<PAGE>

                                 FORM 10-K

                     SECURITIES AND EXCHANGE COMMISSION
                           WASHINGTON, D.C. 20549

         [X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE 
                      SECURITIES EXCHANGE ACT OF 1934
                For the fiscal year ended December 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

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

                                                    NAME OF EACH EXCHANGE
    TITLE OF EACH CLASS                               ON WHICH REGISTERED

COMMON STOCK, PAR VALUE $5 PER SHARE              New York, Chicago and Pacific
RIGHTS TO PURCHASE COMMON STOCK                   New York, Chicago and Pacific
CUMULATIVE PREFERRED STOCK, PAR VALUE $100 PER SHARE 
     4 1/4 Series                                             American
     7.15% Series                                             New York

CUMULATIVE PREFERRED STOCK ($25), PAR VALUE PER SHARE
     8.40% Series                                             New York

         SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
            CUMULATIVE PREFERRED STOCK, PAR VALUE $100 PER SHARE
                            (TITLE OF CLASS)

    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        
                                                   -------    ------- 

    INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO 
ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, 
TO THE BEST OF REGISTRANT'S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION 
STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY 
AMENDMENT TO THIS FORM 10-K. [  ]

    THE AGGREGATE MARKET VALUE OF THE REGISTRANT'S COMMON STOCK, $5.00 PAR 
VALUE (THE ONLY CLASS OF VOTING STOCK), HELD BY NON-AFFILIATES WAS 
$2,536,745,052 BASED ON THE LAST SALE PRICE THEREOF REPORTED ON THE 
CONSOLIDATED TAPE FOR FEBRUARY 21, 1997.

    AT FEBRUARY 21, 1997, 65,253,892 SHARES OF THE REGISTRANT'S COMMON STOCK,
$5.00 PAR VALUE (THE ONLY CLASS OF COMMON STOCK), WERE OUTSTANDING.

                    DOCUMENTS INCORPORATED BY REFERENCE

PORTIONS OF THE REGISTRANT'S 1997 PROXY STATEMENT ARE INCORPORATED BY REFERENCE
IN PART II, ITEM 9 AND PART III, ITEMS 10, 11, 12 AND 13 OF THIS FORM 10-K.

<PAGE>
                             TABLE OF CONTENTS

                                   PART I

Item 1.  Business.........................................................   1 
     The Company..........................................................   1 
         Cheyenne & WGI...................................................   2 
         e prime and subsidiaries.........................................   2 
         Other Subsidiaries...............................................   2 
     Electric Operations..................................................   2 
         Peak Load........................................................   3 
         Purchased Power..................................................   3 
         Construction Program.............................................   5 
     Electric Fuel Supply.................................................   5 
         Coal.............................................................   6 
         Natural Gas and Fuel Oil.........................................   7 
     Natural Gas Operations...............................................   8 
         Natural Gas Supply and Storage...................................   8 
     Regulation and Rates.................................................   8 
         Merger Rate Filings..............................................   9 
         State Regulation.................................................   9 
             CPUC.........................................................   9 
             Gas Rate Case................................................   9 
             Electric and Gas Adjustment Clauses..........................   9 
             Incentive Regulation and Demand Side Management..............  10 
             IRP - Electric...............................................  10 
             WPSC.........................................................  10 
         Federal Energy Regulatory Commission.............................  10 
     Environmental Matters................................................  11 
     Competition..........................................................  12 
         Industry Outlook.................................................  12 
         State Regulatory Environment.....................................  12 
         Electric.........................................................  13 
         Natural Gas......................................................  13 
     Franchises...........................................................  13 
     Employees & Union Contracts..........................................  13 
     Research and Development.............................................  14 
     Consolidated Electric Operating Statistics...........................  15 
     Consolidated Gas Operating Statistics................................  16 
     Electric Transmission Map............................................  17 

Item 2.  Properties.......................................................  18 
     Electric Generation Property.........................................  18 
     Nuclear Generation Property..........................................  18 
     Electric Transmission and Distribution Property......................  18 
     Gas Property.........................................................  19 
     Other Property.......................................................  19
     Property of Subsidiaries.............................................  20
     Character of Ownership...............................................  20

Item 3.  Legal Proceedings................................................  20

Item 4.  Submission of Matters to a Vote of Security Holders..............  20

                                     i 
<PAGE>
                                  PART II

Item 5.  Market for Registrant's Common Equity and Related 
           Stockholder Matters............................................  21

Item 6.  Selected Financial Data..........................................  22

Item 7.  Management's Discussion and Analysis of Financial 
           Condition and Results of Operations............................  23 
     Industry Outlook.....................................................  23 
     Corporate Overview...................................................  23 
     Recent Developments..................................................  24
     Earnings.............................................................  25 
     Electric Operations..................................................  25 
     Gas Operations.......................................................  27 
     Non-Fuel Operating Expenses..........................................  28 
     Financial Position...................................................  29 
     Commitments and Contingencies........................................  29 
     Common Stock Dividend................................................  29 
     Liquidity and Capital Resources......................................  29 
          Cash Flows......................................................  29 
          Prospective Capital Requirements................................  30 
          Capital Sources.................................................  31 
          Registration Statements.........................................  31 
          Company's Indentures............................................  31 
          Company's Restated Articles of Incorporation....................  32 
          Short-Term Borrowing Arrangements...............................  32 

Item 8.  Financial Statements and Supplementary Data......................  33 
     Report of Audit Committee of the Board of Directors..................  33 
     Report of Management.................................................  34 
     Report of Independent Public Accountants.............................  35 
     Consolidated Balance Sheets..........................................  36 
     Consolidated Statements of Income....................................  38 
     Consolidated Statements of Shareholders' Equity......................  39 
     Consolidated Statements of Cash Flows................................  40 
     Notes to Consolidated Financial Statements...........................  41 

Schedule II...............................................................  69 

Exhibit 12(a).............................................................  70 

Exhibit 12(b).............................................................  71 

Exhibit 99................................................................  72 

Item 9.   Changes in and Disagreements with Accountants on 
            Accounting and Financial Disclosure...........................  78 

                                  PART III

Item 10.  Directors and Executive Officers of the Registrant..............  78 

Item 11.  Executive Compensation..........................................  81 

Item 12.  Security Ownership of Certain Beneficial Owners and Management..  81 


                                      ii

<PAGE>

Item 13.  Certain Relationships and Related Transactions..................  81

                                  PART IV

Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K.  81

Experts...................................................................  83 

Consent of Independent Public Accountants.................................  84 

Power of Attorney.........................................................  84 

Signatures................................................................  85 

Exhibit Index.............................................................  87 















     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 due to a variety of factors including, without limitation, 
restructuring of the utility industry; future economic conditions; earnings 
retention and dividend payout policies; developments in the legislative, 
regulatory and competitive environments 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.

                                     iii 
<PAGE>
                                   TERMS

The abbreviations or acronyms used in the text and notes are defined below:

ABBREVIATION OR ACRONYM                                                   TERM 
------------------------------------------------------------------------------ 
AEP....................................................American Electric Power
AFDC............................. Allowance for Funds Used During Construction 
APB Opinion No. 25................. Accounting Principles Board Opinion No. 25 
                                    "Accounting for Stock Issued to Employees" 
Amax.............. Amax Coal Company, a subsidiary of Cyprus/Amax Coal Company 
Arapahoe........................... Arapahoe Steam Electric Generating Station 
BLM................................................. Bureau of Land Management 
Cameo................................. Cameo Steam Electric Generating Station 
CCT3................................................ Clean Coal Technology III 
CERCLA... Comprehensive Environmental Response, Compensation and Liability Act 
Cherokee........................... Cherokee Steam Electric Generating Station 
Cheyenne............................... Cheyenne Light, Fuel and Power Company 
COLI........................................... Corporate-owned life insurance 
Colorado Supreme Court................. Supreme Court of the State of Colorado 
Comanche........................... Comanche Steam Electric Generating Station 
Company or PSCo............................ Public Service Company of Colorado 
                                                      (excluding subsidiaries) 
CPCN.......................... Certificate of Public Convenience and Necessity 
CPUC..................... Public Utilities Commission of the State of Colorado 
Craig................................. Craig Steam Electric Generating Station 
CWIP............................................ Construction Work in Progress 
CWQCD................................. Colorado Water Quality Control Division 
Denver District Court.................. District Court in and for the City and 
                                                              County of Denver 
DOE................................................. U.S. Department of Energy 
DSM.................................................... Demand Side Management 
DSMCA.................................. Demand Side Management Cost Adjustment 
Dth................................................................. Dekatherm 
e prime......................................................... e prime, inc. 
ECA.................................................... Energy Cost Adjustment 
EIS............................................ Environmental Impact Statement 
EPAct...................................... National Energy Policy Act of 1992 
EPA...................................... U.S. Environmental Protection Agency 
EWG................................................ Exempt Wholesale Generator 
FASB..................................... Financial Accounting Standards Board 
FERC..................................... Federal Energy Regulatory Commission 
FERC Order 636.................................FERC Order Nos. 636-A and 636-B 
Fort St. Vrain............. Fort St. Vrain Nuclear Electric Generating Station 
Fuelco....... Fuel Resources Development Co., a dissolved Colorado corporation 
GCA....................................................... Gas Cost Adjustment 
Hayden............................... Hayden Steam Electric Generating Station 
IBM....................................................... IBM Global Services 
ICA................................................. Incentive Cost Adjustment 
Interstate.................................... Colorado Interstate Gas Company 
IPPF.................................... Independent Power Production Facility 
IRP.................................................. Integrated Resource Plan 
IRS.................................................. Internal Revenue Service 
ISFSI............................. Independent Spent Fuel Storage Installation 
KN Energy..................................................... KN Energy, Inc. 
Merger.......... the proposed business combination between the Company and SPS 

                                     iv 
<PAGE>

Merger Agreement............ Agreement and Plan of Reorganization by and among 
                                         the Company, SPS, and NCE, as amended 
Natural Fuels....................................... Natural Fuels Corporation 
NCE................................................ New Century Energies, Inc. 
NOPR............................................ Notice of Proposed Rulemaking 
NOx............................................................ Nitrogen Oxide 
NRC............................................. Nuclear Regulatory Commission 
OCC....................................... Colorado Office of Consumer Counsel 
OPEB................................... Other Postretirement Employee Benefits 
PCB.................................................. Polychlorinated biphenyl 
Pawnee............................... Pawnee Steam Electric Generating Station 
Pawnee 2.......... Pawnee Steam Electric Generating Station, Unit 2 (proposed) 
Pool........................................................ Inland Power Pool 
PRPs.......................................... Potentially Responsible Parties 
PSCCC.......................................... PS Colorado Credit Corporation 
PSRI.................................................... PSR Investments, Inc. 
PUHCA.............................. Public Utility Holding Company Act of 1935 
QF........................................................ Qualifying Facility 
QFCCA.......................... Qualifying Facilities Capacity Cost Adjustment 
QSP................................................... Quality of Service Plan 
SEC........................................ Securities and Exchange Commission 
SFAS 71.................. Statement of Financial Accounting Standards No. 71 - 
                   "Accounting for the Effects of Certain Types of Regulation" 
SFAS 106................ Statement of Financial Accounting Standards No. 106 - 
       "Employers' Accounting for Postretirement Benefits Other Than Pensions" 
SFAS 107................ Statement of Financial Accounting Standards No. 107 - 
                       "Disclosures about Fair Value of Financial Instruments" 
SFAS 109................ Statement of Financial Accounting Standards No. 109 - 
                                                 "Accounting for Income Taxes" 
SFAS 112................ Statement of Financial Accounting Standards No. 112 - 
                           "Employers' Accounting for Postemployment Benefits" 
SFAS 121................ Statement of Financial Accounting Standards No. 121 - 
                           "Accounting for the Impairment of Long-Lived Assets 
                                      and Long-Lived Assets to be Disposed Of" 
SFAS 123................ Statement of Financial Accounting Standards No. 123 - 
                                     "Accounting for Stock-Based Compensation" 
SO2............................................................ Sulfur Dioxide 
SPS....................................... Southwestern Public Service Company 
TOG...................................................... Texas-Ohio Gas, Inc. 
TOP..................................................Texas-Ohio Pipeline, Inc. 
Tri-State............. Tri-State Generation and Transmission Association, Inc. 
UK..............................................................United Kingdom
Valmont............................. Valmont Steam Electric Generating Station 
WGG................................................... WestGas Gathering, Inc. 
WGI.................................................. WestGas InterState, Inc. 
WGT............................................... WestGas TransColorado, Inc. 
WPSC..................................... Public Service Commission of Wyoming 
WSCC..................................... Western Systems Coordinating Council 
Young Storage................................. Young Gas Storage Company, Ltd. 
YGSC................................................ Young Gas Storage Company 
Yorkshire Electricity..........................Yorkshire Electricity Group plc
Yorkshire Holdings......................................Yorkshire Holdings plc
Yorkshire Power.....................................Yorkshire Power Group Ltd.
Zuni................................... Zuni Steam Electric Generating Station


                                     v 
<PAGE>

                                   PART I


ITEM 1.  BUSINESS

THE COMPANY 

     The Company, incorporated through merger of predecessors under the laws of
the State of Colorado in 1924, 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 provides
electricity or gas or both in an area having an estimated population of 3.0
million people of which approximately 2.1 million are in the Denver metropolitan
area.  The Company's operations are wholly within the State of Colorado. 

     On August 22, 1995, the Company, SPS, a New Mexico corporation, and NCE, a
newly formed Delaware corporation, entered into a Merger Agreement providing for
a business combination as peer firms involving the Company and SPS in a "merger
of equals" transaction.  As part of the agreement, NCE would become the parent
company for the Company and SPS.  On January 30, 1996, NCE filed its application
with the SEC to be a registered public utility holding company.  The
shareholders of the Company and SPS approved the Merger Agreement on January 31,
1996.  The Merger is subject to customary closing conditions, including the
receipt of all necessary governmental approvals and the making of all necessary
governmental filings, as discussed in Note 3. Merger and Note 9. Commitment and
Contingencies - Regulatory Matters in Item 8.  FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA.  The future operations and financial position of the Company
will be significantly affected by the Merger.  See the information in Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS and the unaudited pro forma financial information for NCE included in
this report as Exhibit 99.

