissioning contractors have notified
the Company of several scope changes which were primarily related to the
identification of higher radiation levels in the reactor core than originally
anticipated and regulatory changes related to site release as discussed below.

On October 25, 1994, the Company and the decommissioning contractors
reached an agreement resolving all issues and claims related to identified and
certain possible future changes in scope of work covered by the contract, with
certain exceptions. In order to complete all decommissioning activities
related to such scope changes, the Company recognized an additional $15
million in decommissioning expense during 1994.

The significant exceptions to the agreement, which were also areas for
potential changes in the defined work scope under the decommissioning
contract, include changes in law, radioactive material created by activation
in the lower portion of the reactor, as well as changes in the methodology
requirements and guidance established by the NRC for final site release. On
January 26, 1995, the Company received NRC approval of its Final Survey Plan
for Site Release reducing the future uncertainty related to this issue. In
the event additional costs are identified, which relate to an issue excepted
from the agreement, the decommissioning contractors will perform all required
activities on a cost basis.

While this agreement with the decommissioning contractors does not
eliminate all future decommissioning risk, the Company believes it will serve
to substantially reduce such risk. However, the Company can provide no
assurance that recognition of additional costs will not be required if events
or circumstances unknown to the Company today are identified in the future.

9
<PAGE>

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)

Defueling

Currently, six segments of Fort St. Vrain's spent nuclear fuel (segments
4-9) are stored in the ISFSI located at the plant site. While the Company has
entered into two separate agreements with the Department of Energy ("DOE") for
(a) the temporary storage of segments 1-8 at a DOE facility located in the
State of Idaho (such contract includes an option to store additional spent
fuel segments at the DOE's discretion) and (b) the disposal of segment 9 at a
Federal repository, resolution of all spent fuel disposal issues has been
substantially delayed pending resolution of several lawsuits filed during 1991
by and among the Company, the DOE, the State of Idaho and the Shoshone -
Bannock Indian Tribes. While the plant was operating and as part of routine
refueling procedures, three spent fuel segments were transported to the Idaho
facility. It is currently estimated that the Federal repository will not be
available until 2010. The Company, however, intends to pursue with the DOE
the storage of segment 9 at the Idaho facility in conjunction with the first
eight segments. The Company and the DOE are in discussions regarding the
issues related to the disposal of Fort St. Vrain's spent nuclear fuel.

In April 1995, the DOE issued an Environmental Impact Statement ("EIS")
relative to, among other things, the receipt and storage of spent fuel at the
Idaho facility. In May 1995, the final record of decision was issued related
to such EIS. The EIS specifies a preferred alternative under which existing
environmental restoration and waste management facilities and projects would
continue to be operated, including Fort St. Vrain spent fuel nuclear fuel
shipment from the ISFSI and storage at the Idaho facility. However, following
the filing of a complaint by the State of Idaho contending that the EIS was
not complete, the U.S. District Court for the District of Idaho issued an
injunction prohibiting all shipments of spent fuel to the Idaho facility.
Additionally, modifications to the Idaho facility will be required to
accommodate the new spent fuel shipping casks. These modifications would be
completed subsequent to the resolution of the various issues related to the
EIS. The DOE's estimate of the time to complete the modification is between
15-18 months. Furthermore, the DOE has stated that a facility readiness
review will be required. Such review is standard DOE procedure required to
validate the readiness of equipment following a shut-down period. Such review
will also be conducted subsequent to the resolution of the various EIS issues.

As a result of increased uncertainties related to the ultimate disposal
of Fort St. Vrain's spent nuclear fuel, the Company recognized during 1994 an
additional $15 million defueling reserve, determined on a present value basis.
This amount represents the additional estimated cost of operating and
maintaining the ISFSI until 2020 (if required), the earliest date the Company
believes a Federal repository will be available to accept the Company's spent
nuclear fuel. These estimated expenditures have been escalated for inflation
using an average rate of 3.5% and discounted to present value at a rate of 8%.

The estimated total cost of defueling and decommissioning Fort St. Vrain
is approximately $361.8 million. At June 30, 1995, approximately $297.1
million has been spent for such activities with the remaining $64.7 million
defueling and decommissioning liability reflected on the consolidated
condensed balance sheet ($23.6 million - defueling; $41.1 million -
decommissioning). Because of the possibility of further changes in the
decommissioning work scope, changes in applicable regulations and/or the
uncertainties related to the final disposal of spent fuel, there can be no
assurance that the actual cost of defueling and decommissioning will not

10
<PAGE>

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)

exceed the estimated liability. The Company could be required to revise the
estimated cost of defueling and decommissioning as a result of any such
matters.

Funding

Under NRC regulations, the Company is required to make filings with, and
obtain the approval of, the NRC regarding certain aspects of the Company's
decommissioning proposals, including funding. On January 27, 1992, the NRC
accepted the Company's funding aspects of the decommissioning plan. The
Company has also obtained an unsecured irrevocable letter of credit totaling
$125 million that meets the NRC's stipulated funding guidelines including
those proposed on August 21, 1991 that address decommissioning funding
requirements for nuclear power reactors that have been prematurely shut down.
In accordance with the NRC funding guidelines, the Company is allowed to
reduce the balance of the letter of credit based upon milestone payments made
under the fixed-price decommissioning contract. As a result of such payments,
at June 30, 1995, the letter of credit had been reduced to $50 million.

The Company had previously set aside approximately $30 million in trust
accounts for decommissioning the reactor. Since commencement of
decommissioning, the Company completed withdrawing funds from the trust
accounts during the second quarter of 1993. As previously discussed, on July
1, 1993, the Company began collection of the remaining decommissioning costs
from customers.

In addition, the Company has established a separate decommissioning
trust for the ISFSI which had funds of approximately $1.7 million at June 30,
1995. It is anticipated that this amount, together with the expected earnings
on the funds, will be sufficient to decommission the ISFSI.

Costs for maintaining the ISFSI and removing fuel from the ISFSI, which
the Company is not required to prefund, will be paid from a combination of
operating funds of the Company and its subsidiaries and/or external financing.

Nuclear Insurance

The Price Anderson Act, as amended, limits the public liability of a
licensee for a single nuclear incident at its nuclear power plant to the
amount of financial protection available through liability insurance and
deferred premium assessment charges, currently approximately $8.9 billion,
which includes a 5% surcharge. The Act requires licensees to participate in
an assessable excess liability program through an indemnity program with the
NRC. Under the terms of this indemnity program, the Company could be liable
for retrospective assessments of approximately $79 million per nuclear
incident at any nuclear power plant. This amount is indexed every five years
for inflation. Also, it is provided that not more than $10 million could be
payable per incident in any one year. The Company's primary financial
protection for this exposure was provided in the amount available ($200
million) by private insurance. In consideration of the shutdown and defueled
status of Fort St. Vrain, the Company requested exemption from the
indemnification obligations under the Act. The NRC granted the Company's
request for exemption from participation in the indemnity program for nuclear
incidents occurring after February 17, 1994 and reduced the amount of primary
liability insurance required to $100 million.