        On February 24, 1997, the Company and AEP jointly announced that they 
have reached agreement with the board of directors of Yorkshire Electricity, a 
UK regional electricity company, on the terms of a recommended cash tender 
offer for all of the outstanding and to be issued ordinary shares of Yorkshire 
Electricity (the "Proposed Acquisition").  The Company and AEP, through a 
joint venture named Yorkshire Holdings, are offering the equivalent of US 
$15.02 (9.27 pounds) per ordinary share, for a total purchase price of 
approximately US $2.4 billion (1.5 billion pounds).  The boards of directors 
of the Company and AEP have approved the transaction.  The board of directors 
of Yorkshire Electricity has agreed to recommend the offer to Yorkshire 
Electricity's shareholders.  Consummation of the Proposed Acquisition is 
subject to customary conditions in the UK, including regulatory clearance and 
acceptance of the offer by holders of at least 90% of the outstanding shares 
of Yorkshire Electricity.  Yorkshire Holdings may waive the latter condition 
when it has received acceptances of its offer and has otherwise acquired 
shares which in total represent more than 50% of the outstanding shares of 
Yorkshire Electricity.  The Company cannot predict at this time whether or 
not these conditions will be met or waived.

        See "Recent Developments" in Item 7. MANAGEMENT'S DISCUSSION AND 
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS and Note 4.
Acquisition and Divestiture of Investments - Proposed  Acquisition of Yorkshire 
Electricity in Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. 

     As of December 31, 1996, the Company owned all of the outstanding capital
stock of Cheyenne, WGI, e prime, 1480 Welton, Inc., PSRI, PSCCC, Green and Clear
Lakes Company and Fuelco (a dissolved corporation). In addition, the Company
owned 83.63% of the capital stock of Natural Fuels and e prime owned all of the
outstanding capital stock of TOG, TOP and YGSC. These subsidiaries are included
in the Company's consolidated financial statements.  The Company also holds a
controlling interest in several other relatively small ditch and water companies
whose capital requirements are not significant and which are not consolidated in
the Company's financial statements or statistical data.


                                      1

<PAGE>

     Information regarding industry segments is set forth in Note 14. Segments
of Business in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
     
CHEYENNE AND WGI 

      Cheyenne is an operating utility engaged in the purchase, distribution and
sale of electricity and natural gas primarily serving customers in Cheyenne,
Wyoming.  WGI is a natural gas transmission company engaged in transporting gas
to Cheyenne, Wyoming via a thirteen mile connecting pipeline between Chalk
Bluffs, Colorado and Cheyenne, Wyoming.  Gas transportation volumes were
approximately 3.4 million Dth for 1996.

E PRIME AND SUBSIDIARIES

     e prime, with headquarters in Denver and an office in Tulsa, was 
established in 1995 and provides energy related products and services which 
include, but are not limited to, electric and gas brokering and marketing, 
energy consulting and project development services and information processing 
and other technology based services.  e prime is also pursuing international 
energy investment opportunities.  On March 29, 1996, e prime received 
authorization from the FERC to act as a power marketer. Effective September 
1, 1996, the Company and e prime acquired TOG, a gas marketing company, with 
headquarters in Houston and an office in Boston.  TOG serves approximately 
1,400 industrial and commercial customers in the eastern U.S.  e prime and 
TOG have merged operations and together they provide value-added energy 
related products and services to end use customers and utilities nationwide.  
e prime also acquired TOP on September 1, 1996, a small pipeline company 
which connects two major interstate pipelines.  TOP is subject to FERC 
regulation.  The Company and its subsidiary, e prime are also developing the 
necessary policies and procedures to enable it to use energy derivative 
financial instruments in its electric and gas brokering and marketing 
activites.

     e prime owns a 50% general partnership interest in the Johnstown 
Cogeneration Company, LLC, which produces electric energy that is sold to 
PSCo under a 30 year contract.  In addition, e prime acquired a 50% limited 
partnership interest in ep3 to identify and develop various international 
energy business opportunities.

     YGSC, a subsidiary of e prime, owns a 47.5% general partnership interest in
Young Storage. Young Storage owns and operates an underground gas storage
facility in northeastern Colorado. Young Storage is subject to FERC regulation.

OTHER SUBSIDIARIES

     1480 Welton, Inc. is a real estate company which owns certain of the
Company's real estate interests; PSRI owns and manages permanent life insurance
policies on certain past and present employees, the benefits from which are to
provide future funding for general corporate purposes; PSCCC is a finance
company that finances certain of the Company's current assets; Green and Clear
Lakes Company owns water rights and storage facilities for water used at the
Company's Georgetown Hydroelectric Station; Natural Fuels sells compressed
natural gas as a transportation fuel to retail markets, converts vehicles for
natural gas usage, constructs fueling facilities and sells miscellaneous fueling
facility equipment.  On July 1, 1996, Fuelco, which was primarily involved in
the exploration and production of oil and natural gas, sold its remaining
properties, the San Juan Basin Coal Bed Methane properties, at approximately
book value.  Effective October 31, 1996, Fuelco was dissolved. (See Note 4.
Acquisition and Divestiture of Investments in Item 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA).  

ELECTRIC OPERATIONS

     The Company proposes to use the following resources to meet its net 
dependable system capacity: 1) the Company's electric generating stations 
(see Electric Generation Property in Item 2. PROPERTIES); 2) purchases from 
other utilities and from QFs and IPPFs; 3) demand-side management options and 
4) new generation alternatives, including the phased repowering of Fort St. 
Vrain.  Additional planned resources are summarized in the

                                      2

<PAGE>

Company's proposed IRP, which was filed
with the CPUC in October 1996 (see "Regulation and Rates - State Regulation - 
IRP - Electric").

PEAK LOAD

     During 1997, net firm system peak demand for the Company and Cheyenne is
estimated to be 4,413 Mw, assuming normal weather conditions.  Net dependable
system capacity is projected to be, after accounting for 68 Mw of demand-side
management options, 5,127 Mw (generating capacity of 3,304 Mw and firm purchases
of 1,823 Mw) at the time of the anticipated 1997 system peak (summer season),
resulting in a reserve margin of approximately 16%.

     The net firm system peak demand for the Company and Cheyenne for each of
the last five years was as follows:

                                       1992    1993    1994    1995    1996 
                                      -----   -----   -----   -----   ----- 
Net Firm System Peak Demand* (Mw)...  3,757   3,869   3,972   4,248   4,397 

------------------- 
*  Excludes station housepower, nonfirm electric furnace load and controlled
   interruptible loads (of which approximately 156 Mw, 164 Mw, 160 Mw, 148 Mw
   and 122 Mw in the years 1992-1996, respectively, was not interrupted at the
   time of the system peak).

                                     2 
<PAGE>

     The net firm system peak demand for the Company and Cheyenne for the years
1992-1996 occurred in the summer.  The net firm system peak demand for 1996,
which occurred on August 13, 1996, was 4,397 Mw. At that time, the net
dependable system capacity totaled 5,103 Mw (generating capacity of 3,314 Mw,
together with firm purchases of 1,789 Mw), which represented a reserve margin of
approximately 16%.  Net dependable system capacity is the maximum net capacity
available from both Company-owned generating units and purchased power contracts
to meet the net firm system peak demand.

PURCHASED POWER

     The Company purchases capacity and energy from various regional utilities
as well as QFs and an IPPF in order to meet the energy needs of its customers.
Capacity, typically measured in Kws or Mws, is the measure of the rate at which
a particular generating source produces electricity.  Energy, typically measured
in Kwhs or Mwhs, is a measure of the amount of electricity produced from a
particular generating source over a period of time.  Purchase power contracts
typically provide for a charge for the capacity from a particular generating
source, together with a charge for the associated energy actually purchased from
such generating source.  


                                      3

<PAGE>

The Company and Cheyenne have contracted with the
following sources for the firm purchase of capacity and energy at the time of
the anticipated summer 1997 net firm system peak demand through the expiration
of the contracts:

<TABLE>
                                                                    Mw Contracted     
                                                                   For at the Time    
                                                                  of the Anticipated  
                                              Generating         Summer 1997 Net Firm     Contract  
Company                                         Source            System Peak Demand     Expiration 
-------                                       ----------         --------------------    ---------- 
<S>                                     <C>                      <C>                     <C>        
Basin Electric Power Cooperative,       Laramie River Station
Agreements 1 and 2 (a) (b)              Units 2 and 3                      175              2016  

PacifiCorp (c)                          PacifiCorp System                  140              2000  

PacifiCorp (d)                          PacifiCorp Resource Pool           176              2011  

Platte River Power Authority (a) (e)    Craig Units 1 and 2;               180              2004   
                                        Rawhide Unit 1

Tri-State                                                                  525               (f)    
Agreements 1, 2, 3 and 4 (a) (f)        Laramie River Station         
                                        Units 2 and 3;
                                        Craig Units 1, 2 and 3

Agreement 5 (a) (f)                     Laramie River Station
                                        Units 2 and 3;
                                        Craig Units 1, 2 and 3;
                                        Nucla Units 1, 2, 3 and 4

Various Owners (a)                      QFs & IPPF                        627          Various dates 
                                                                        ----- 
                                                                        1,823 
                                                                        ----- 
                                                                        ----- 
</TABLE>

------------------- 
(a)  These contracts are contingent upon the availability of the units listed as
     the generating source.  These contracts are take and pay contracts.  Based
     upon the terms of these agreements, if the capacity is available from these
     units, the Company is obligated to pay for capacity whether or not it takes
     any energy.  However, the Company has historically satisfied the minimum
     energy requirements associated with these agreements and anticipates doing
     so in the future.  Additionally, if these units are unavailable, the
     supplying company has no obligation to furnish capacity or energy and the
     capacity charge to the Company is reduced accordingly.

(b)  The Company has entered into two agreements with Basin Electric Power
     Cooperative.  The first agreement is for 100 Mw of capacity through March
     31, 2016.  The second agreement is for 75 Mw of summer season capacity
     through March 31, 2016 and 25 Mw of winter season capacity through March
     31, 2010.
<PAGE>

(c)  This contract calls for PacifiCorp to sell to Cheyenne the total electric
     capacity and energy requirements associated with the operation of
     Cheyenne's service area. 

(d)  The current agreement with PacifiCorp expires October 31, 2022.  However,
     the agreement provides the Company the opportunity to exercise an
     irrevocable option to terminate the agreement on December 31, 2011,
     provided the Company gives notice to PacifiCorp no later than March 1,
     2002.

(e)  The amount of capacity to be made available for each summer and winter
     season is agreed upon prior to such season to the extent that Platte River
     Power Authority has excess capacity for such season.  

(f)  The Company has entered into five agreements with Tri-State.  Agreements 1,
     2 and 5 are contracts for 100 Mw each of capacity and expire in 2001, 2017
     and 2011, respectively.  Agreement 3 is a contract for 25 Mw of summer
     season capacity and 75 Mw of winter season capacity and expires in 2016. 
     Agreement 4 expires in 2018 and the related capacity is for the following
     amounts:  1997 through 2000 - 200 Mw and 2001 through 2018 - 250 Mw;
     however, either party may elect to reduce the Agreement 4 capacity by up to
     50 Mw each year, except for 2001, effective in the year 1999.  If the full
     50 Mw reduction is taken each year, the capacity associated with Agreement
     4 from 1999 on would be as follows:  1999 - 150 Mw, 2000 through 2001 - 100
     Mw, 2002 - 50 Mw with no commitments thereafter.  The Company has notified
     Tri-State of its intent to reduce the capacity associated with Agreement 4
     to 150 Mw for 1999.


                                      4

<PAGE>

     See Note 9. Commitments and Contingencies - Purchase Requirements in 
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for information regarding 
the Company's financial commitments under these contracts.  See Electric 
Transmission and Distribution Property in Item 2. PROPERTIES for a discussion 
of the Company's interconnections with these sources.

     Based on present estimates, the Company and Cheyenne will purchase
approximately 37% of the total electric system energy input for 1997.  In
addition, based on the capacity associated with the purchase power contracts
described above, approximately 36% of the total net dependable system capacity
for the estimated summer 1997 net firm system peak demand for the Company and
Cheyenne will be provided by purchased power, compared to approximately 35% in
1996.

     In accordance with the Public Utility Regulatory Policies Act of 1978
("PURPA"), the Company is obligated to purchase at "avoided cost" capacity and
energy from QFs.  The Company has had tariffs in effect since 1984 for these
purchases.

     In December 1987, the CPUC issued an order imposing a moratorium during
which the Company was no longer required to continue to execute additional QF
contracts due to the fact that excess generating capacity would be created if
additional contracts were executed.  Although a comprehensive QF bidding
procedure was adopted by the CPUC in 1988, which allowed the Company to purchase
the most competitively priced QF power, all of the QF capacity purchased by the
Company, including approximately 5 Mw of additional capacity scheduled to come
on line in the future, is being purchased under contracts entered into prior to
the adoption of such procedure.  Based on the 1988 comprehensive QF bidding
criteria, QFs could provide up to 20% of the Company's net firm system peak
load.  The CPUC has circulated proposed new rules that would supplant the 1988
comprehensive QF bidding criteria whereby long-term future resource needs would
be selected through a competitive bidding process.  In 1996, approximately 15%
of the Company's summer net firm system peak demand was provided by QFs.  

     In addition to long-term and QF and IPPF purchases, the Company also made
short-term and non-firm purchases throughout the year to replace generation from
Company owned units which were unavailable due to maintenance and unplanned
outages, to provide the Company's reserve obligation to the Pool, to obtain
energy at a lower cost than that which could be produced by other resource
options, including Company-owned generation and/or long-term purchase power
contracts, and for various other operating requirements.  Short-term and non-
firm purchases accounted for approximately 3% of the Company's total energy
requirement in 1996.

     Based on current projections, the Company expects that purchased 
capacity will continue to meet a significant portion of system requirements 
at least for the remainder of the 1990s.  Such purchases neither require the 
Company to make an investment nor afford the Company an opportunity to earn a 
return.  Further discussion related to recovery of purchased capacity costs 
can be found in "Regulations and Rates - State Regulation - Electric and Gas 
Adjustment Clauses".

     The Company is a member of the Pool which is composed of members each of
which owns and/or operates electric generation and/or transmission systems which
are interconnected to one or more other member systems.  The objective of the
Pool is to provide capacity which is categorized as: 1) immediately accessible;
2) accessible within ten minutes; and 3) accessible within twelve hours, as
required.  As a result of membership in the Pool, the Company can supply and
protect its electric system with less aggregate operating reserve capacity than
otherwise would be necessary; emergency conditions can be met with less
likelihood of curtailment or impairment of electric service; and generation and
transmission facilities and interconnections can be used more efficiently and
economically.

CONSTRUCTION PROGRAM

     At December 31, 1996, the Company and its subsidiaries estimated the cost
of their total construction program, including AFDC, to be approximately $327
million in 1997, approximately $376 million in 1998, and 


                                      5

<PAGE>

approximately $300 million in 1999 (see Item 7. MANAGEMENT'S DISCUSSION AND 
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS).