11
<PAGE>

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)

In addition to the Company's liability insurance, Federal regulations
require the Company to maintain $1.06 billion in nuclear property insurance.
Effective February 1, 1991, the NRC granted the Company's exemption request to
reduce the nuclear property insurance coverage from $1.06 billion to a minimum
of $169 million. This lower limit would cover stabilization and
decontamination expenses resulting from a worst case accident. However, on
June 7, 1995, the NRC granted the Company an exemption from the requirement to
maintain nuclear property damage insurance following an environmental
assessment and finding of no significant impact. Accordingly, the Company has
reduced such insurance coverage to $10 million, which is related only to the
ISFSI.

3. Commitments and Contingencies

Regulatory Matters

Electric and Gas Cost Adjustment Mechanisms

The Company's Electric Cost Adjustment ("ECA") mechanism was revised and
a new Qualifying Facility Capacity Cost Adjustment ("QFCCA") mechanism was
implemented on December 1, 1993, along with the base rate changes resulting
from the 1993 rate case. Under the revised ECA, fuel used for generation and
purchased energy costs from utilities, Qualifying Facilities ("QF") and
Independent Power Production Facilities (excluding all purchased capacity
costs) to serve retail customers, are recoverable. Purchased capacity costs
are recovered as a component of base rates, except as described below. The
ECA rate is revised annually on October 1. Recovered energy costs are
compared with actual costs on a monthly basis and differences, including
interest, are deferred. Under the QFCCA, all purchased capacity costs from
new QF projects, not reflected in base rates, are recoverable similar to the
ECA. While the CPUC approved the QFCCA, recovery of such costs may be subject
to an earnings test, which has not yet been defined by the CPUC. The OCC has
proposed an annual earnings test that may result in a reduction of QFCCA
recoveries to the extent the Company's earnings are in excess of its 11%
authorized rate of return on regulated common equity. Hearings regarding this
matter were held on April 10-11, 1995. A decision on this matter is expected
by September 1995.

During 1994, the CPUC initiated proceedings for reviewing the justness
and reasonableness of Gas Cost Adjustment ("GCA") and ECA mechanisms used by
gas and electric utilities within its jurisdiction. On March 17, 1995, the
CPUC issued an order requiring the Company to make an individual filing with
the CPUC related to its ECA by September 1, 1995, at which time the CPUC will
review whether the ECA should be maintained in its present form, altered or
eliminated. On April 14, 1995, the CPUC issued a final order which retained
the GCA with no modifications and closed its investigation with respect to the
GCA mechanism.

On June 8, 1994, the CPUC approved the recovery of certain "energy
efficiency credits" from retail jurisdiction customers through the Demand Side
Management Cost Adjustment ("DSMCA"). On December 1, 1994, the OCC filed an
appeal in the District Court in and for the City and County of Denver ("Denver
District Court") of the CPUC's decision. The Denver District Court approved
the collection of these credits on June 19, 1995, subject to refund.
Accordingly, effective July 1, 1995, the Company began collection of the
December 31, 1994 balance of unbilled revenue related to these credits

12
<PAGE>

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)

(approximately $6.7 million). At June 30, 1995, approximately $8.5 million of
unbilled revenue related to these credits has been recognized by the Company.
If the OCC is successful in its appeal, the Company could be required to
reverse these unbilled revenues and refund the amounts previously collected.

1995 Rate Filing

The Company is developing a comprehensive proposal which it anticipates
filing with the CPUC in the third quarter of 1995. The proposal may include,
among other things, maintaining current rates for an interim period,
retention, modification or elimination of the ECA, GCA, and/or QFCCA and the
implementation of performance based incentive measures.

Incentive Regulation and Demand Side Management

The CPUC has opened a separate docket to investigate issues relating to
the adoption and implementation of incentive regulation, which includes the
concept of decoupling the Company's earnings from sales, and additional demand
side management ("DSM") incentives. On February 10, 1994, the parties to this
docket filed a unanimous stipulation and settlement agreement with the CPUC.
Provisions of the stipulation include, among other things, retaining the cost
recovery component of the DSMCA through December 31, 1998, modifying slightly
the DSM incentive mechanism for 1994 and 1995 and forming a technical working
group to study and analyze various alternative annual revenue reconciliation
mechanisms and incentive mechanisms for 1996 through 1998, which would replace
existing DSM incentives until another mechanism or regulatory approach is
approved by the CPUC. The stipulation agreement, which included a procedural
schedule to review the results of all studies and simulations over the next
year, was approved by the CPUC on June 16, 1994. During the first quarter of
1995, the technical working group presented to the CPUC a detailed analysis
demonstrating the effect of the various proposed mechanisms. The Company is
in opposition to all proposed alternative annual revenue reconciliation
mechanisms and incentive mechanisms, but not the DSMCA. Direct testimony and
exhibits were filed by the Company on June 15, 1995. Hearings have been
scheduled for September 1995.

Phase II of 1993 Rate Case

On August 1, 1994, the Company filed its Phase II testimony. The Phase
II proceedings will address cost allocation issues and specific rate changes
for the various customer classes based on the results of the Phase I hearings
and decision that became effective December 1, 1993. A settlement agreement
was reached related to gas rates in June 1995. Approval of the gas settlement
agreement by the CPUC is expected in the third quarter of 1995 and a final
decision on the Phase II proceedings related to electric rates is expected
before year-end.

Federal Energy Regulatory Commission

On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking
("NOPR") on Open Access Non-Discriminatory Transmission Services by Public
Utilities and Transmitting Utilities and a supplemental NOPR on Recovery of
Stranded Costs.

The rules proposed in the NOPR are intended to facilitate competition
among electric generators for sales to the bulk power supply market. If

13
<PAGE>

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)

adopted, the NOPR on open access transmission would require public utilities
under the Federal Power Act to provide open access to their transmission
systems and would establish guidelines for their doing so. A final rule would
define the terms under which independent power producers, neighboring
utilities, and others could gain access to a utility's transmission grid to
deliver power to wholesale customers, such as municipal distribution systems,
rural electric cooperatives, or other utilities. Under the NOPR, each public
utility would also be required to establish separate rates for its
transmission and generation services for new wholesale service, and to take
transmission services, including ancillary services, under the same tariffs
that would be applicable to third-party users for all of its new wholesale
sales and purchases of energy.

The supplemental NOPR on stranded costs provides a basis for recovery by
regulated public utilities of legitimate and verifiable stranded costs
associated with existing wholesale requirements customers and retail customers
who become unbundled wholesale transmission customers of the utility. The
FERC would provide public utilities a mechanism for recovery of stranded costs
that result from municipalization, former retail customers becoming wholesale
customers, or the loss of a wholesale customer. The FERC will consider
allowing recovery of stranded investment costs associated with retail wheeling
only if a state regulatory commission lacks the authority to consider that
issue.

On June 26, 1995, the Company filed transmission tariffs with the FERC
that are intended to meet the comparability of service requirements as set out
in the NOPR. Concurrently with the comparability filing, e prime, a non-
regulated energy services subsidiary of the Company, filed a power marketer
application with the FERC. The Company has requested that the transmission
tariffs be made effective on August 25, 1995, sixty days from the date of the
filing, and that e prime be authorized to make wholesale sales of electric
power beginning on that same day.

The Company is continuing to evaluate the NOPR to determine its impact
on the Company and its customers. It is anticipated that a final rule could
take effect in early 1996. The Company cannot predict the outcome of this
matter.

Environmental Issues

Environmental Site Cleanup

Under the Comprehensive Environmental Response, Compensation and
Liability Act, the Environmental Protection Agency has identified, and a Phase
II environmental assessment has revealed, low level, widespread contamination
from hazardous substances at the Barter Metals Company properties located in
central Denver. For an estimated 30 years, the Company sold scrap metal and
electrical equipment to Barter for reprocessing. The Company, which is one of
several Potentially Responsible Parties ("PRPs"), is involved in the cleanup
of this site which began in November 1992 and is expected to be completed
during the third quarter of 1995. The total project cost is currently
estimated to be approximately $8.9 million. On March 16, 1995, the Denver
District Court entered judgment in favor of the Company in the amount of $5.6
million, for costs incurred through January 31, 1995, regarding a lawsuit
against one of the Company's insurance providers for the cleanup of this site.
Additionally, the Company expects to recover costs incurred subsequent to

14
<PAGE>

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)

January 31, 1995 through future insurance claims. The insurance provider has
appealed the jury decision. Previously, the Company had received certain
insurance settlement proceeds, a portion of which remains to be allocated to
this site. To the extent such costs are not recovered by insurance or from
other PRPs, the Company believes it is probable that such costs will be
recovered through the rate regulatory process.

Polychlorinated biphenyl ("PCB") presence has been identified in the
basement of an historic office building located in downtown Denver. The
Company was negotiating the future cleanup with the current owners; however,
on October 5, 1993, the owners filed a civil action against the Company in the
Denver District Court. The action alleged that the Company was responsible
for the PCB releases and additionally claimed other damages in unspecified
amounts. On August 8, 1994, the Denver District Court entered a judgment
approving a $5.3 million settlement agreement between the Company and the
building owners resolving all claims between the Company and the building
owners. The Company believes it is probable that it will recover some portion
of these costs through insurance claims. To the extent such costs are not
recovered by insurance, the Company believes it is probable that such costs
will be recovered through the rate regulatory process.

The Elitch Gardens Amusement Park site near downtown Denver has revealed
low level, widespread contamination. The Company had used the site in the
past as a manufactured gas plant site and is one of three PRPs. An agreement
has been signed by Trillium Corporation, a PRP, Elitch Gardens Co. and the
Company, releasing the Company from responsibility for the first $2 million
of expenses related to contamination. Any contamination expenses incurred
during construction or thereafter which exceed $2 million will be the
responsibility of the Company; however, the Company could then pursue recovery
of the incurred costs from Burlington Northern Railroad, the third PRP, and/or
through insurance claims. Contamination expenses incurred through June 30,
1995 have not exceeded $2 million. The amusement park began operations in the
second quarter of 1995.

In addition to these sites, the Company has identified several sites
where cleanup of hazardous substances may be required. While potential
liability and settlement costs are still under investigation and negotiation,
the Company believes that the resolution of these matters will not have a
material effect on its financial position, results of operations or cash
flows. The Company fully intends to pursue the recovery of all significant
costs incurred for such projects through insurance claims and/or the rate
regulatory process. To the extent any costs are not recovered through the
options listed above, the Company would be required to recognize an expense
for such unrecoverable amounts.

Other Environmental Matters

Under the Clean Air Act Amendments of 1990, coal burning power plants
are required to reduce Sulfur Dioxide ("SO2") and Nitrogen Oxide ("NOx")
emissions to specified levels through a phased approach. The Company is
currently meeting Phase I emission standards placed on SO2 through the use of
low sulfur coal and the operation of pollution control equipment on certain
generation facilities. The Company will be required to modify certain boilers
by the year 2000 to reduce Nox emissions in order to comply with Phase II
requirements. The estimated costs for future plant modifications total
approximately $33 million. The Company is studying its options to reduce SO2

15
<PAGE>

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)

emissions and currently does not anticipate that these regulations will
significantly impact its operations.

On August 18, 1993, a conservation organization filed a complaint in the
U.S. District Court for the District of Colorado ("U.S. District Court"),
pursuant to Section 304 of the Federal Clean Air Act, against the Company and
the other joint owners of the Hayden Steam Electric Generating Station. The
plaintiff alleges that 1) the station exceeded the 20% opacity limitations in
excess of 19,000 six minute intervals during the period extending from the
last quarter of 1988 through mid-1993 based on the data and reports obtained
from the station's continuous opacity monitors ("COMs"), which measure average
emission stream opacity in six minute intervals on a continuous basis, 2) the
station was operated for over two weeks in late 1992 without a functioning
electrostatic precipitator which constituted a "modification" of the station
without the requisite permit from the Colorado Department of Public Health and
Environment and 3) the owners failed to operate the station in a manner
consistent with good air pollution control practices. The complaint seeks,
among other things, civil monetary penalties and injunctive relief. The joint
owners of the station contest all of these claims and contend that there were
no violations of the opacity limitation, because pursuant to the Colorado
state implementation plan ("SIP"), visual emissions are to be measured by
qualified personnel using the U.S. Environmental Protection Agency's ("EPA")
visual test known as "Method 9" and not by any measurements from the station's
COMs as alleged by the plaintiff.

Discovery was completed and oral arguments on summary judgment motions
were heard in mid-May 1995. On July 21, 1995, the U.S. District Court ordered
partial summary judgment of liability in favor of the plaintiff in regards to
the claims described in items 1) and 3) above and denied the plaintiff's
motion in regards to the claims described in item 2) above. On July 31, 1995,
the joint owners filed a petition for an interlocutory appeal with the 10th
Circuit Court of Appeals. If the joint owners are not successful in their
appeal, the U.S. District Court will determine the appropriate penalties
and/or remedies.