ELECTRIC FUEL SUPPLY

     The following table presents the delivered cost per million Btu of each
category of fuel consumed by the system for electric generation of the Company
and its utility subsidiary during the years indicated, the percentage of total
fuel requirements represented by each category of fuel and the weighted average
cost of all fuels during such years:

                                                                    Weighted   
                                                                      Average  
                                          Coal*          Gas       All Fuels** 
                                      ---------------------------------------- 
                                      Cost $    %    Cost $    %      Cost $ 

     1996...........................  1.029     98   2.424     2       1.054 
     1995...........................  0.992     99   1.521     1       0.998 
     1994...........................  1.038     99   2.069     1       1.053 
     1993...........................  1.078     98   2.319     2       1.097 
     1992...........................  1.091     99   2.065     1       1.105 

     *  The average cost per ton of coal, including freight, for years 1992
        through 1996 shown above was $21.14, $21.03, $20.57, $19.06 and
        $20.17, respectively.  

     ** Insignificant purchases of oil are included.

COAL

     The Company's primary fuel for its steam electric generating stations is
low-sulfur western coal.  The Company's coal requirements are purchased
primarily under seven long-term contracts with suppliers operating in Colorado
and Wyoming, the largest of which is with Cyprus/Amax Coal Company, which
operates the Belle Ayr and Eagle Butte Mines near Gillette, Wyoming and the
Foidel Creek and Empire Energy mines in northwestern Colorado.

     Long-term contracts presently in existence provide for a substantial
portion of future annual coal requirements.  Any shortfall will be provided by
purchases on the spot market.  During the year ended December 31, 1996, the
Company's coal requirements for existing plants were approximately 9,118,360
tons, a substantial portion of which was supplied pursuant to long-term supply
contracts.  Coal supply inventories at December 31, 1996 were approximately 43
days usage, based on the average peak burn rate for all the Company's coal-fired
plants.


                                      6

<PAGE>

     The following table provides a summary of the basic supply provisions of
the existing long-term contracts, which provide a minimum delivery of
approximately 78 million tons of low-sulfur coal over their remaining life (see
Note 9. Commitments and Contingencies - Purchase Requirements in Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ).

<TABLE>
                                                 MINIMUM              MAXIMUM        CONTRACT 
                                                 DELIVERY             DELIVERY       MAXIMUM  
                                             PER CONTRACT YEAR   PER CONTRACT YEAR    SULFUR  
COAL SUPPLIER AND DELIVERY YEAR                   IN TONS             IN TONS        CONTENT  
-------------------------------              -----------------   -----------------   -------- 
<S>                                          <C>                 <C>                 <C>      
Amax (1)
  1988 through Pawnee 2 completion.....          3,960,000              (2)            0.50% 
  Pawnee 2 completion through 2013.....          3,600,000              (3)            0.50% 

Colowyo Coal Company
  1992 through 2017....................             79,429 (4)      79,429             0.70% 

Cyprus Coal Company
  1988 through 1997....................          1,700,000       1,900,000             0.60% 

Mountain Coal Company
  1993 through 2000....................            600,000 (5)     800,000             0.67% 

Powderhorn Coal Company
  1995 through 1999....................            150,000         350,000             0.69% 

Seneca Coals, Ltd (6)
  1992 through 2004....................            439,800              (7)            1.00% 

Trapper Mining, Inc.
  1992 through 2014....................            189,108 (8)     189,108               (9) 
</TABLE>

(1)  The contract term is completed upon delivery of 144,843,970 tons regardless
     of the year in which delivery is completed.  From January 1, 1976 through
     December 31, 1996, 79,573,842 tons have been delivered.

(2)  Coal requirements of Comanche and Pawnee.

(3)  Coal requirements of Pawnee and Pawnee 2. 

(4)  The contract minimum quantity varies by year during the agreement from
     79,429 tons in 1996 to 124,810 tons in 2017.

(5)  The contract term is completed on December 31, 2000 or upon delivery of
     3,200,000 tons.  As of December 31, 1996, 2,181,740 tons have been
     delivered.

(6)  The contract term is completed upon total delivery of 31,250,000 tons to
     Hayden from and after January 1, 1983.  As of December 31, 1996, 20,604,164
     tons have been delivered.  Delivery is expected to be completed in the year
     2004.

(7)  Coal requirements of Hayden.

(8)  The contract minimum quantity varies by year during the agreement from
     189,108 tons in 1996 to 140,621 tons in 2014.

(9)  Not specified in the contract.

     Each coal contract contains adjustment clauses which permit periodic price
increases or decreases.  See Note 9.  Commitments and Contingencies - Purchase
Requirements in Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for
information regarding the Company's financial commitments under these contracts
as well as coal transportation contracts.

NATURAL GAS AND FUEL OIL

     The Company uses both firm and interruptible natural gas and standby oil in
combustion turbines and certain boilers.  Natural gas supplies for the Company's
power plants are procured under short-term contracts on a competitive basis to
provide an adequate supply of fuel.

                                      7
<PAGE>

NATURAL GAS OPERATIONS

     During the period 1992-1996, PSCo and Cheyenne have experienced growth in
the number of residential and commercial customers ranging from 1.4% to 3.4%
annually. Since 1992, residential and commercial gas volumes sold have averaged
131.9 million dekatherms ("MMDth") annually. The growth of residential and
commercial sales has steadily improved due primarily to stronger economic
conditions in Colorado and Wyoming. Growth of commercial customers has been
impacted by large commercial customers selecting to purchase gas directly from
suppliers. PSCo and Cheyenne transport gas through their transmission and
distribution facilities for large commercial and industrial customers which
purchase gas directly from suppliers.  Fees for transportation services, which
are paid by these customers, substantially offset the effect on net income of
the revenue loss from decreased sales of gas to these customers.  During 1996,
transportation services generated revenues of $28.5 million compared to $23.8
million in 1995 and $23.5 million in 1994.

     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 proposed as part of the merger with SPS (see Note 3. Merger in
Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). The Company is seeking
approval from the SEC to maintain these businesses and currently does not
anticipate that divestiture will be required. If divestiture is ultimately
required, the SEC has historically allowed companies sufficient time to
accomplish divestitures in a manner that protects shareholder value. 

     For a discussion of non-regulated gas marketing operations, see information
in "e prime and subsidiaries".

NATURAL GAS SUPPLY AND STORAGE 

     PSCo and Cheyenne have attempted to maintain low cost, reliable natural gas
supplies by optimizing a balance of long- and short-term gas purchase, firm
transportation and gas storage contracts.  During 1996, PSCo and Cheyenne
purchased 142.2 MMDth from approximately 71 suppliers, including the following
major suppliers:  Interstate (39.9 MMDth); Western Gas Resources (12.2 MMDth);
Barrett Resources (11.4 MMDth); Amoco Energy Trading Co. (11.3 MMDth); and
PanEnergy Gas Services, Inc. (6.0 MMDth).  In 1996, the average delivered cost
per one thousand dekatherms ("MDth") for PSCo and Cheyenne was $2.58 compared to
$2.22 per MDth in 1995 and $2.85 per MDth in 1994.  Purchased gas costs are
recovered from customers through the GCA  (see "Regulation and Rates - State
Regulation - Electric and Gas Adjustment Clauses").

     Interstate was the largest gas supplier to PSCo and Cheyenne in 1996. 
During 1993, PSCo and Cheyenne entered into two non-regulated supply agreements,
as allowed under FERC Order 636.  Under the agreement with Interstate, which
covered the period from October 1, 1993 through September 30, 1996, the annual
quantities purchased declined from 46 MMDth in the first year to 34 MMDth in the
second year and declined to 23 MMDth in the third year. Under the agreement with
KN Gas Supply Services, Inc., which covered the period from September 1, 1993
through August 31, 1996, the annual quantities to be purchased were fixed at 4
MMDth. During 1996, PSCo and Cheyenne entered into new contracts with Interstate
and others for firm transportation and gas storage services with terms of 5-7
years.  Adequate supplies of natural gas are currently available for delivery
within the Rocky Mountain region. PSCo and Cheyenne continually evaluate the
natural gas market and procure supplies, as needed, to meet current and
anticipated customer demand.

REGULATION AND RATES

     The Company is subject to the jurisdiction of the CPUC with respect to its
facilities, rates, accounts, services and issuance of securities.  Cheyenne is
subject to the jurisdiction of the WPSC.  The Company is subject to the
jurisdiction of the DOE through the FERC with respect to its wholesale electric
operations and accounting practices and policies.  The Company is also subject
to the jurisdiction of the NRC with respect to the decommissioning of Fort St.
Vrain.  Although the Company is a "holding company" under the PUHCA, it has
filed an annual exemption statement pursuant to Rule 2 of the SEC under that Act
and is, therefore, currently exempt from all of the provisions of such Act and
the Rules thereunder, except Section 9(a)(2) thereof.  Such 


                                      8

<PAGE>

exemption is subject to termination under Rule 6 of PUHCA.  On January 30, 
1996, as part of the Merger of the Company with SPS, NCE filed its 
application with the SEC to be a registered public utility holding company, 
which would subject the Company and its subsidiaries to regulation under 
PUHCA (see "Recent Developments" in Item 7.  MANAGEMENT'S DISCUSSION AND 
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS).

     The Company holds a FERC certificate which allows it to transport 
natural gas in interstate commerce pursuant to the provisions of the Natural 
Gas Act, the Natural Gas Policy Act of 1978 and FERC Order Nos. 436 and 500 
without the Company becoming subject to full FERC jurisdiction.  WGI and TOP 
each hold a FERC certificate which allows them to transport natural gas in 
interstate commerce pursuant to the provisions of the Natural Gas Act.  WGI 
and TOP are subject to FERC jurisdiction.  e prime and TOG have authorization 
from FERC to act as power marketers.

MERGER RATE FILINGS

     See Note 3. Merger and Note 9.  Commitments and Contingencies - Regulatory
Matters - Merger Rate Filings in Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA. 

STATE REGULATION

CPUC

     The CPUC consists of three full-time members appointed by the Governor and
approved by the Colorado Senate.  Only two members may be from the same
political party. 

     In 1996, the CPUC opened an  inquiry docket related to electric utility
restructuring.  The Company submitted a response to a CPUC sponsored
restructuring questionnaire which was followed by the CPUC issuing a summary of
all responses.  The CPUC is currently working with the Colorado General Assembly
in its investigation and implementation of public policy.

GAS RATE CASE
     See Note 9.  Commitments and Contingencies - Rate Case in Item 8. 
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
 
ELECTRIC AND GAS ADJUSTMENT CLAUSES

     At December 31, 1996, the Company has four adjustment clauses: the ICA
(which replaced the ECA), GCA, DSMCA and QFCCA.  These adjustment clauses allow
certain costs to be passed through to retail customers.  The Company and
Cheyenne are required to file applications with their respective state
regulatory commissions for approval of adjustment mechanisms in advance of the
proposed effective date.  The applications must be acted upon before becoming
effective. 

     During 1994 and 1995, the CPUC conducted several proceedings to review
issues related to the ECA. 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 in Note 9. 
Commitments and Contingencies - Regulatory Matters - Merger Rate Filings in Item
8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.  The CPUC decision on the
Merger modified and replaced the ECA with the ICA.  The ICA, which became
effective October 1, 1996, allows for a 50%/50% sharing of certain fuel and
energy cost increases and decreases among customers and shareholders.  

     The Company, through its GCA, is allowed to recover the difference between
its actual costs of purchased gas and the amount of these costs recovered under
its base rates.  The GCA rate is revised annually on October 1 and otherwise as
needed, to coincide with changes in purchased gas costs.  Purchased gas costs
and 

                                       9

<PAGE>

revenues received to recover such gas costs are compared on a monthly basis
and differences, including interest, are deferred.

     The CPUC has had an on-going docket to review the status of the GCA and
will determine whether it should be maintained in its present form, altered or
eliminated.  The CPUC conducted hearings regarding this matter on February 14,
1997.  Additional hearings have been scheduled for March 7, 1997.

     The QFCCA was implemented on December 1, 1993.  Under the QFCCA, all
purchased capacity costs from new QF projects, not otherwise reflected in base
electric rates, are recoverable.  The DSMCA is discussed below in "Incentive
Regulation and Demand Side Management".

INCENTIVE REGULATION AND DEMAND SIDE MANAGEMENT

     The Company, in a collaborative process with public interest groups,
consumers and industry, has developed DSM programs (programs designed to reduce
peak electricity demand, shift on-peak demand to off-peak hours and provide for
more efficient operation of the electric generation system), including incentive
and cost recovery mechanisms.  The CPUC approved the programs in 1993 along with
a schedule to be implemented over a three-year period.  Effective July 1, 1993,
the Company implemented a DSMCA clause which permits it to recover deferred DSM
costs over seven years while non-labor incremental expenses, carrying costs
associated with deferred DSM costs and certain incentives associated with the
approved DSM programs are recovered on an annual basis.

     The CPUC subsequently opened a separate docket to investigate issues
involving alternative annual revenue reconciliation mechanisms and incentive
mechanisms related to the Company's DSM programs.  The investigation was
completed in 1995 and a final order was issued. The major provisions of the
final order, effective December 27, 1995, included: 1) not to proceed with any
of the proposed mechanisms; 2) to reduce the recovery period for certain costs
of the Company's DSM programs from seven to five years for expenditures made on
or after January 1, 1995; 3) not to establish DSM targets for 1997 and 1998; 4)
not to adopt a penalty for failure to achieve DSM targets; and 5) to approve the
Company's proposal to forego incentive payments for DSM programs.

     Under a separate CPUC order issued in December 1992, the Company has
implemented a Low-Income Energy Assistance Program.  The costs of this energy
conservation and weatherization program for low-income customers are recoverable
through the DSMCA.

IRP - ELECTRIC

The Company filed a new IRP with the CPUC in October 1996.  A final order is
expected in 1997.

WPSC

     In June 1993, Cheyenne filed gas and electric IRPs with the WPSC pursuant
to a settlement agreement.  The WPSC has not formally acted on these filings.

     The WPSC has approved adjustment mechanisms which permit Cheyenne to
recover purchased energy costs.

FEDERAL ENERGY REGULATORY COMMISSION

     See Note 9.  Commitments and Contingencies - Regulatory Matters - Rate
Cases in Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for information
related to the Company's FERC rate case.

     Information regarding FERC Order No. 888, Order No. 889 and the NOPR on
Capacity Reservation Open Access Transmission Tariffs is discussed in Note 9. 
Commitments and Contingencies - Regulatory Matters - Federal Energy Regulatory
Commission in Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.