At this time, the Company is not able to estimate the outcome of the
appeal or the amount, if any, of its potential liability. The plaintiff has
requested, among other things, that the joint owners "pay to the EPA to
finance air compliance and enforcement activities, as provided for by 42
U.S.C. section 7604(g)(1), a penalty of $25,000 per day for each of their
violations of the Clean Air Act." The statute provides for penalties of up to
$25,000 per day per violation, but the level of penalties imposed in any
particular instance is discretionary. In setting penalties in its own
enforcement actions, the EPA relies, in part, on such factors as the economic
benefit of noncompliance, the actual or possible harm of noncompliance, the
size of the violator, the willfulness or negligence of the violator and its
degree of cooperation in resolving the matter. The Company cannot predict the
level of penalties, if any, or the remedies that the court may impose in the
instance if the joint owners are unsuccessful in their appeal.

In April 1992, the Company acquired interests in the two generating
units at the Hayden station located near Hayden, Colorado. The Company
currently is the operator of the Hayden station and owns an undivided interest
in each of the two generating units at the station which in total average
approximately 53%. Additional pollution control equipment may also be
required to be installed at the station. The Company has not recorded any

16
<PAGE>

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Continued)

amounts for potential loss contingencies related to this matter.

The Company believes that, consistent with historical regulatory
treatment, any costs to comply with pollution control regulations would be
recovered from its customers. However, no assurance can be given that this
practice will continue in the future.

Employee Litigation

Several employee lawsuits have been filed against the Company involving
alleged sexual/age discrimination. The Company is actively contesting all
outstanding lawsuits and believes the ultimate outcome will not have a
material impact on the Company's results of operations, financial position or
cash flow.

Certain employees terminated as part of the Company's 1991/1992
organizational analysis asserted breach of contract and promissory estoppel
with respect to job security and breach of the covenant of good faith and fair
dealing. Of the 21 actions filed, the trial court directed verdicts for the
Company in 19 cases. Two cases went to a jury which entered verdicts adverse
to the Company. All 21 decisions are currently on appeal, but the Company
believes its liability, if any, will not have a material impact on the
Company's results of operations, financial position or cash flow.

4. Management's Representations

In the opinion of the Company, the accompanying unaudited consolidated
condensed financial statements include all adjustments necessary for the fair
presentation of the financial position of the Company and its subsidiaries at
June 30, 1995 and December 31, 1994, and the results of operations for the
three and six months ended June 30, 1995 and 1994 and cash flows for the six
months ended June 30, 1995 and 1994. The consolidated condensed financial
information and notes thereto should be read in conjunction with the
consolidated financial statements and notes for the years ended December 31,
1994, 1993 and 1992 included in the Company's 1994 Annual Report filed with
the Securities and Exchange Commission on Form 10-K.

Because of seasonal and other factors, the results of operations for the
three and six month periods ended June 30, 1995 should not be taken as an
indication of earnings for all or any part of the balance of the year.

17
<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 June 30, 1995, and the related consolidated condensed statements of
income for the three and six month periods ended June 30, 1995 and 1994 and
the consolidated condensed statements of cash flows for the six month periods
ended June 30, 1995 and 1994. These financial statements are the
responsibility of the Company's management.

We conducted our review in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures
to financial data and making inquiries of persons responsible for financial
and accounting matters. It is substantially less in scope than an audit
conducted in accordance with generally accepted auditing standards, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that
should be made to the financial statements referred to above for them to be in
conformity with generally accepted accounting principles.

We have previously audited, in accordance with generally accepted auditing
standards, the consolidated balance sheet of Public Service Company of
Colorado and subsidiaries as of December 31, 1994 (not presented herein), and,
in our report dated February 10, 1995, we expressed an unqualified opinion on
that statement. In our opinion, the information set forth in the accompanying
consolidated condensed balance sheet as of December 31, 1994, is fairly
stated, in all material respects, in relation to the consolidated balance
sheet from which it has been derived. Our February 10, 1995 report contains
an explanatory paragraph that describes the uncertainties related to the
adequacy of the Company's recorded liability for defueling and decommissioning
the Fort St. Vrain Nuclear Generating Station.

As more fully discussed in Note 2 to the consolidated condensed financial
statements, the adequacy of the Company's recorded liability for defueling and
decommissioning its Fort St. Vrain Nuclear Generating Station (approximately
$64.7 million at June 30, 1995) is primarily dependent on assurances that the
dismantlement and decommissioning of the Fort St. Vrain Nuclear Generating
Station can be accomplished at currently estimated costs and that the spent
fuel storage and shipment issues are successfully resolved. The outcome of
the above issues cannot be determined at this time. The accompanying
consolidated condensed financial statements do not include any adjustments
that might result from the outcome of these uncertainties.

As more fully discussed in Note 3 to the consolidated condensed financial
statements, the Company is a defendant in certain litigation pursuant to
Section 304 of the Federal Clean Air Act, involving the Company and the other
joint owners of the Hayden Steam Electric Generating Station. The U.S.
District Court for the District of Colorado has issued an order providing the
plaintiffs with summary judgment on certain claims. The Company has filed a
petition for appeal of the decision, the outcome of which is uncertain at this
time. Accordingly, no provision for any liabilities that may result from the
resolution of this matter have been made in the accompanying consolidated
condensed financial statements.

18
<PAGE>

ARTHUR ANDERSEN LLP
Denver, Colorado,
August 4, 1995

19
<PAGE>

Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations

Three Months Ended June 30, 1995 Compared to the Three Months Ended June 30,
1994

Earnings

Earnings per share were $0.40 for the second quarter of 1995, compared
to $0.34 for the second quarter of 1994. The higher earnings were primarily
attributed to lower operating and maintenance expenses resulting from cost
containment efforts that were implemented in 1994.

The Company eliminated approximately 550 management and staff level
positions in connection with an internal restructuring and involuntary
severance program which was implemented in late 1994. The cost savings from
this program, estimated to be approximately $21 million on an annual basis,
reduced employee labor and benefit costs for the second quarter of 1995 as
discussed below. Through an early retirement/severance program, effective
April 1, 1994, the Company reduced its workforce by approximately 550
employees. The salary savings from this program, estimated to be
approximately $22 million on an annual basis, lowered employee labor and
benefit costs for the first quarter of 1995.

Electric Operations

The following table details the changes in electric revenues and energy
costs for the second quarter of 1995 compared to the same period in 1994.
<TABLE>
<CAPTION>
Increase (Decrease)
(Thousands of Dollars)
<S> <C>
Electric revenues:
Retail . . . . . . . . . . . . . . . . . . . . . . . $ 14,870
Wholesale . . . . . . . . . . . . . . . . . . . . . (47)
Other (including unbilled revenues) . . . . . . . . (13,287)
Total revenues . . . . . . . . . . . . . . . . . . 1,536
Fuel used in generation . . . . . . . . . . . . . . . (4,208)
Purchased power . . . . . . . . . . . . . . . . . . . 14,587
Net decrease in electric margin . . . . . . . . . . $ (8,843)
</TABLE>

The following schedule compares electric Kwh sales for the second
quarter of 1995 and 1994.
<TABLE>
<CAPTION>
Electric Sales
(Millions of Kwh)
1995 1994 % Change *
<S> <C> <C> <C>
Residential . . . . . . . . . . . . . . . 1,455.1 1,387.8 4.8%
Commercial and Industrial . . . . . . . . 3,584.9 3,524.1 1.7%
Public Authorities . . . . . . . . . . . 40.2 40.3 (0.3%)
Other Utilities . . . . . . . . . . . . . 682.8 674.1 1.3%
5,763.0 5,626.3 2.4%

* Percentages are calculated using unrounded amounts
</TABLE>

20
<PAGE>

Retail electric revenues increased approximately $14.9 million during
the three months ended June 30, 1995, when compared to the three months ended
June 30, 1994, primarily due to increases in billed sales resulting from
moderate customer growth and the recovery of net higher costs for purchased
power and fuel used in generation. Other electric revenues decreased
approximately $13.3 million primarily due to: 1) the recognition of lower
unbilled revenues in the current period resulting from the effects of
unseasonably cool weather during June 1995, as compared to the record hot
weather in June 1994, and 2) the recognition of approximately $5 million in
unbilled revenues related to certain energy efficiency credits, following the
CPUC's second quarter 1994 decision allowing for the future recovery of such
credits. (see Note 3. Commitments and Contingencies - Regulatory Matters in
Item 1. FINANCIAL STATEMENTS).

The Company and Cheyenne currently have cost adjustment mechanisms which
recognize the majority of the effects of changes in fuel used in generation
and purchased power costs and allow recovery of such costs on a timely basis.
A substantial portion of these net higher costs have been billed to customers,
however, the changes in revenues associated with these mechanisms during the
second quarters of 1995 and 1994 had little impact on net income. The Company
is required to make a filing with the CPUC related to its ECA by September 1,
1995, at which time the CPUC will review whether the ECA should be maintained
in its present form, altered or eliminated (See Note 3. Commitments and
Contingencies - Regulatory Matters in Item 1. FINANCIAL STATEMENTS).

Fuel used in generation expense decreased $4.2 million, or 8.7%, during
the second quarter of 1995, compared to the same period in 1994, primarily due
to lower generation levels, coupled with a slight reduction in the cost per
Kwh which is primarily due to lower transportation costs from the
renegotiation of certain coal transportation contracts. Purchased power
expense increased $14.6 million, or 14.1%, for the three months ended June 30,
1995, when compared to the same period in 1994, primarily due to increased
purchases from qualifying facilities. The cost per Kwh of electric energy
purchased from qualifying facilities is over 50% higher than the purchased
power costs from other suppliers, further contributing to the increase in
purchased power expense. A majority of purchased power costs associated with
qualifying facilities is collected through the QFCCA, a cost adjustment
mechanism; however, the future recovery of costs under the QFCCA may be
subject to an earnings test, which has not yet been defined by the CPUC (See
Note 3. Commitments and Contingencies - Regulatory Matters in Item 1.
FINANCIAL STATEMENTS).

Gas Operations

The following table details the changes in gas revenues and gas
purchased for resale during the second quarter of 1995 compared to the same
period in 1994.
<TABLE>
<CAPTION>
Increase (Decrease)
(Thousands of Dollars)
<S> <C>
Total gas operating revenues . . . . . . . . . . . . $ 17,995
Less: transport, gathering, and processing revenues . (1,871)
Revenues from gas sales . . . . . . . . . . . . . . 19,866
Gas purchased for resale . . . . . . . . . . . . . . 18,265
Net increase in gas sales margin . . . . . . . . . . $ 1,601
</TABLE>

21
<PAGE>

The following schedule compares gas deliveries for the second quarter of
1995 and 1994.
<TABLE>
<CAPTION>
Gas Deliveries
(Millions of Mcf)
1995 1994 % Change *
<S> <C> <C> <C>
Residential . . . . . . . . . . . . . . . 23.9 19.1 25.1%
Commercial and Industrial . . . . . . . . 14.4 12.2 18.4%
Other Utilities . . . . . . . . . . . . . 0.2 0.2 16.9%
Total Gas Sales . . . . . . . . . . . . 38.5 31.5 22.5%
Gathered and Processed . . . . . . . . . 0.3 10.8 (96.9%)
Transported and Other . . . . . . . . . . 24.5 18.1 35.4%
63.3 60.4 5.0%

* Percentages are calculated using unrounded amounts
</TABLE>

The $1.6 million increase in gas sales margin during the second quarter
of 1995, as compared to the same period of the prior year, is primarily due to
the unseasonably cool weather during the second quarter of 1995 and moderate
customer growth. A portion of the increase in billed sales resulting from the
colder weather was offset by lower unbilled revenue ($4.7 million) during the
second quarter of 1995.

A decline in transport, gathering and processing revenues reduced gas
sales margin by $1.9 million during the second quarter of 1995, as compared to
the same period of the prior year. The sale of WestGas Gathering, Inc. in
August 1994 resulted in a $2.9 million reduction in gathering revenues during
the current period. These lower revenues, however, have been offset, in part,
by revenue from higher transport deliveries. The growth in transportation
services is primarily due to serving new qualifying facility customers and
certain other pipeline customers on a short-term interruptible basis.

The Company and Cheyenne have in place GCA mechanisms for natural gas
sales, which recognize the majority of the effects of changes in the cost of
gas purchased for resale and adjust revenues to reflect such changes in cost
on a timely basis. As a result, the changes in revenues associated with these
mechanisms in the second quarters of 1995 and 1994 had little impact on net
income. The increase in gas purchased for resale for the second quarter of
1995, compared to the second quarter of 1994, is due to the higher gas sales,
but reflects a 12.5% decrease in the per unit cost of gas.

Non-Fuel Operating Expenses

Other operating and maintenance expenses decreased $10.8 million during
the second quarter of 1995, when compared to the same period in 1994,
primarily due to lower labor and employee benefit costs resulting from the
employee downsizing accomplished in late 1994 (approximately a $5 million
reduction) and the recognition of approximately $5.4 million of involuntary
severance costs in the second quarter of 1994. Lower maintenance expenses at
the Company's steam generation facilities also contributed to this decrease.

Depreciation and amortization expense decreased $1.4 million during the
second quarter of 1995, when compared to the same period in 1994, primarily
due to the effects of using a longer estimated depreciable life of the
Company's electric steam production facilities, consistent with the Company's
most recent depreciation study.

22
<PAGE>

In December 1991, the Company recorded a $3.0 million incentive award
granted by the CPUC for the Company's efforts to secure gas refunds for
customers from one of its natural gas suppliers. However, on July 11, 1994,
the Colorado Supreme Court reversed the incentive granted by the CPUC.
Accordingly, the change in other income and deductions - net for the second
quarter of 1995, compared to the second quarter of 1994, is primarily due to
the 1994 reversal of this incentive award.