                                      10

<PAGE>

ENVIRONMENTAL MATTERS

     Environmental regulations at the Federal, state and local levels, including
the Clean Air Act Amendments (CAAA) of 1990 and other environmental matters, are
expected to have a continuing impact on the Company's operations.  See Note 9.
Commitments and Contingencies - Environmental Issues in Item 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA for a discussion of the impact on the Company
of the CAAA of 1990, environmental site clean-up, and other environmental
matters not discussed below.  The Company continues to strive to achieve
compliance with all environmental regulations currently applicable to its
operations.  However, it is not possible at this time to determine when or to
what extent additional facilities or modifications of existing or planned
facilities will be required as a result of changes to environmental regulations,
interpretations or enforcement policies or, generally, what effect future laws
or regulations may have upon the Company's operations.

     At December 31, 1996, the estimated 1997, 1998 and 1999 expenditures for
environmental air and water emission control facilities were $29.6 million,
$43.7 million and $23.2 million, respectively.  As discussed below the Company's
share of estimated cost to install emission control equipment at the Hayden
station for the years 1997 through 1999 is approximately $70 million.

     The Company continues to research and implement various SO2 and NOx
emissions reduction projects, including two CCT3 projects.  The CCT3 projects
are part of a larger DOE Clean Coal Program, which co-funds developing
technologies aimed at more efficient and environmentally acceptable methods of
burning coal. Research and implementation continues on the two CCT3 projects,
which involve Arapahoe Unit 4 and Cherokee Unit 3.  Modification and testing at
Cherokee Unit 3 and Arapahoe Unit 4 was conducted through 1996 and is expected
to continue into 1997.  

     The Company is currently participating in the Northern Front Range Air
Quality Study (NFRAQS), a follow-up study to the previous Metro Denver Brown
Cloud Studies, which is designed to investigate the formation of secondary
particulates in the Denver metropolitan area.  The previous study, completed in
1993, was inconclusive and did not offer any policy recommendations.  The NFRAQS
began field sampling in early December 1996 and is expected to be completed by
December 1997.   Also, the EPA issued a draft particulate regulation in 1996,
requesting public comments on the proposed regulation with issuance of the final
regulation expected in June 1997.  The Company is currently evaluating the
impact of this new regulation on its operations.

     The Mount Zirkel Wilderness Area ("MZWA") Reasonable Attribution Study,
designed to ascertain the contribution of various emission sources to visibility
impairment in the MZWA was completed in 1996.  The Company is a participant in
the Hayden and Craig generating stations, in the nearby Yampa Valley.  The study
results revealed that the Hayden and Craig Stations were minor contributors to
visibility impairment in the MZWA.  In May 1996, the joint owners of the Hayden
station reached a settlement with a conservation organization, the Colorado
Department of Public Health and Environment, and the EPA to resolve alleged air
quality concerns in the Yampa Valley.  The settlement, among certain other
items, will result in the installation of additional emission control equipment
at the Hayden station (see Note 9. Commitments and Contingencies - Environmental
Issues in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).

     Pursuant to the requirements of the Federal Clean Water Act, as amended,
and the Colorado Water Quality Control Act and regulations issued thereunder,
the Company receives National Pollution Discharge Elimination System permits to
discharge effluents into various streams and waters of the State of Colorado for
each of its generating stations.  These permits, which have a five-year life,
are issued by the CWQCD, but are subject to review by the EPA.  The Company
believes it is presently in compliance with such discharge permits.  

     Renewed wastewater discharge permits have been issued for: 1) Fort St.
Vrain, effective April 1, 1993; 2) Cherokee, effective July 1, 1993; 3) Zuni,
effective August 1, 1993; 4) Hayden, effective August 1, 1994; 5) Valmont,
effective October 1, 1994; 6) Arapahoe, effective December 1, 1994; 7) Cameo,
effective December 1, 1994 and 8) Comanche effective July 1, 1996.  A renewal
wastewater discharge permit for the Leyden Gas Storage facility is expected in
the first quarter of 1997.  All discharge permits that are not renewed by the


                                      11

<PAGE>

CWQCD prior to their expiration date automatically receive an administrative
extension pending the issuance of a final permit.

     The Company has completed the preparation of applications for Operating
Permits as required by Title V of the 1990 CAAA.  Permits were submitted to the
state health department to meet 1996 submittal deadlines.  The Company received
its first Operating Permit in December 1996 for the Denver Steam Plant.  The
Company has applied for an early election of annual NOx emission limits for six
units including Cherokee Units 3 and 4, Valmont Unit 5, Pawnee Unit 1, and
Comanche Units 1 and 2.  If the Company meets emission limits for these six
units, as required by the early election, the Company would have until the year
2008, rather than the year 2000, to meet the lower emission limits established
by Phase II of the CAAA.

COMPETITION

INDUSTRY OUTLOOK

     Unprecedented change is occurring in the electric utility industry
nationwide, furthering the development of a competitive environment.  In
general, the economics of the electric generation business have fundamentally
changed with open transmission access and the increased availability of electric
supply alternatives. Such alternatives will ultimately serve to lower customer
prices, particularly in areas where only higher cost energy is currently
provided.  Customer demands for lower prices and supplier choices, the
availability of alternative supplies (IPPFs, QFs, EWGs and power marketers), and
open access to the utility transmission grid have resulted in a commodity market
for bulk electric supply.  The EPAct directly addressed this issue by giving the
FERC the authority to require utilities to provide non-discriminatory open
access to the transmission grid for purposes of providing wholesale customers
with direct access.  In response to such authority, in early 1996, the FERC
issued new rules on open access transmission services.  Furthermore, an
increasing number of states with above average energy prices are pursuing full
competition in the electric industry.

     The presence of competition and the associated pressure on prices may
ultimately lead to the unbundling of products and services similar to what has
evolved in the natural gas industry.  Today's market view of the future
envisions an unbundled electric utility industry consisting of at least four
major business segments: energy supply, transmission, distribution and energy
services - each having a different driving force. 

     The SEC has also responded to increasing competition in the utility
industry and changes in state and federal utility regulation.  In June 1995, the
SEC issued its report which focused on both legislative and administrative
options for the reform of public utility holding company regulation.  The report
presented three possible recommendations for legislative reform of PUHCA: 1)
conditional repeal of PUHCA, 2) unconditional repeal of PUHCA, and 3) PUHCA
remains unmodified, but grants the SEC broader exemptive authority under PUHCA.
Any changes in regulation will be determined by Congress.

     Further discussion can be found in Item 7.  MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

STATE REGULATORY ENVIRONMENT

     Colorado law permits the CPUC to authorize rates negotiated with 
individual electric and gas customers which have threatened to discontinue 
using the services of the Company, so long as the CPUC finds that such 
authorization: 1) in the case of electric rates, will not adversely affect 
the Company's remaining customers and 2) in the case of gas rates, will not 
affect the Company's remaining customers as adversely as would the 
alternative. In response to the increasingly competitive operating 
environment for utilities, the regulatory climate is also changing.  The CPUC 
recently issued a report on a comprehensive survey on electric industry 
restructuring.  The Company continues to participate in regulatory 
proceedings which could change or impact current regulation. The Company 
believes it will continue to be subject to rate regulation that will allow 
for the recovery of all of its deferred costs (see Note 1. Summary of 
Significant Accounting Policies - Business and Regulation - Regulatory 


                                      12

<PAGE>

Assets and Liabilities and Note 9. Commitments and Contingencies - Regulatory 
Matters in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).

ELECTRIC

     The wholesale electric business faces increasing competition in the supply
of bulk power due to provisions of the EPAct and Federal and state initiatives
with respect to providing open access to utility transmission systems.  Under
the new FERC rules issued in early 1996, utilities are required to provide
wholesale open-access transmission services consistent with what is provided for
in their own operations.  The Company and Cheyenne are operating with the
tariffs approved by the FERC under these new rules.  To date, these provisions
have not had a material impact on the Company's operations.  For 1996, the
Company's wholesale revenues totaled approximately 8% of total electric
revenues.  A substantial portion of these revenues related to firm sales
contracts, which are expected to continue at current levels for a minimum of 10
years.

     Today, the retail electric business faces increasing competition from
industrial and large commercial customers who have the ability to own or operate
facilities to generate their own electric energy requirements.  In addition,
customers may have the option of substituting fuels, such as natural gas for
heating, cooling and manufacturing purposes rather than electric energy, or of
relocating their facilities to a lower cost environment. While the Company faces
these challenges, it believes its rates are competitive with currently available
alternatives.  The Company is taking actions to lower operating costs and is
working with its customers to analyze the feasibility of various options,
including energy efficiency, load management and co-generation in order to
better position the Company to more effectively operate in a competitive
environment.  

NATURAL GAS

     Historically, gas utilities have competed with suppliers of electricity and
fuel oil, as well as, to a lesser extent, propane, for sales of gas to customers
for heating and/or cooling purposes.  In the 1980s, industrial and large
commercial customers began to "by-pass" the local gas utility through the
construction of interconnections directly with, and the purchase of gas directly
from, interstate pipelines, thereby avoiding the additional charges added by the
local gas utility.  In addition, industrial and commercial customers sought to
purchase less expensive supplies of natural gas directly from producers,
marketers and brokers.  The Company has been actively involved for several years
in providing transportation services for those industrial and large commercial
customers which chose to purchase gas directly from suppliers.  In addition, the
Company has provided flexible transportation rates for several years.  The per-
unit fee charged for transportation services, while significantly less than the
per-unit fee charged for the sale of gas to a similar customer, provides an
operating margin approximately equivalent to the margin earned on gas sold. 
Therefore, increases in such activities will not have as great an impact on gas
revenues as increases in deliveries from the sale of gas, but will have a
positive impact on operating margin.  In 1995, the Company organized e prime to
engage in the non-regulated marketing of natural gas in order to expand its
marketshare.

FRANCHISES

     The Company and its subsidiaries held nonexclusive franchises to provide
electric or gas service or both services in 120 incorporated cities and towns at
December 31, 1996.  These franchises consist of 69 combined gas and electric
service franchises, 29 electric service franchises and 22 gas service
franchises.  In 1997, the Company expects to renegotiate four of the franchise
agreements which will be expiring.  The Company's franchise with the City of
Denver will expire in 2006.  The Company and its subsidiaries supply electric or
gas service or both services in about 114 unincorporated communities in which
franchises are not required. 

EMPLOYEES AND UNION CONTRACTS

     The number of employees of the Company and its subsidiaries decreased from
4,776 at December 31, 1995 to 4,675 at December 31, 1996.  Approximately, 2,090
employees, or 45% of the Company's total 


                                      13

<PAGE>

workforce, are represented by the International Brotherhood of Electrical 
Workers, Local 111. The number of employees covered by collective bargaining 
agreements at December 31, 1996 approximated 2,284.

RESEARCH AND DEVELOPMENT

     The Company and its utility subsidiaries spent approximately $3.8 million
in 1996, $3.6 million in 1995 and $3.8 million in 1994 on research and
development.  The major portion of those expenditures went to utility
associations which engage in research projects to benefit the electric and gas
industries as a whole.  The balance of the expenditures went for smaller
internal and external projects dealing with such areas as pollution control and
alternative fuels research.
























                                        14
<PAGE>

                 CONSOLIDATED ELECTRIC OPERATING STATISTICS

<TABLE>
                                                                        YEAR ENDED DECEMBER 31,                       
                                                --------------------------------------------------------------------- 
                                                   1996           1995           1994          1993          1992     
                                                -----------   ------------   ------------   -----------   ----------- 
<S>                                             <C>           <C>            <C>            <C>           <C>         
Energy Generated, Received, 
 & Sold (Thousands of Kwh):
Net Generated:
  Steam, Fossil................................  17,099,890     16,053,928     15,949,980    15,470,247    14,972,688 
  Combustion Turbine...........................     121,079          5,251         41,705        39,228        47,194 
  Pumped Storage...............................     178,205         68,400        126,721       118,593        79,609 
  Hydro........................................     197,660        208,104        176,264       198,272       175,010 
                                                -----------   ------------   ------------   -----------   ----------- 

    Total Net Generation.......................  17,596,834     16,335,683     16,294,670    15,826,340    15,274,501 
  Energy Used for Pumping......................     276,983        109,632        201,744       185,850       126,266 
                                                -----------   ------------   ------------   -----------   ----------- 

    Total Net System Input.....................  17,319,851     16,226,051     16,092,926    15,640,490    15,148,235 
  Purchased Power and Net Interchange..........  10,349,298      9,794,968      9,653,067     9,631,982     8,663,339 
                                                -----------   ------------   ------------   -----------   ----------- 

    Total System Input.........................  27,669,149     26,021,019     25,745,993    25,272,472    23,811,574 
  Used by Company..............................      57,603         64,885         66,348        60,396        64,125 
  Other (1)....................................   1,352,843      1,526,358      1,670,591     2,001,832     1,932,333 
                                                -----------   ------------   ------------   -----------   ----------- 
    Total Energy Sold..........................  26,258,703     24,429,776     24,009,054    23,210,244    21,815,116 
                                                -----------   ------------   ------------   -----------   ----------- 
                                                -----------   ------------   ------------   -----------   ----------- 

Electric Sales (Thousands of Kwh) (2):
  Residential.................................    6,606,601      6,281,911      6,119,914     5,969,529     5,747,048 
  Commercial..................................    9,880,502      9,284,577      8,931,962    10,797,272    10,350,155 
  Industrial..................................    5,791,608      5,747,534      5,726,837     3,289,501     3,375,638 
  Public Authorities..........................      200,070        188,363        187,939       186,397       187,500 
  Wholesale - Regulated.......................    3,361,217      2,927,391      3,042,402     2,967,545     2,154,775 
  Wholesale Energy Services - Non-Regulated...      418,705              -              -             -             - 
                                                -----------   ------------   ------------   -----------   ----------- 
    Total Energy Sold.........................   26,258,703     24,429,776     24,009,054    23,210,244    21,815,116 
                                                -----------   ------------   ------------   -----------   ----------- 
                                                -----------   ------------   ------------   -----------   ----------- 

Number of Customers at End of Period(2):
  Residential.................................      959,249        936,759        913,582       898,752       894,217 
  Commercial..................................      126,426        123,277        120,886       120,317       120,198 
  Industrial..................................          380            378            384           157           194 
  Public Authorities..........................       79,725         79,154         77,842        76,476           647 
  Wholesale - Regulated.......................           26             17             18            20            34 
  Wholesale Energy Services - Non-Regulated...            6              -              -             -             - 
                                                -----------   ------------   ------------   -----------   ----------- 
    Total Customers...........................    1,165,812      1,139,585      1,112,712     1,095,722     1,015,290 
                                                -----------   ------------   ------------   -----------   ----------- 
                                                -----------   ------------   ------------   -----------   ----------- 

Electric Revenues (Thousands of Dollars)(2):
  Residential.................................  $   507,233   $    477,740   $    453,614   $   433,521   $   413,655 
  Commercial..................................      571,536        552,905        519,340       602,187       572,780 
  Industrial..................................      249,774        257,189        252,552       142,146       148,951 
  Public Authorities..........................       25,798         23,029         21,950        20,828        20,221 
  Wholesale - Regulated.......................      120,478        114,514        120,238       116,937        80,290 
  Wholesale Energy Services - Non-Regulated...        7,806              -              -             -             - 
  Other Electric Revenues.....................        6,365         23,719         32,142        21,434        24,872 
                                                -----------   ------------   ------------   -----------   ----------- 
    Total Electric Revenues...................  $ 1,488,990   $  1,449,096   $  1,399,836   $ 1,337,053   $ 1,260,769 
                                                -----------   ------------   ------------   -----------   ----------- 
                                                -----------   ------------   ------------   -----------   ----------- 
Average Annual Kwh Sales per Residential 
 Customer.....................................        6,965          6,794          6,770         6,717         6,533 
Average Annual Revenue per Residential 
 Customer.....................................      $534.79        $516.70        $501.82       $487.81       $470.26 
Average Residential Revenue per Kwh...........         7.68 CENTS     7.61 CENTS     7.41 CENTS    7.26 CENTS    7.20 CENTS
Average Commercial Revenue per Kwh...........          5.78 CENTS     5.96 CENTS     5.81 CENTS    5.58 CENTS    5.53 CENTS
Average Industrial Revenue per Kwh............         4.31 CENTS     4.47 CENTS     4.41 CENTS    4.32 CENTS    4.41 CENTS
Average Wholesale - Regulated Revenue per Kwh.         3.58 CENTS     3.91 CENTS     3.95 CENTS    3.94 CENTS    3.73 CENTS
</TABLE>

------------------- 
(1)  Primarily includes net distribution and transmission line losses.

(2)  Comparison of energy sales, customers and electric revenues between periods
     is impacted by: 1) a change in criteria for counting customers resulting 
     from the implementation of a new customer information system during 1993,
     and 2) effective January 1, 1994, a reclassification to include large 
     commercial customers (>1,000 Kw demand) within the industrial category, to 
     be consistent with recommended utility industry guidelines.



                                       15
<PAGE>
                                     
                   CONSOLIDATED GAS OPERATING STATISTICS

<TABLE>
                                                                        YEAR ENDED DECEMBER 31,                       
                                                --------------------------------------------------------------------- 
                                                   1996           1995           1994          1993          1992     
                                                -----------   ------------   ------------   -----------   ----------- 
<S>                                             <C>           <C>            <C>            <C>           <C>         
Natural Gas Purchased and 
 Sold (Thousands of Dth):
  Purchased from Interstate....................      39,924         38,687         45,177        55,078        59,328 
  Purchased from Others........................     107,374        101,259         88,174        88,482        79,011 
  Purchased for Non-regulated Gas 
   Marketing (1)...............................      22,807            237              -             -             - 
                                                -----------   ------------   ------------   -----------   ----------- 
    Total Purchased............................     170,105        140,183        133,351       143,560       138,339 
  Company Use..................................         520          1,330          2,386         2,349         2,603 
  Other (2)....................................      10,000          5,657          3,824        (1,803)        6,052 
                                                -----------   ------------   ------------   -----------   ----------- 
    Total Gas Sold.............................     159,585        133,196        127,141       143,014       129,684 
                                                -----------   ------------   ------------   -----------   ----------- 
                                                -----------   ------------   ------------   -----------   ----------- 
Gas Deliveries (Thousands of Dth):
  Residential..................................      86,102         82,188         77,955        83,991        74,951 
  Commercial...................................      50,100         50,463         48,689        54,125        50,705 
  Wholesale....................................       1,555            308            497         4,898         4,028 
  Non-regulated Gas Marketing (1)..............      21,828            237              -             -             - 
                                                -----------   ------------   ------------   -----------   ----------- 
    Total Gas Sold.............................     159,585        133,196        127,141       143,014       129,684 
  Transportation...............................      90,304         75,704         66,230        61,421        51,706 
  Gathering and Processing (3).................       1,141          1,391         25,316        35,877        28,292 
                                                -----------   ------------   ------------   -----------   ----------- 
    Total Deliveries...........................     251,030        210,291        218,687       240,312       209,682 
                                                -----------   ------------   ------------   -----------   ----------- 
                                                -----------   ------------   ------------   -----------   ----------- 
Number of Customers at End of Period:
  Residential..................................     902,078        872,777        845,464       820,521       808,722 
  Commercial...................................      90,761         89,034         87,103        86,227        86,192 
  Wholesale ...................................           -              -              8             8             8 
  Non-regulated Gas Marketing (1)..............       1,255              2              -             -             - 
                                                -----------   ------------   ------------   -----------   ----------- 
    Total......................................     994,094        961,813        932,575       906,756       894,922 
  Transportation and Other.....................       1,794            952            786           619           416 
                                                -----------   ------------   ------------   -----------   ----------- 
    Total Customers............................     995,888        962,765        933,361       907,375       895,338 
                                                -----------   ------------   ------------   -----------   ----------- 
                                                -----------   ------------   ------------   -----------   ----------- 
Gas Revenues (Thousands of Dollars):
  Residential.................................. $   362,481   $    383,719   $    375,406   $   366,445   $   329,406 
  Commercial...................................     173,308        200,314        203,311       204,820       191,366 
  Wholesale ...................................       3,020          4,961          7,319        13,966        10,099 
  Non-regulated Gas Marketing (1)..............      64,389            399              -             -             - 
  Transportation...............................      28,549         23,769         23,495        23,176        20,638 
  Gathering and Processing.....................         364            443          8,335        10,575         8,023 
  Other Gas Revenues...........................       8,386         10,980          7,056         9,342         9,354 
                                                -----------   ------------   ------------   -----------   ----------- 
    Total Gas Revenues......................... $   640,497   $    624,585   $    624,922   $   628,324   $   568,886 
                                                -----------   ------------   ------------   -----------   ----------- 
                                                -----------   ------------   ------------   -----------   ----------- 
Average Annual Dth Sales per Residential 
 Customer......................................       97.14          95.65          93.67        103.21         93.73 
Average Annual Revenue per Residential 
 Customer......................................     $408.93        $446.58        $451.09       $450.29       $411.94 
Average  Revenue per Dekatherm:
  Residential..................................      $4.210         $4.669         $4.816        $4.363        $4.395 
  Commercial...................................      $3.459         $3.970         $4.176        $3.784        $3.774 
  Transportation...............................      $0.316         $0.314         $0.355        $0.377        $0.399 
</TABLE>

------------------- 
(1)  Includes purchases and sales by e prime and TOG.

(2)  Primarily includes distribution and transmission line losses and net 
     changes to gas in storage.

(3)  In August 1994, the Company sold WGG, which resulted in the decline in 
     gathering and processing deliveries.

                                       16
<PAGE>

                    PUBLIC SERVICE COMPANY OF COLORADO 
               ELECTRIC TRANSMISSION INTERCONNECTED SYSTEM 





                                   [MAP]















                                       17
<PAGE>

ITEM 2.  PROPERTIES

ELECTRIC GENERATION PROPERTY

  The electric generating stations of the Company and its subsidiaries expected 
to be available at the time of the anticipated 1997 net firm system peak demand 
during the summer season are as follows: 

<TABLE>

                                                                              Net Dependable 
                                                            Installed           Capacity (Mw)
                                                               Gross       at Time of Anticipated     Major  
                    Name of Station                          Capacity       1997 Net Firm System       Fuel  
                     and Location                              (Mw)             Peak Demand*          Source 
                    ---------------                         ---------      ----------------------     ------ 
<S>                                                         <C>            <C>                        <C>    
Steam:
  Arapahoe-Denver.......................................       262.00              246.00             Coal   
  Cameo-near Grand Junction.............................        77.00               72.70             Coal   
  Cherokee-Denver.......................................       784.00              723.00             Coal   
  Comanche-near Pueblo..................................       725.00              660.00             Coal   
  Craig-near Craig......................................        86.90 (a)           83.20             Coal   
  Hayden-near Hayden....................................       259.00 (b)          237.00             Coal   
  Pawnee-near Brush.....................................       530.00              495.00             Coal   
  Valmont-near Boulder (Unit 5).........................       188.00              178.00             Coal   
  Zuni-Denver...........................................       115.00              107.00            Gas/Oil 
                                                             --------            -------- 
    Total...............................................     3,026.90            2,801.90

Fort St. Vrain Combustion Turbine  - near Platteville...       141.45              126.75              Gas   
Combustion turbines (6 units-various locations).........       209.00              171.00              Gas   
Hydro (14 units-various locations) (c)..................        53.35               36.55 (d)         Hydro  
Cabin Creek Pumped Storage-near Georgetown..............       324.00 (e)          162.00             Hydro  
Cherokee Diesel generators (2 units)....................         5.50                5.50              Oil   
                                                             --------            -------- 
    Total...............................................     3,760.20            3,303.70                    
                                                             --------            -------- 
                                                             --------            -------- 
</TABLE>

------------------- 
*   A measure of the unit capability planned to be available at the time of 
    the system peak load net of seasonal reductions in unit capability due to 
    weather, stream flow, fuel availability and station housepower, including 
    requirements for air and water quality control equipment.

(a) The gross maximum capability of Craig Units No. 1 and No. 2 is 894 Mw, of
    which the Company has a 9.72% undivided ownership interest.

(b) The gross maximum capability of Hayden Units No. 1 and No. 2 is 202.01 Mw
    and 285.96 Mw, respectively, of which the Company has a 75.5% and 37.4%
    undivided ownership interest, respectively.

(c) Includes one station (two units) not owned by the Company but operated
    under contract.

(d) Seasonal Hydro Plant net dependable capabilities are based upon average
    water conditions and limitations for each particular season.  The
    individual plant seasonal capabilities are sometimes limited by less than
    design water flow.

(e) Capability at maximum load.

NUCLEAR GENERATION PROPERTY

    Fort St. Vrain, near Platteville, the Company's only previous nuclear
generating station, ceased operations on August 29, 1989 and on March 22, 1996
the physical decommissioning of the station was completed. The initial phase of
the repowered gas fired combined cycle steam electric generating station began
commercial operations on May 1, 1996 (see Note 2. Fort St. Vrain in Item 8. 
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).  

ELECTRIC TRANSMISSION AND DISTRIBUTION PROPERTY

    On December 31, 1996, the Company's transmission system consisted of
approximately 112 circuit miles of 345 Kv overhead lines; 1,916 circuit miles of
230 Kv overhead lines; 15 circuit miles of 230 Kv underground 

                                       18
<PAGE>

lines; 65 circuit miles of 138 Kv overhead lines; 999 circuit miles of 115 Kv 
overhead lines; 20 circuit miles of 115 Kv underground lines; 344 circuit 
miles of 69 Kv overhead lines; 143 circuit miles of 44 Kv overhead lines; and 
1 circuit mile of 44 Kv underground lines.  The Company jointly owns with 
another utility approximately 342 circuit miles of 345 Kv overhead lines and 
360 miles of 230 Kv overhead lines, of which the Company's share is 112 miles 
and 147 miles, respectively, which shares are included in the amounts listed 
above.

    The Company's transmission facilities are located wholly within Colorado. 
The map on page 16 illustrates the Company's transmission interconnected 
system. The system is interconnected with the systems of the following 
utilities with which the Company has major firm purchase power contracts; 
capacity and energy are provided primarily by generating sources in the 
locations indicated: 

    Utility                                                Location 
    -------                                                -------- 
    Basin Electric Power Cooperative....................   Southeast Wyoming
    PacifiCorp..........................................   West & Northwest U.S.
                                                           Northwest Colorado
    Platte River Power Authority........................   Northcentral Colorado
    Tri-State...........................................   Southeast Wyoming and
                                                           Northwest Colorado

    The Company has wheeling agreements with the above, and with other
utilities and public power agencies, which are utilized to provide capacity and
energy to the Company's system from time to time.    

    The Company is a member of the WSCC, an interstate network of transmission
facilities which are owned by public entities and investor-owned utilities. 
WSCC is the regional reliability coordinating organization for member electric
power systems in the western United States.

    At December 31, 1996, the distribution systems consisted primarily of
approximately 12,939 miles of overhead line, 1,068 miles of which are located on
poles owned by other utilities under joint use agreements.  The Company also
owned approximately 7,891 cable miles of underground distribution system
(excluding street lighting) located principally in the Denver metropolitan area.
The Company owned 219 substations (four of which are jointly owned) having an
aggregate transformer capacity of 18,705,000 Kva, of which 4,145,827 Kva is
step-up transformer capacity at generating stations.  

GAS PROPERTY

    The gas property of the Company at December 31, 1996 consisted chiefly of
approximately 15,304 miles of distribution mains ranging in size from 0.50 to 30
inches and related equipment.  The Denver distribution system consisted of 8,691
miles of mains.  Pressures in the low pressure system are varied to meet load
requirements and individual house regulators are installed on each customer's
premises to provide uniform flow of gas to appliances.  The Company also owns
and operates four gas storage facilities.

OTHER PROPERTY

    The Company's steam heating property at December 31, 1996 consisted of 10.5
miles of transmission, distribution and service lines in the central business
district of Denver, including a steam transmission line connecting the steam
heating system with Zuni.  Steam is supplied from boilers installed at the
Company's Denver Steam Plant which has a capability of 295,000 pounds of steam
per hour under sustained load and an additional 300,000 pounds of steam per hour
is available from Zuni on a peak demand basis.  The Company also owns service
and office facilities in Denver and other communities strategically located
throughout its service territory.



                                       19
<PAGE>

PROPERTY OF SUBSIDIARIES

    The book value of the properties of the consolidated subsidiaries of the
Company aggregates approximately 3% of the total book value of the properties of
the Company and such subsidiaries combined.  Such properties consist largely of
electric and gas properties similar in character to the properties of the
Company. Unregulated subsidiary property is approximately 1% of the total book
value of the properties of the Company and consolidated subsidiaries combined. 
1480 Welton, Inc. owns two buildings that are used by the Company. 