Interest charges increased $3.1 million during the second quarter of
1995, when compared to the same period in 1994, primarily due to higher
interest rates associated with short-term borrowings and the recognition of
interest costs related to the over collection of expenses under the Company's
cost adjustment mechanisms.

23
<PAGE>

Six Months Ended June 30, 1995 Compared to the Six Months Ended June 30, 1994

Earnings

Earnings per share were $1.21 for the first six months of 1995, compared
to $1.05 for the first six months of 1994. The higher earnings were primarily
attributed to lower operating and maintenance expenses. The lower operating
expenses are the result of cost containment efforts that were implemented in
1994, as discussed earlier in the second quarter earnings summary. The
reduced employee labor and benefit costs for the first six months of 1995 are
discussed below.

Electric Operations

The following table details the changes in electric revenues and energy
costs for the first six months of 1995 compared to the same period in 1994.
<TABLE>
<CAPTION>
Increase (Decrease)
(Thousands of Dollars)
<S> <C>
Electric revenues:
Retail . . . . . . . . . . . . . . . . . . . . . . . $ 33,416
Wholesale . . . . . . . . . . . . . . . . . . . . . (3,671)
Other (including unbilled revenues) . . . . . . . . (9,910)
Total revenues . . . . . . . . . . . . . . . . . . 19,835
Fuel used in generation . . . . . . . . . . . . . . . (10,391)
Purchased power . . . . . . . . . . . . . . . . . . . 29,597
Net increase in electric margin . . . . . . . . . . $ 629
</TABLE>

The following schedule compares electric Kwh sales for the first six
months of 1995 and 1994.
<TABLE>
<CAPTION>
Electric Sales
(Millions of Kwh)
1995 1994 % Change *
<S> <C> <C> <C>
Residential . . . . . . . . . . . . . . . 3,182.6 3,101.2 2.6%
Commercial and Industrial . . . . . . . . 7,275.1 7,086.5 2.7%
Public Authorities . . . . . . . . . . . 88.6 86.8 2.0%
Other Utilities . . . . . . . . . . . . . 1,477.0 1,557.3 (5.2%)
12,023.3 11,831.8 1.6%

* Percentages are calculated using unrounded amounts
</TABLE>

Retail electric revenues increased $33.4 million for the six months
ended June 30, 1995, when compared to the six months ended June 30, 1994,
primarily due to increases in billed sales resulting from moderate customer
growth and the recovery of net higher costs for purchased power and fuel.
Wholesale electric revenues decreased $3.7 million for the six months ended
June 30, 1995, when compared to the same period in the prior year, primarily
due to a 5.2% decrease in wholesale Kwh sales. The demand for wholesale
energy has been negatively impacted by an available supply of low-cost non-
firm energy in the region.

Other electric revenues decreased approximately $9.9 million primarily
due to: 1) the recognition of lower unbilled revenues in the current period

24
<PAGE>

resulting from the effects of unseasonably cool weather during June 1995, as
compared to the record hot weather in June 1994, and 2) the recognition of
approximately $5 million in unbilled revenues related to certain energy
efficiency credits, following the CPUC's second quarter 1994 decision allowing
for the future recovery of such credits. (see Note 3. Commitments and
Contingencies - Regulatory Matters in Item 1. FINANCIAL STATEMENTS).

Fuel used in generation expense decreased $10.4 million, or 10.2%,
during the first six months in 1995, compared to the same period in 1994,
primarily due to a 2.4% decrease in generation, coupled with a slight
reduction in the cost per Kwh which is primarily due to lower transportation
costs from the renegotiation of certain coal transportation contracts.
Purchased power expense increased approximately $29.6 million, or 14.1%,
during the six months ended June 30, 1995, when compared to the same period in
1994, primarily due to increased purchases from qualifying facilities. The
cost per Kwh of electric energy purchased from qualifying facilities is over
50% higher than the purchased power costs from other suppliers, further
contributing to the increase in purchased power expense. A majority of
purchased power costs associated with qualifying facilities is collected
through the QFCCA, a cost adjustment mechanism; however, the future recovery
of costs under the QFCCA may be subject to an earnings test, which has not yet
been defined by the CPUC (See Note 3. Commitments and Contingencies -
Regulatory Matters in Item 1. FINANCIAL STATEMENTS).

Gas Operations

The following table details the changes in gas operating revenues and
gas purchased for resale for the first six months of 1995 compared to the same
period in 1994.
<TABLE>
<CAPTION>
Increase (Decrease)
(Thousands of Dollars)
<S> <C>
Total gas operating revenues . . . . . . . . . . . . $ 7,548
Less: transport, gathering, and processing revenues . (4,411)
Revenues from gas sales . . . . . . . . . . . . . . 11,959
Gas purchased for resale . . . . . . . . . . . . . . 8,886
Net increase in gas sales margin . . . . . . . . . . $ 3,073
</TABLE>

25
<PAGE>

The following schedule compares gas deliveries for the first six months
of 1995 and 1994.
<TABLE>
<CAPTION>
Gas Deliveries
(Millions of Mcf)
1995 1994 % Change *
<S> <C> <C> <C>
Residential . . . . . . . . . . . . . . . 64.7 61.6 5.1%
Commercial and Industrial . . . . . . . . 37.7 37.3 1.3%
Other Utilities . . . . . . . . . . . . . 0.4 0.4 (7.9%)
Total Gas Sales . . . . . . . . . . . . 102.8 99.3 3.6%
Gathered and Processed . . . . . . . . . 0.8 21.6 (96.5%)
Transported and Other . . . . . . . . . . 48.7 40.8 19.3%
152.3 161.7 (5.8%)
* Percentages are calculated using unrounded amounts
</TABLE>
Gas operating revenues and gas purchased for resale increased during the
first six months of 1995, as compared to the same period in the prior year,
primarily due to a 3.6% increase in total gas sales resulting from cooler
weather during March to June 1995. These increases were offset, in part, by
the 96.5% decrease in gathering and processed gas deliveries. The sale of
WestGas Gathering, Inc. during 1994 resulted in a $5.5 million reduction in
gathering revenues and a 20.7 MMcf reduction in gathering deliveries for the
current period. These lower revenues, however, have been offset, in part, by
revenues from higher transport deliveries primarily due to servicing new
qualifying facility customers.

The Company and Cheyenne have in place GCA mechanisms for natural gas
sales, which recognize the majority of the effects of changes in the cost of
gas purchased for resale and adjust revenues to reflect such changes in cost
on a timely basis. As a result, the changes in revenues associated with these
mechanisms in the first six months of 1995 and 1994 had little impact on net
income. The increase in gas purchased for resale for the first six months of
1995, compared to the first six months of 1994, is offset, in part, by a 6.5%
decrease in the per unit cost of gas.