CHARACTER OF OWNERSHIP

    The steam electric generating stations, the majority of major electric
substations and the major gas regulator stations owned by the Company and its
subsidiaries are on land owned in fee.  Approximately half of the compressor
stations and a limited number of town border and meter stations are also on land
owned in fee. The remaining major electric substations and compressor stations
and the majority of gas regulator stations and town border and meter stations
are wholly or partially on land leased from others or on or along public
highways or on streets or public places within incorporated towns and cities. 
The Company's Cabin Creek Pumped Storage Hydroelectric Generating Station, its
Shoshone Hydroelectric Generating Station and a portion of the related intake
tunnel are located on public lands of the United States.  As to substantially
all property on or across public lands of the United States, the Company or its
subsidiaries hold licenses or permits issued by appropriate Federal agencies or
departments.  The Leyden gas storage facility is located largely on leased
property under leases expiring December 31, 2040.  The Company and its utility
subsidiaries have the power of eminent domain pursuant to Colorado law to
acquire property for their electric and gas facilities.  The electric and gas
transmission and distribution facilities are for the most part located over or
under streets, public highways or other public places and on public lands under
franchises or other rights, and on land owned by the Company or others pursuant
to easements obtained from the record holders of title.  The water rights of the
Company and its subsidiaries are owned subject to divestment to the extent of
any abandonment thereof.  

    Substantially all of the utility plant and other physical property owned by
the Company and its utility subsidiaries is subject to the liens of the
respective indentures securing the mortgage bonds of the Company and its utility
subsidiaries.

ITEM 3.  LEGAL PROCEEDINGS

    See Note 9. Commitments and Contingencies in ITEM 8. FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

    Does not apply.














                                       20
<PAGE>

                                    PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

    The Company's common stock is listed on the New York, Chicago and Pacific 
Stock Exchanges.  The following table sets forth for the periods indicated 
the dividends declared per share of common stock and the high and low sale 
prices of the common stock on the consolidated tape as reported by THE WALL 
STREET JOURNAL.

                                       Dividends         Price Range
         Year and Quarter              Declared        High        Low
         ----------------              ---------     -------     -------
1996
    First Quarter....................   $.525        $36 1/2     $33 3/4
    Second Quarter...................    .525         36 3/4      32 3/8
    Third Quarter....................    .525         36 7/8      34 3/4
    Fourth Quarter...................    .525         39 1/2      35 1/4
                                        -----
                                        $2.10
1995
    First Quarter....................   $ .51        $31 1/2     $29    
    Second Quarter...................     .51         32 7/8      29 1/4
    Third Quarter....................     .51         34 1/2      30 5/8
    Fourth Quarter...................     .51         35 7/8      33 3/8
                                        -----
                                        $2.04

    At December 31, 1996, the book value of the common stock was $22.19 per 
share.  At February 21, 1997, there were 57,532 holders of record of the 
Company's common stock.  

    The dividend level is dependent upon the Company's results of operations, 
financial position and other factors and is evaluated quarterly by the Board 
of Directors. See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL 
CONDITION AND RESULTS OF OPERATIONS.

    On February 26, 1991, the Company's Board of Directors declared a 
dividend of one common share purchase right ("right") on each outstanding 
share of the Company's common stock.  All future common shares issued will 
contain this right.  Each right stipulates an initial purchase price of $55 
per share and also prescribes a means whereby the resulting effect is such 
that, under the circumstances described below, shareholders would be entitled 
to purchase additional shares of common stock at 50% of the prevailing market 
price at the time of exercise.  The rights are not currently exercisable, but 
would become exercisable if certain events occurred related to a person or 
group acquiring or attempting to acquire 20% or more of the outstanding 
shares of common stock of the Company. On August 22, 1995, in connection with 
the proposed merger (see Note 3. Merger in Item 8. FINANCIAL STATEMENTS AND 
SUPPLEMENTARY DATA), the Company's Rights Agreement was amended to provide 
that NCE will not be deemed an "Acquiring Person" as a result of the 
execution, delivery, and performance of the Merger Agreement.

    In the event a takeover results in the Company being merged into an 
acquiror, the unexercised rights could be used to purchase shares in the 
acquiror at 50% of market price.  Subject to certain conditions, if a person 
or group acquires at least 20% but no more than 50% of the Company's common 
stock, the Company's Board of Directors may exchange each right held by 
shareholders other than the acquiring person or group for one share of common 
stock (or its equivalent).

    If a person or group successfully acquires 80% of the Company's common 
stock for cash, after tendering for all of the common stock, and satisfies 
certain other conditions, the rights would not operate.  The rights expire on 
March 22, 2001; however, each right may be redeemed by the Board of Directors 
for one cent at any time prior to the acquisition of 20% of the common stock 
by a potential acquiror.  For a description of the rights and their terms see 
the Company's Rights Agreement, as amended, which is an exhibit to this Form 
10-K.



                                       21
<PAGE>

ITEM 6.  SELECTED FINANCIAL DATA

    The following selected consolidated financial data of the Company and its 
subsidiaries for each of the five years in the period ended December 31, 1996 
should be read in conjunction with the consolidated financial statements and 
the management's discussion and analysis of financial condition and results 
of operations appearing elsewhere herein.

<TABLE>
<CAPTION>
                                                                                    YEAR ENDED DECEMBER 31,
                                                            ----------------------------------------------------------------------
                                                               1996           1995           1994           1993           1992 
                                                            ----------     ----------     ----------     ----------     ----------
                                                                        (IN THOUSANDS-EXCEPT PER SHARE DATA & RATIOS)
<S>                                                         <C>            <C>            <C>            <C>            <C>
Operating revenues:
  Electric...............................................   $1,488,990     $1,449,096     $1,399,836     $1,337,053     $1,260,769
  Gas....................................................      640,497        624,585        624,922        628,324        568,886
  Other..................................................       41,899         36,920         32,626         33,308         32,618
                                                            ----------     ----------     ----------     ----------     ----------
       Total.............................................    2,171,386      2,110,601      2,057,384      1,998,685      1,862,273
Total operating expenses.................................    1,812,902      1,784,784      1,786,592      1,717,752      1,612,646
Operating income.........................................      358,484        325,817        270,792        280,933        249,627
Total interest charges...................................      149,880        143,906        132,134        130,337        121,116
Net income...............................................      190,346        178,856        170,269        157,360        136,623
Dividend requirements on preferred stock.................       11,848         11,963         12,014         12,031         12,077
Earnings available for common stock......................      178,498        166,893        158,255        145,329        124,546
Per share data applicable to common stock (a):
  Earnings...............................................   $     2.78     $     2.65     $     2.57     $     2.43     $     2.16
  Dividends declared.....................................   $     2.10     $     2.04     $     2.00     $     2.00     $     2.00
Shares of common stock outstanding:
  Weighted average.......................................       64,187         62,932         61,547         59,695         57,558
  Year-end...............................................       64,819         63,358         62,155         60,457         58,477
Rate of return earned on average common equity 
  (net to common)........................................        12.8%          12.8%          12.9%          12.7%          11.7%
Ratio of earnings to fixed charges (b)...................         2.75           2.78           2.53           2.54           2.43
Total assets.............................................   $4,572,648     $4,351,789     $4,207,832     $4,057,600     $3,759,583
Total net plant..........................................    3,598,895      3,480,712      3,291,402      3,193,136      3,077,509
Total construction expenditures..........................      321,162        285,516        317,138        293,515        261,666
AFDC.....................................................        4,101          7,095          7,158         12,667         11,302
Cash generated internally as a percent of 
  construction expenditures (c)..........................        56.9%          87.4%          35.4%          52.2%          57.5%
Total common equity......................................   $1,438,288     $1,343,645     $1,267,482     $1,184,183     $1,101,047
Preferred stock:
  Not subject to mandatory redemption....................      140,008        140,008        140,008        140,008        140,008
  Subject to mandatory redemption at par 
    (including amounts due within one year)..............       42,489         43,865         45,241         45,454         45,654
Long-term debt (including amounts due within one year)...    1,414,558      1,278,389      1,180,580      1,193,668      1,199,779
Notes payable & commercial paper.........................      244,725        288,050        324,800        276,875        250,626
</TABLE>

-------------------------
(a)  Earnings per share are based on the weighted average number of shares
     of common stock outstanding.
(b)  See Exhibit 12(a) herein.
(c)  Calculated as cash provided by operations net of cash used for dividends,
     divided by construction expenditures net of AFDC equity-component.




                                       22

<PAGE>

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS

INDUSTRY OUTLOOK

    Fundamental changes continue to occur throughout the electric utility 
industry as it moves toward deregulation with customer choice and increased 
competition.  Regulatory actions at both the federal and state level have 
opened up the wholesale, and to a lessor extent retail, markets to more 
competition. The FERC issued new rules in early 1996 requiring utilities to 
provide wholesale open-access transmission services and allowing for recovery 
of stranded investment costs.  A few states with above-average electric 
energy prices are aggressively pursuing full competition in the electric 
industry.  Some states currently have pilot plans in place to allow retail 
customers to select their energy supplier.  Federal legislation related to 
deregulation of the electric utility industry was introduced in 1996 and 
broad support for restructuring legislation is developing.  In addition, the 
reform or repeal of PUHCA, the law which regulates the ownership and 
operation of public utility holding companies, is expected to be given 
serious consideration in 1997 by Congress.  Utilities are responding to 
increased competition.  Mergers, acquisitions and corporate restructurings 
have continued to occur nationally and globally as companies strive to 
position themselves for the future, achieving economies of scale and 
increases in productivity and efficiency.

    Electric prices in Colorado are relatively low in comparison to other 
parts of the country, lessening the need for immediate change in the state's 
electric industry.  In 1996, the CPUC performed a comprehensive survey on 
electric industry restructuring.  The report issued by the CPUC is not 
conclusive on what the next steps should be.  Clearly, the issues are complex 
and controversial with significant consequences to the Company's securities 
holders.  The Company supports the need for change and believes that Colorado 
must take the time to study and learn from the restructuring models developed 
in other states to determine which aspects of those programs may be 
appropriate, and to identify other specific regional issues that need to be 
addressed.  The Company's response to the survey included a proposal that the 
CPUC undertake a comprehensive study of these complex issues, which would 
provide the necessary foundation of information for consideration by the 
state legislature.

CORPORATE OVERVIEW

    Significant progress on the Merger of the Company with SPS was achieved 
in 1996 and early 1997. Shareholder approvals were received in January 1996 
and required authorizations were obtained from all state utility regulators.  
Final approvals and filings are in progress with completion of the merger 
anticipated in the spring of 1997.  The Merger will permit the Company to 
derive benefits from the more efficient and economic utilization of combined 
facilities and personnel.  With a larger and more geographically diverse 
combined service territory, the business risks related to changes in 
economic, competitive or climatic conditions will be reduced.  In addition, 
purchasing savings, increased economical use of generation capacity and 
reduced administrative costs are anticipated.  Merger transition plans have 
been developed to begin realizing synergy savings upon consummation of the 
Merger, although the savings expected for 1997 will be reduced somewhat by 
various Merger related costs, including those related to planned workforce 
reductions.

    Operating priorities in 1996 continued to focus on reducing costs and 
developing new business opportunities.  Positive earnings reflected the 
continued cost containment efforts initiated in 1994.  The performance based 
regulatory plan approved by the CPUC resulted in a sharing arrangement 
between customers and shareholders of electric department earnings in excess 
of 11% for the years 1997-2001, a 50%/50% sharing of certain fuel and energy 
cost increases or decreases and a QSP which provides for penalties if certain 
performance measures relating to electric reliability, customer complaints 
and telephone response to inquiries are not met.  The Company anticipates 
that a reward structure for performance above certain standards will be 
implemented in the near term.

    In line with the Company's strategic focus on expanding market share and 
value, e prime received authorization from the FERC to act as a power 
marketer and is now marketing wholesale electricity.  In September 1996, e 
prime acquired TOG, a gas marketing company which serves 1,400 industrial and 
commercial customers in the eastern U.S.  In line with customer retention, 
the Company and one of its largest wholesale customers entered into a new 
purchase power agreement in which the Company provides power through the year 

                                      23
<PAGE>
                                       
2001.  This wholesale customer had previously notified the Company of its 
intent to reduce firm and peaking power purchases beginning in 1998.  The 
Company continues to look for opportunities to expand its customer base as 
both a natural gas and electric energy provider and to advance its strategy 
to focus on customer needs, while building a national presence in the 
marketplace.

    The regulatory environment within Colorado is a primary focus for the 
Company and the successful merger with SPS will likely have long-term effects 
on the Company's future financial performance. The Company strongly believes 
that all potentially stranded costs resulting from changes in laws or 
regulation should be recoverable.  Additionally, the Company believes that it 
will continue to be subject to rate regulation that will allow for the 
recovery of all of its deferred costs.  To the extent the Company concludes 
in the future that such recovery is no longer probable, the Company may be 
required to recognize as expense, at a minimum, all deferred costs currently 
recognized as regulatory assets on the consolidated balance sheet. (See Note 
1. Summary of Significant Accounting Policies in Item 8. FINANCIAL STATEMENTS 
AND SUPPLEMENTARY DATA).


RECENT DEVELOPMENTS

    On February 24, 1997, the Company and AEP jointly announced that they have 
reached agreement with the board of directors of Yorkshire Electricity, a UK 
regional electricity company, on the terms of a recommended cash tender offer 
for all of the outstanding and to be issued ordinary shares of Yorkshire 
Electricity.  The Company and AEP, through a joint venture named Yorkshire 
Holdings, are offering the equivalent of US $15.02 (9.27 pounds) per ordinary 
share, for a total purchase price of approximately US $2.4 billion (1.5 
billion pounds).  The boards of directors of  the Company and AEP have 
approved the transaction.  The board of directors of Yorkshire Electricity 
has agreed to recommend the offer to Yorkshire Electricity's shareholders.  
The offer will be made through Yorkshire Holdings, a wholly-owned subsidiary 
of Yorkshire Power,  a newly formed UK corporation owned equally by the 
Company  and AEP.  The Company will make its investment through New Century
International, Inc., a wholly-owned subsidiary of the Company.  If the 
Proposed Acquisition is completed, the Company would have an indirect 50% 
ownership interest in Yorkshire Electricity, which would be accounted for 
using the equity method of accounting.  Consummation of the Proposed 
Acquisition is subject to customary conditions in the UK, including 
regulatory clearance and acceptance of the offer by holders of at least 90% 
of the outstanding shares of Yorkshire Electricity.  Yorkshire Holdings may 
waive the latter condition when it has received acceptances of its offer and 
has otherwise acquired shares which in total represent more than 50% of the 
outstanding shares of Yorkshire Electricity.  The Company cannot predict at 
this time whether or not these conditions will be met or waived.

    The Proposed Acquisition will be financed by Yorkshire Power through a 
combination of approximately 25% equity and 75% debt, including the 
assumption of the existing debt of Yorkshire Electricity.  The funds for the 
Proposed Acquisition will be obtained from the Company's  and AEP's 
investment in Yorkshire Power of approximately US $360 million (220 million 
pounds) each, with the remainder to be obtained by Yorkshire Power through 
the issuance of non-recourse debt.  Yorkshire Power will, in turn, fund 
Yorkshire Holdings for the purpose of the Proposed Acquisition.  The Company 
intends initially to use debt to fund its entire equity investment in 
Yorkshire Power, including the issuance of US $250 million of its secured 
medium-term notes with varying maturities and drawings of US $110  million on 
its short-term lines of credit. It is currently anticipated that the 
Company's entire equity investment in Yorkshire Power will be refinanced 
through the issuance of common equity at the NCE level within six to eighteen 
months from the date of consummation of the Proposed Acquisition.

    According to Yorkshire Electricity's 1996 Annual Report and Accounts, 
Yorkshire Electricity's principal activities are the distribution of 
electricity to 2.1 million industrial, commercial, agricultural and domestic 
customers in its authorized area, which covers 4,180 square miles of 
northeast England.  Yorkshire Electricity  is also active in electricity 
supply and generation and the supply of natural gas, including the ownership 
of gas assets.  Other activities include the development of 
telecommunications services and the construction and operation of windfarms.  
For the fiscal year ended March 31, 1996, Yorkshire Electricity reported a 
consolidated profit on ordinary activities before taxation and exceptional 
items of US $310.8 million (199.2 million pounds) on revenues of US $2.2 
billion (1.4 billion pounds), had  reported total  assets at that date of US 
$2.2 billion (1.4 billion pounds), and reported net assets at that date of US 
$818.9 million (521.1 million pounds). 

                                       24
<PAGE>

    The SEC, in an order issued on February 19, 1997 under section 3(b) of 
PUHCA, exempted Yorkshire Electricity from all provisions of PUHCA that would 
be applicable to it as a subsidiary of the Company.  In connection with its 
application for such order, the Company also requested and obtained  a 
no-action letter from the Division of Investment Management of the Office of 
Public Utility Regulation of the SEC stating that, as long as the Merger is 
completed by September 30, 1997, it will not recommend any enforcement action 
with respect to the possible effect of the Proposed Acquisition on the 
Company's existing section 3(a)(2) exemption under PUHCA.  In seeking the 
section 3(b) exemption for Yorkshire Electricity, the Company informed the 
SEC that its investment in Yorkshire Electricity would be less than 50% of 
the Company's and SPS's combined retained earnings as of September 30, 1996, 
consistent with the requirements of Rule 53 under PUHCA.  The Company also 
informed the SEC in its application for a section 3(b) exemption that upon 
completion of the Merger, NCE would hold the proposed investment in Yorkshire 
Power through a separate subsidiary and not through the Company.  At that 
time, Yorkshire Electricity would be qualified as a foreign utility company 
under section 33 of PUHCA.

    See Note 4. Acquisition and Divestiture of Investments - Proposed 
Acquisition of Yorkshire Electricity in Item 8. FINANCIAL STATEMENTS AND 
SUPPLEMENTARY DATA.


EARNINGS

    Earnings per share were $2.78, $2.65 and $2.57 during 1996, 1995 and 
1994, respectively.  The improved earnings in both 1996 and 1995 are 
primarily attributable to increased electric and gas margins resulting from 
higher sales and lower operating and maintenance expenses resulting from the 
Company's cost containment efforts.  In addition, earnings in 1996 were 
favorably impacted by 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 8. FINANCIAL STATEMENTS AND 
SUPPLEMENTARY DATA).


ELECTRIC OPERATIONS

    The following table details the annual change in electric operating 
revenues and energy costs as compared to the preceding year:

                                                            INCREASE (DECREASE)
                                                             FROM PRIOR YEARS
                                                            1996         1995
                                                          --------     --------
                                                          (THOUSANDS OF DOLLARS)
Electric operating revenues:
  Retail...............................................   $ 43,478     $ 63,407
  Wholesale............................................     13,770       (5,724)
  Other (including unbilled revenues)..................    (17,354)      (8,423)
                                                          --------     --------
    Total revenues.....................................     39,894       49,260
Fuel used in generation................................     13,447      (16,123)
Purchased power........................................      8,470       44,871
                                                          --------     --------
Net increase in electric margin........................   $ 17,977     $ 20,512
                                                          --------     --------
                                                          --------     --------

                                       25
<PAGE>

The following table summarizes electric sales by major customer classes:

                                               MILLIONS OF         % CHANGE *
                                                KWH SALES       FROM PRIOR YEARS
                                            ----------------    ----------------
                                             1996      1995      1996      1995
                                            ------    ------    ------    ------
Residential.............................     6,607     6,282      5.2%     2.6%
Commercial and Industrial...............    15,672    15,032      4.3      2.5
Public Authority........................       200       189      6.2      0.2
                                            ------    ------
    Total Retail........................    22,479    21,503      4.5      2.6
Wholesale...............................     3,780     2,927     29.1     (3.8)
                                            ------    ------
    Total...............................    26,259    24,430      7.5      1.8
                                            ------    ------
                                            ------    ------

* Percentages are calculated using unrounded amounts.

    Electric operating revenues increased in 1996, when compared to 1995, 
primarily due to an overall 4.5% increase in retail sales resulting primarily 
from customer growth of 2.3%.  The increase in wholesale revenues was due to 
higher economy sales by the Company and power marketing activities of 
non-regulated subsidiaries. However, these additional sales contributed 
little to the increase in electric margin.  Electric operating revenues 
increased in 1995, when compared to 1994, primarily due to higher retail 
sales resulting from customer growth and additional revenues related to 
collection of QF purchased power capacity costs.  Wholesale revenues 
decreased in 1995, as compared to 1994, as a result of lower wholesale Kwh 
sales.  The demand for wholesale energy during 1995 was negatively impacted 
by an available supply of low-cost non-firm energy in the region.

    The Company and Cheyenne currently have cost adjustment mechanisms which 
recognize the majority of the effects of changes in fuel used in generation 
and purchased power costs and allow recovery of such costs on a timely basis. 
As a result, the changes in revenues associated with these mechanisms in 
1996 and 1995, when compared to the respective preceding year, had little 
impact on net income.  However, as discussed in Note 9. Commitments and 
Contingencies -Regulatory Matters - Merger Rate Filings in Item 8. FINANCIAL 
STATEMENTS AND SUPPLEMENTARY DATA, in its decision on the Merger, the CPUC 
modified and replaced the Company's ECA with an ICA, effective October 1, 
1996, which allows for a 50%/50% sharing of certain fuel and energy cost 
increases and decreases among customers and shareholders.  The change did not 
significantly impact the cost recoveries for 1996.

    Fuel used in generation expense increased $13.4 million in 1996, when 
compared to 1995, primarily due to higher generation levels.  Fuel used in 
generation expense decreased $16.1 million during 1995, as compared to the 
prior year, primarily due to lower coal and coal transportation costs from 
the renegotiation of certain contracts as generation levels were about the 
same for both years.

    Purchased power expense increased slightly in 1996 primarily due to 
purchases in connection with the non-regulated power marketing sales.  
Purchased power expense increased 10.3% in 1995, as compared to 1994, 
primarily due to increased purchases from QFs as mandated by the CPUC.  
Electric energy purchased from QFs is over 50% higher per Kwh than that 
purchased from other suppliers.

                                       26
<PAGE>

GAS OPERATIONS

    The following table details the annual change in revenues from gas sales 
and gas purchased for resale as compared to the preceding year:

                                                            INCREASE (DECREASE)
                                                             FROM PRIOR YEARS
                                                            1996         1995
                                                          --------     --------
                                                          (THOUSANDS OF DOLLARS)
Revenues from gas sales................................     11,211       7,281
Gas purchased for resale...............................        483      (5,197)
                                                           -------     -------
  Net increase in gas sales margin.....................    $10,728     $12,478
                                                           -------     -------
                                                           -------     -------

The following table summarizes gas deliveries by major customer classes:

                                               MILLIONS OF         % CHANGE *
                                             DTH DELIVERIES     FROM PRIOR YEARS
                                            ----------------    ----------------
                                             1996      1995      1996      1995
                                            ------    ------    ------    ------
Residential.............................      86.1      82.2      4.8%     5.4%
Commercial..............................      50.1      50.5     (0.7)     3.6
Wholesale...............................       1.6       0.3      **     (38.0)
Non-regulated gas marketing.............      21.8       0.2      **       **
                                            ------    ------
    Total Sales.........................     159.6     133.2     19.8      4.8
Transportation, gathering and 
  processing............................      91.4      77.1     18.6    (15.8)
                                            ------    ------
    Total...............................     251.0     210.3     19.4     (3.8)
                                            ------    ------
                                            ------    ------

* Percentages are calculated using unrounded amounts.
**Percentage change is significant, but presentation of the amount is 
  not meaningful.
    Gas sales margin increased in 1996, when compared to 1995, primarily due 
to higher retail gas sales resulting from customer growth of 3.4% and 
slightly colder weather.  Increased gas marketing activities by non-regulated 
subsidiaries favorably impacted gas sales margin in 1996.  Gas sales margin 
increased in 1995, as compared to 1994, primarily due to higher retail gas 
sales resulting from colder weather and moderate customer growth; there were 
approximately 17% more heating degree days in 1995 than in 1994.

    Gas transportation, gathering and processing revenues increased $4.7 
million in 1996, as compared to 1995, primarily due to an increase in 
transport deliveries resulting from the shifting of various Company 
commercial customers to firm transport customers which accelerated in October 
1995 with the implementation of new gas rates.  Transportation, gathering and 
processing revenues decreased $7.6 million in 1995 primarily due to the sale 
of WGG in August 1994 (See Note 4. Acquisition and Divestiture of Investments 
in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).

    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 1996 and 1995, when compared to the respective preceding 
year, had little impact on net income. However, the fluctuations in gas sales 
impact the amount of gas the Company must purchase and, therefore, along with 
increases and decreases in the per-unit cost of gas, affect total gas 
purchased for resale. In 1996, the increase in the quantity of gas purchased 
was offset substantially by the lower per unit average cost of gas for the 
year.  The $5.2 million decrease in gas purchased for resale for 1995 is 
primarily due to lower per unit cost of gas offset, in part, by a slight 
increase in gas purchases.

NON-FUEL OPERATING EXPENSES

    Other operating and maintenance expenses decreased $10.1 million during 
1996 as compared to 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 (See Note 2. Fort 
St. Vrain. in Item 8. FINANCIAL 

                                       27
<PAGE>

STATEMENTS AND SUPPLEMENTARY DATA), lower labor and employee benefit costs 
resulting from the hiring freeze instituted in August 1995 and other general 
cost reductions resulting from the Company's cost containment efforts.  These 
reductions were offset, in part, by higher operating costs from non-regulated 
operations that were, for the most part, initiated during 1996.

    Other operating and maintenance expenses decreased $26.1 million in 1995, 
as compared to 1994, primarily due to lower labor and employee benefit costs 
resulting from the Company's cost containment efforts which included the 
restructuring and downsizing accomplished in 1994 (approximately a $26 
million reduction) and the recognition of approximately $8.7 million of 
involuntary severance costs in 1994.  This restructuring and downsizing was 
completed in two phases: 1) effective April 1, 1994, the Company reduced its 
workforce by approximately 550 employees through an early 
retirement/severance program, and 2) during the last six months of 1994, the 
Company eliminated approximately 550 management and staff level positions in 
connection with an internal restructuring and involuntary severance program.  
These decreases in 1995 were offset, in part, by the $2.5 million write-off 
of software costs due to the cancellation of a materials management project, 
three months of additional amortization of the early retirement/severance 
program costs totaling $2.2 million and $2.2 million of additional repair 
costs associated with an early winter snow storm.

    During 1994, the Company recognized additional expenses aggregating 
approximately $43.4 million for increased costs associated with the defueling 
and decommissioning of Fort St. Vrain and the impairment of certain Fort St. 
Vrain related property and inventory.  The additional expense was primarily 
associated with radiation levels in the reactor core being higher than 
originally anticipated and increased uncertainty related to spent fuel 
disposal issues (See Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS 
AND SUPPLEMENTARY DATA).

    Depreciation and amortization expense increased $13.3 million in 1996 and 
$2.3 million in 1995 primarily due to higher depreciation expense from 
property additions and amortization of software costs.

    Taxes (other than income taxes) decreased $5.1 million in 1995 primarily 
due to lower payroll related taxes resulting from the 1994 downsizing.

    Income taxes increased $1.0 million in 1996, as compared to 1995, 
primarily due to higher pre-tax income, offset, in part, by the write-off of 
additional investment tax credits for retired property and additional tax 
benefits at PSRI. The $46.9 million increase in income taxes during 1995, as 
compared to 1994, is primarily due to higher pre-tax income and the effects 
of two items recorded in 1994 which served to lower tax expense during that 
period.  These items included: 1) an adjustment associated with the adoption 
of full normalization which was provided for in a CPUC rate order 
(approximately $21.3 million), and 2) the true-up of the tax accrual related 
to the filing of the 1993 tax return (approximately $5.1 million).

    Other income and deductions decreased $15.2 million during 1996, as 
compared to the preceding year, primarily due to higher costs related to the 
Merger ($3.1 million), the recognition of $4.1 million of certain severance 
costs, the recognition of $2.3 million of costs associated with the 
settlement of environmental issues related to the operations of the Hayden 
station and a decrease in the allowance for equity funds used during 
construction.  Other income and deductions decreased $34.7 million in 1995 
primarily due to the net effects of the pre-tax gain of approximately $34.5 
million recognized on the sale of WGG in 1994 (See Note 4. Acquisition and 
Divestiture of Investments in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY 
DATA) and $4.0 million of costs related to the Merger (See Note 3. Merger in 
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA), offset, in part, by the 
1994 reversal of the $3.0 million gas search award, as the Colorado Supreme 
Court reversed the incentive award previously granted by the CPUC.

    Interest charges increased $6.0 million during 1996, as compared to 1995. 
Higher interest on long-term debt resulted from the financing of capital 
expenditures.  Interest charges increased $11.8 million during 1995 as 
compared to 1994.  Other interest increased due to higher interest rates and 
an increased level of short-term borrowings in 1995, the recognition of 
interest costs related to the over-collection of expenses under the Company's 
cost adjustment mechanisms and higher interest on COLI contracts, while the 
net costs associated with long-term debt decreased slightly.

                                       28
<PAGE>

FINANCIAL POSITION

    Accounts receivable increased at December 31, 1996, as compared to 1995, 
primarily due to overall sales growth, including marketing activities by 
non-regulated subsidiaries, and the fact that a portion of the gas refund 
made late in 1995 was applied directly to customers' accounts, which served 
to lower the accounts receivable balance at December 31, 1995.  Accounts 
payable increased primarily due to the Company's higher gas costs at the end 
of 1996 and increased activities by non-regulated subsidiaries.