Non-Fuel Operating Expenses

Other operating and maintenance expenses decreased $17.0 million during
the first six months of 1995, when compared to the same period in 1994,
primarily due to lower labor and employee benefit costs resulting from the
restructuring and employee downsizing accomplished in 1994 (approximately a
$16 million reduction) and the recognition of approximately $5.4 million of
involuntary severance costs in the second quarter of 1994. Lower maintenance
expenses at the Company's steam generation facilities also contributed to this
decrease. These decreases were offset, in part, by $2.3 million of additional
amortization of the early retirement/severance program costs for the six
months ended June 30, 1995 and the $2.5 million write-off of certain software
costs.

Depreciation and amortization expense decreased $3.1 million during the
first six months of 1995, when compared to the same period in 1994, primarily
due to the effects of using a longer estimated depreciable life of the
Company's electric steam production facilities, consistent with the Company's
most recent depreciation study.

The $4.1 million increase in income tax expense for the first six months
of 1995, compared to the same period in 1994, is primarily attributable to
higher pre-tax income, but includes additional tax benefits related to certain

26
<PAGE>

non-regulated investment activities.

Other income and deductions - net decreased $0.9 million during the
first six months of 1995, when compared to the same period in 1994, due to the
recognition of $2.1 million of the gain on the sale of WestGas Gathering, Inc.
as an amount to be refunded to ratepayers in accordance with a first quarter
of 1995 settlement agreement as well as from higher contributions, lower
interest income and reductions in non-utility income. These decreases were
offset, in part, by the reversal of a $3.0 million gas incentive award in the
second quarter of 1994, as previously discussed.

Interest charges increased $5.5 million during the first six months of
1995, when compared to the same period in 1994, primarily due to higher
interest rates associated with short-term borrowings.

Commitments and Contingencies

Issues relating to Fort St. Vrain, regulatory and environmental matters
are discussed in Notes 2 and 3 in Item 1. FINANCIAL STATEMENTS.

Liquidity and Capital Resources

Cash Flows

Cash provided by operating activities increased $98.5 million during the
first six months of 1995, when compared to the first six months of 1994,
primarily due to higher earnings, lower decommissioning expenditures ($9.3
million) and a significant increase in the recovery of purchased gas and
electric energy costs ($46.2 million). At June 30, 1995, the Company's
decommissioning liability, excluding defueling, was approximately $40.4
million. The expenditures related to this obligation are expected to be
incurred over the next year with final completion of such activities
anticipated in the second quarter of 1996. The annual decommissioning amount
being recovered from customers is approximately $13.9 million which will
continue through June, 2005. At June 30, 1995, approximately $102.4 million
remains to be collected from customers and is reflected as a regulatory asset
on the consolidated condensed balance sheet. Accordingly, operating cash
flows will continue to be negatively impacted until the decommissioning of
Fort St. Vrain is complete.

Cash used in investing activities increased $36.0 million during the
first six months of 1995, when compared to the same period in 1994, primarily
due to the June 1995 purchase of Young Gas Storage Company ($6.0 million) (see
Item 5. Other Information), the receipts from the sale of certain Fuelco
properties during early 1994 ($27.5 million) offset, in part, by a decrease in
construction expenditures in 1995 ($9.2 million).

Cash used in financing activities increased approximately $52.5 million
during the first six months of 1995, when compared to the same period in 1994,
primarily due to increased repayments of short-term borrowings during the
current year ($61.9 million) compared to additional short-term borrowings in
1994. Proceeds from the sale of common stock under the Company's dividend
reinvestment and stock purchase plan decreased in the first six months of 1995
to $13.8 million as compared to the proceeds of approximately $22.3 million
from issuances under such plan in the first six months of 1994. Long-term
debt refinancing activity in the first six months of 1995,as compared to 1994,
has decreased as a result of higher interest rates. Net decreases in the
maturities of long-term debt and issuances of long-term debt have reduced, in
part, the net amount of cash used in financing activities by $20.1 million.

27
<PAGE>

Common Stock Dividend

On June 27, 1995, the Company's Board of Directors declared a quarterly
dividend on its common stock of $0.51 per share, up from $0.50 per share for
the previous year. The Company's common stock dividend level is dependent
upon the Company's results of operations, financial position, cash flow and
other factors, and will continue to be evaluated quarterly by the Board of
Directors.

28
<PAGE>

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

Part 1. Issues relating to the recovery of energy efficiency
credits, environmental site cleanup and other environmental
matters are discussed in Note 3. Commitments and
Contingencies in Item 1, Part 1.

Item 4. Submission of Matters to a Vote of Security Holders

(a) The 1995 Annual Meeting of Shareholders of the Company took place on May
11, 1995.

(b) Two matters were voted upon at the meeting: 1) the election of
directors; and 2) the appointment of Arthur Andersen LLP as the
Company's independent public accountants.
<TABLE>
<CAPTION>
With respect to the election of directors, the votes were as follows:
<S> <C>
Wayne H. Brunetti 52,247,763 shares for 1,884,998 shares withheld
Collis P. Chandler, Jr. 52,517,907 shares for 1,614,854 shares withheld
Doris M. Drury, PhD 52,441,491 shares for 1,691,270 shares withheld
Thomas T. Farley 52,529,641 shares for 1,603,120 shares withheld
Gayle L. Greer 52,356,778 shares for 1,775,983 shares withheld
A. Barry Hirschfeld 52,434,448 shares for 1,698,313 shares withheld
D. D. Hock 52,143,290 shares for 1,989,471 shares withheld
George B. McKinley 52,466,502 shares for 1,666,259 shares withheld
Will F. Nicholson, Jr. 52,516,579 shares for 1,616,182 shares withheld
J. Michael Powers 52,552,211 shares for 1,580,550 shares withheld
Thomas E. Rodriguez 52,470,590 shares for 1,662,171 shares withheld
Rodney E. Slifer 52,563,926 shares for 1,568,835 shares withheld
W. Thomas Stephens 52,555,822 shares for 1,576,939 shares withheld
Robert G. Tointon 52,537,269 shares for 1,595,492 shares withheld

With respect to the appointment of Arthur Andersen LLP, the vote was: 52,443,250
shares for; 911,779 shares against; 777,732 shares abstain. There were zero broker
non-votes.
</TABLE>
Item 5. Other Information

On June 27, 1995, the Company purchased all of the outstanding common
stock of Young Gas Storage Company (YGSC) for $6 million. YGSC owns a
47.5% interest in a partnership which owns and operates gas storage
facilities located in northeastern Colorado.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

12(a) - Computation of Ratio of Consolidated Earnings to
Consolidated Fixed Charges is set forth at page 29 herein.

12(b) - Computation of Ratio of Consolidated Earnings to
Consolidated Combined Fixed Charges and Preferred Stock
Dividends is set forth at page 30 herein.

29
<PAGE>

15 - Letter from Arthur Andersen LLP regarding unaudited interim
information is set forth at page 31 herein.

27 - Financial Data Schedule UT

(b) Reports on Form 8-K

No reports on Form 8-K were filed during the second quarter of 1995.

30
<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: August 10, 1995

31
<PAGE>

EXHIBIT INDEX

12(a) - Computation of Ratio of Consolidated Earnings to
Consolidated Fixed Charges is set forth at page 29 herein.

12(b) - Computation of Ratio of Consolidated Earnings to
Consolidated Combined Fixed Charges and Preferred Stock
Dividends is set forth at page 30 herein.

15 - Letter from Arthur Andersen LLP regarding unaudited interim
information is set forth at page 31 herein.

27 - Financial Data Schedule UT

32
<PAGE>

EXHIBIT 12(a)

PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES

COMPUTATION OF RATIO OF CONSOLIDATED EARNINGS
TO CONSOLIDATED FIXED CHARGES

(not covered by report of independent public accountants)

<TABLE>
<CAPTION>
Six Months Ended
June 30,
1995 1994
(Thousands of Dollars,
except ratios)
<S> <C> <C>
Fixed charges:

Total . . . . . . . . . . . . . . . . . . . . . . $ 75,554 $ 70,387

Earnings (before fixed charges and taxes on income):

Net income . . . . . . . . . . . . . . . . . . . . . . $ 81,899 $ 70,404
Fixed charges as above . . . . . . . . . . . . . . . . 75,554 70,387
Provisions for Federal and state taxes on income,
net of investment tax credit amortization . . . . . . 41,988 37,928

Total . . . . . . . . . . . . . . . . . . . . . . . $ 199,441 $ 178,719

Ratio of earnings to fixed charges . . . . . . . . . . . 2.64 2.54
</TABLE>

33
<PAGE>

EXHIBIT 12(b)

PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES

COMPUTATION OF RATIO OF CONSOLIDATED EARNINGS
TO CONSOLIDATED COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

(not covered by report of independent public accountants)

<TABLE>
<CAPTION>
Six Months Ended
June 30,
1995 1994
(Thousands of Dollars,
except ratios)
<S> <C> <C>
Fixed charges and preferred stock dividends:

Interest on long-term debt . . . . . . . . . . . . . . $ 42,843 $ 45,183
Interest on borrowings against
corporate-owned life insurance contracts . . . . . . 16,601 14,206
Other interest . . . . . . . . . . . . . . . . . . . . 11,110 5,780
Amortization of debt discount and expense less premium 1,597 1,528
Interest component of rental expense . . . . . . . . . 3,403 3,690
Preferred stock dividend requirement . . . . . . . . . 6,001 6,010
Additional preferred stock dividend requirement . . . . 3,076 3,238
Total . . . . . . . . . . . . . . . . . . . . . . $ 84,631 $ 79,635

Earnings (before fixed charges and taxes on income):

Net income . . . . . . . . . . . . . . . . . . . . . . $ 81,899 $ 70,404
Interest on long-term debt . . . . . . . . . . . . . . 42,843 45,183
Interest on borrowings against
corporate-owned life insurance contracts . . . . . . 16,601 14,206
Other interest . . . . . . . . . . . . . . . . . . . . 11,110 5,780
Amortization of debt discount and expense less premium 1,597 1,528
Interest component of rental expense . . . . . . . . . 3,403 3,690
Provisions for Federal and state taxes on income,
net of investment tax credit amortization . . . . . . 41,988 37,928
Total . . . . . . . . . . . . . . . . . . . . . . . $ 199,441 $ 178,719

Ratio of earnings to fixed charges and preferred stock
dividends . . . . . . . . . . . . . . . . . . . . . . . 2.36 2.24
</TABLE>

34
<PAGE>

EXHIBIT 15
August 4, 1995

Public Service Company of Colorado:

We are aware that Public Service Company of Colorado has incorporated by
reference in its Registration Statement (Form S-3, File No. 33-42442)
pertaining to the Automatic Dividend Reinvestment and Common Stock
Purchase Plan; the Company's Registration Statement (Form S-3, File No.
33-37431), as amended on December 4, 1990, pertaining to the shelf
registration of the Company's First Mortgage Bonds; the Company's
Registration Statement (Form S-8, File No. 33-55432) pertaining to the
Omnibus Incentive Plan; the Company's Registration Statement (Form S-3,
File No. 33-51167) pertaining to the shelf registration of the Company's
First Collateral Trust Bonds and the Company's Registration Statement
(Form S-3, File No. 33-54877) pertaining to the shelf registration of the
Company's First Collateral Trust Bonds and Cumulative Preferred Stock, its
Form 10-Q for the quarter ended June 30, 1995, which includes our report
dated August 4, 1995, covering the unaudited consolidated condensed
financial statements contained therein. Pursuant to Regulation C of the
Securities Act of 1933, that report is not considered a part of the
registration statement prepared or certified by our firm or a report
prepared or certified by our firm within the meaning of Sections 7 and 11
of the Act.

Very truly yours,

ARTHUR ANDERSEN LLP

35
<PAGE>

<ARTICLE> UT
<LEGEND>
This Schedule contains summary Financial information extracted from Public
Service Company of Colorado and Subsidiaries consolidated condensed balance
sheet as of June 30, 1995 and consolidated condensed statements of income and
cash flows for the six months ended June 30, 1995 and is qualified in its
entirety by reference to such financial statements.
</LEGEND>

<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> JUN-30-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,358,412
<OTHER-PROPERTY-AND-INVEST> 25,055
<TOTAL-CURRENT-ASSETS> 423,651
<TOTAL-DEFERRED-CHARGES> 380,388
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,187,506
<COMMON> 314,617
<CAPITAL-SURPLUS-PAID-IN> 668,269
<RETAINED-EARNINGS> 320,048
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,302,934
42,665
140,008
<LONG-TERM-DEBT-NET> 1,081,746
<SHORT-TERM-NOTES> 40,200
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 246,100
<LONG-TERM-DEBT-CURRENT-PORT> 83,174
2,576
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,248,103
<TOT-CAPITALIZATION-AND-LIAB> 4,187,506
<GROSS-OPERATING-REVENUE> 1,119,295
<INCOME-TAX-EXPENSE> 41,988
<OTHER-OPERATING-EXPENSES> 176,548
<TOTAL-OPERATING-EXPENSES> 964,972
<OPERATING-INCOME-LOSS> 154,323
<OTHER-INCOME-NET> (1,924)
<INCOME-BEFORE-INTEREST-EXPEN> 152,399
<TOTAL-INTEREST-EXPENSE> 70,500
<NET-INCOME> 81,899
6,001
<EARNINGS-AVAILABLE-FOR-COMM> 75,898
<COMMON-STOCK-DIVIDENDS> 64,064
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 246,276
<EPS-PRIMARY> 1.21
<EPS-DILUTED> 1.21

</TABLE>