    The $38.5 million decrease in the defueling and decommissioning liability 
was due to expenditures during 1996.  This decrease and the increase in 
noncurrent investments and receivables were also affected by the February 9, 
1996 settlement agreement with the DOE resolving all spent nuclear fuel 
storage and disposal issues at Fort St. Vrain.  Customers' advances for 
construction decreased by approximately $49.3 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.

COMMITMENTS AND CONTINGENCIES

    Issues relating to regulatory and environmental matters are discussed in 
Note 9. Commitments and Contingencies in Item 8. FINANCIAL STATEMENTS AND 
SUPPLEMENTARY DATA.  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.  This 
follows the 1995 first quarter increase in the quarterly dividend on its 
common stock from $0.50 per share to $0.51 per share.  The Company's common 
stock dividend level is dependent upon the Company's results of operations, 
financial position, cash flow 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

                                                  1996        1995        1994
                                                -------     -------     -------
Net cash provided by operating activities 
  (IN MILLIONS)..............................   $ 327.6     $ 385.7     $ 245.7

    Net cash provided by operating activities decreased $58.1 million in 1996 
primarily due to the undercollection of purchased gas and electric energy 
costs ($40.8 million) and lower cash receipts because of a gas refund that 
was applied directly to customers' accounts in late 1995.  Higher earnings 
and lower decommissioning and defueling expenditures positively impacted 
operating cash flows for both 1996 and 1995.  The increase in 1995 was also 
significantly impacted by the overcollection of purchased gas and electric 
costs.

    At December 31, 1996, the Company's decommissioning liability, excluding 
defueling, was approximately $6.6 million.  The remaining expenditures 
related to this obligation are expected to be incurred over the next year.  
The annual decommissioning amount being recovered from customers is 
approximately $13.9 million which will continue through June 2005.  At 
December 31, 1996, approximately $89.7 million remains to be collected from 
customers and is reflected as a regulatory asset on the consolidated balance 
sheet.

                                                  1996        1995        1994
                                                -------     -------     -------
Net cash used in investing activities 
  (IN MILLIONS)..............................   $(307.1)    $(284.6)    $(177.4)

    Net cash used in investing activities, which substantially consisted of 
construction expenditures, was higher in both 1996 and 1995, compared to the 
respective prior years.  Proceeds from the sale of WGG in 1994 

                                       29
<PAGE>

and the sale of certain Fuelco properties in 1994 and 1996 reduced the net 
cash used in investing activities (See Note 4. Acquisition and Divestiture of 
Investments in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).

                                                  1996        1995        1994
                                                -------     -------     -------
Net cash used in financing activities 
  (IN MILLIONS)..............................   $ (25.8)    $ (92.3)    $ (80.5)

    Net cash used in financing activities decreased (indicating that there 
were more borrowings) significantly in 1996 primarily due to the issuance of 
additional long-term debt, including the $125 million First Collateral Trust 
Bonds in May 1996 and $75 million in medium-term notes in November 1996.  The 
proceeds were used to fund the Company's construction program, for other 
general corporate purposes and to repay short-term indebtedness incurred for 
such purposes.  Cash used in financing activities increased slightly in 1995 
over 1994. Proceeds from the sale of common stock under the Company's 
dividend reinvestment and stock purchase plan decreased in 1995.  Long-term 
debt refinancing activity also decreased in 1995, as compared to 1994, as a 
result of higher interest rates.  The use of short-term borrowing over the 
last several years has increased slightly, however, short-term borrowing 
levels were reduced in late 1995 with an issuance of $80 million of 
medium-term notes by PSCCC. 

PROSPECTIVE CAPITAL REQUIREMENTS

    At December 31, 1996, the Company and its subsidiaries estimated cost of 
their construction programs and other capital requirements for the years 
1997, 1998 and 1999 are shown in the table below:

                                              1997        1998        1999 
                                            --------    --------    --------
Company:                                         (THOUSANDS OF DOLLARS)
Electric
  Production*.............................  $ 95,056    $103,211    $125,505
  Transmission............................    39,600      48,433      22,718
  Distribution............................    68,944      70,426      68,090
Gas.......................................    62,991      88,240      56,172
General**.................................    53,440      59,186      21,137
                                            --------    --------    --------
    Total Company.........................   320,031     369,496     293,622
Subsidiaries..............................     7,015       6,243       6,075
                                            --------    --------    --------
    Total construction expenditures.......   327,046     375,739     299,697
Less: AFDC................................     5,640       5,000       6,113
Add: Sinking funds and debt maturities 
  and refinancings........................   157,851      72,901     120,957
Add: Fort St. Vrain decommissioning.......     2,500           -           -
                                            --------    --------    --------
    Total capital requirements............  $493,037    $453,640    $426,767
                                            --------    --------    --------
                                            --------    --------    --------

* Capital requirements for Electric Production include approximately $121
  million for Fort St. Vrain repowering and approximately $70 million for
  pollution control equipment at Hayden.

**Capital requirements in the "General" category include assets leased 
  under a leasing program.  The 1997 and 1998 amounts include approximately 
  $40 million of expenditures for automated electric and gas meter reading
  equipment.

    The construction programs of the Company and its subsidiaries are subject 
to continuing review and modification.  In particular, actual construction 
expenditures may vary from the estimates due to changes in the electric 
system projected load growth, the desired reserve margin and the availability 
of purchased power, as well as alternative plans for meeting the Company's 
long-term energy needs.  In addition, the proposed merger with SPS, the 
Company's ongoing evaluation of merger, acquisition and divestiture 
opportunities to support corporate strategies, and future requirements to 
install pollution control equipment may impact actual capital requirements 
(See Note 3. Merger, Note 4. Acquisition and Divestiture of Investments and 
Note 9. Commitments and Contingencies - Environmental Issues in Item 8. 
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).


                                       30

<PAGE>

CAPITAL SOURCES

    At December 31, 1996, the Company and its subsidiaries estimated that 
their 1997-1999 capital requirements will be met principally with a 
combination of funds from external sources and funds from operations.  The 
Company and its subsidiaries may meet their external capital requirements 
through the issuance of first collateral trust bonds, preferred and/or common 
stock, by increasing the level of borrowing under PSCCC's medium-term note 
program or through the issuance of commercial paper or through short-term 
borrowing under committed and uncommitted bank borrowing arrangements 
discussed below.  The financing needs are subject to continuing review and 
can change depending on market and business conditions and changes, if any, 
in the construction programs and other capital requirements of the Company 
and its subsidiaries.


REGISTRATION STATEMENTS

    On August 30, 1995, the Company filed a registration statement with the 
SEC for the issuance of 3 million shares of common stock and 3 million rights 
to purchase common stock appurtenant thereto to be issued under the Company's 
Automatic Dividend Reinvestment and Common Stock Purchase Plan ("Dividend 
Reinvestment Plan") for the purpose of funding its construction program and 
other general corporate purposes.

The Dividend Reinvestment Plan allows its shareholders to purchase additional 
shares of the Company's common stock through the reinvestment of cash 
dividends and the purchase of additional shares of common stock with optional 
cash payments.

    In 1994, the Company filed a registration statement with the SEC for the 
issuance of First Collateral Trust Bonds and cumulative preferred stock for 
the purpose of funding its construction program, refunding certain issues of 
its cumulative preferred stock and other general corporate purposes.  The 
aggregate principal amount of first collateral trust bonds, plus the 
aggregate par value of shares of cumulative preferred stock, will not exceed 
$306 million.  On May 31, 1996, the Company issued $125 million aggregate 
principal amount of its First Collateral Trust Bonds.

    On October 24, 1996, the Company filed a registration statement with the 
SEC for the issuance of $400 million aggregate principal amount of First 
Collateral Trust Bonds through one or more series of medium-term notes.  On 
November 13, 1996,  the Company established a $250 million Secured 
Medium-Term Note Program, Series B.  As of January 31, 1997, $150 million of 
the Series B medium-term notes had been issued.


COMPANY'S INDENTURES

    The Company's Indenture dated as of December 1, 1939 (the "1939 
Indenture"), which is a mortgage on the Company's electric and gas 
properties, permits the issuance of additional first mortgage bonds to the 
extent of 60% of the value of net additions to the Company's utility 
property, provided net earnings before depreciation, taxes on income and 
interest expense for a recent twelve month period are at least 2.5 times the 
annual interest requirements on all bonds to be outstanding.  The 1939 
Indenture also permits the issuance of additional bonds on the basis of 
retired first mortgage bonds, in some cases with no requirement to satisfy 
such net earnings test.  At December 31, 1996, the amount of net additions 
would permit (and the net earnings test would not prohibit) the issuance of 
approximately $365 million of new bonds (in addition to the $250 million 
principal amount of secured medium-term notes discussed above) at an assumed 
annual interest rate of 7.80%.  At December 31, 1996, the amount of retired 
bonds would permit the issuance of $718.2 million of new bonds.

    The Company's Indenture dated as of October 1, 1993 (the "1993 
Indenture") is a second mortgage on the Company's electric properties.  
Generally, so long as the Company's 1939 Indenture remains in effect, first 
collateral trust bonds will be issued under the 1993 Indenture on the basis 
of the deposit with the trustee of an equal principal amount of first 
mortgage bonds issued under the 1939 Indenture.  If the bonds issued under 
the 1939 Indenture are to be issued on the basis of property additions, first 
collateral trust bonds may be issued under the 1993 Indenture only if net 
earnings before depreciation, taxes on income, interest expenses and 
non-recurring charges for a recent twelve-month period are at least 2 times 
annual interest requirements on all first mortgage 


                                       31

<PAGE>

bonds (other than bonds held by the trustee under the 1993 Indenture) and all 
first collateral trust bonds to be outstanding.  As of December 31, 1996, 
coverage under the net earnings test was 5.3 times such annual interest 
requirements.

COMPANY'S RESTATED ARTICLES OF INCORPORATION

    The Company's Restated Articles of Incorporation prohibit the issuance of 
additional preferred stock without preferred shareholder approval, unless the 
gross income available for the payment of interest charges for a recent 
twelve month period is at least 1.5 times the total of: 1) the annual 
interest requirements on all indebtedness to be outstanding for more than one 
year; and 2) the annual dividend requirements on all preferred stock to be 
outstanding. At December 31, 1996, gross income available under this 
requirement would permit the Company, if allowed under provisions of the 
Company's Restated Articles of Incorporation, to issue approximately $2.9 
billion of additional preferred stock at an assumed annual dividend rate of 
6.90%.  Coverage of gross income to interest charges was 6.22 at December 31, 
1996.

    The Company's Restated Articles of Incorporation prohibit, without 
preferred shareholder approval, the issuance or assumption of unsecured 
indebtedness, other than for refunding purposes, greater than 15% of the 
aggregate of: 1) the total principal amount of all bonds or other securities 
representing secured indebtedness of the Company, then outstanding; and 2) 
the total of the capital and surplus of the Company, as then recorded on its 
books. At December 31, 1996, the Company had outstanding unsecured 
indebtedness, including subsidiary indebtedness with the credit support of 
the Company, in the amount of $231.2 million.  The maximum amount permitted 
under this limitation was approximately $425.4 million at December 31, 1996.

SHORT TERM BORROWING ARRANGEMENTS

    The Company and certain subsidiaries have available committed and 
uncommitted lines of credit to meet their short-term cash requirements.  The 
Company, PSCCC, and certain subsidiaries have a credit facility with several 
banks which provides $300 million in committed bank lines of credit and is 
used primarily to support the issuance of commercial paper by the Company and 
PSCCC, and to provide for direct borrowings thereunder. Under the facility 
Cheyenne, 1480 Welton, Inc., Fuelco, e prime and PSRI are provided access to 
the credit facility with direct borrowings guaranteed by the Company.  At 
December 31, 1996, $55.3 million remained unused under this facility.  
Generally, the banks participating in the credit facility would have no 
obligation to continue their commitments if there has been a material adverse 
change in the consolidated financial condition, operations, business or 
otherwise that would prevent the Company and its subsidiaries from performing 
their obligation under the credit facility.  This facility expires on 
November 17, 2000.  Also, the Company has individual arrangements for 
uncommitted bank lines of credit which totaled $75 million, and all remained 
unused at December 31, 1996. These individual arrangements expire on December 
31, 1997.  The Company may borrow under uncommitted preapproved lines of 
credit upon request; however, the banks have no firm commitment to make such 
loans (see Note 8. Bank Lines of Credit and Compensating Bank Balances in 
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).

    PSCCC may periodically issue medium-term notes (in addition to the 
short-term debt discussed above) to supplement the financing/purchase of the 
Company's customer accounts receivable and fossil fuel inventories.  As of 
December 31, 1996, PSCCC had issued and had outstanding $100 million in 
medium-term notes. The level of financing of PSCCC is tied directly to daily 
changes in the level of the Company's outstanding customer accounts 
receivable and monthly changes in fossil fuel inventories, and will vary 
minimally from year to year although seasonal fluctuations in the level of 
assets will cause corresponding fluctuations in the level of associated 
financing.



                                      32
<PAGE>

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
                                       
            REPORT OF THE AUDIT COMMITTEE OF THE BOARD OF DIRECTORS

The Board of Directors of the Company addresses its oversight responsibility 
for the consolidated financial statements through its Audit Committee.  The 
Audit Committee meets regularly with the independent certified public 
accountants and the internal auditor to discuss results of their audit work 
and their evaluation of the adequacy of the internal controls and the quality 
of financial reporting.

In fulfilling its responsibilities in 1996, the Audit Committee recommended 
to the Board of Directors, subject to shareholder approval, the selection of 
the Company's independent certified public accountants.  The Audit Committee 
reviewed the overall scope and specific plans of the independent certified 
public accountants' and internal auditor's respective audit plans, and 
discussed the independent certified public accountants' management letter 
recommendations, approved their general audit fees, and reviewed their 
non-audit services to the Company.

The committee meetings are designed to facilitate open communications among 
Company management, internal auditing, independent certified public 
accountants, and the Audit Committee.  To ensure auditor independence, both 
the independent certified public accountants and internal auditor have full 
and free access to the Audit Committee.



J. Michael Powers, Chairman
Audit Committee

February 24, 1997










                                      33

<PAGE>

                             REPORT OF MANAGEMENT

The accompanying financial statements of Public Service Company of Colorado 
and subsidiaries have been prepared by Company personnel in conformity with 
generally accepted accounting principles consistent with the Uniform System 
of Accounts of the Federal Energy Regulatory Commission.  The integrity and 
objectivity of the data in these financial statements are the responsibility 
of management.  Financial information contained elsewhere in this Annual 
Report on Form 10-K is consistent with that in the financial statements.

The accompanying financial statements have been audited by Arthur Andersen 
LLP, independent public accountants.  Management has made available to Arthur 
Andersen LLP all the Company's and its subsidiaries' financial records and 
related data and has provided to them representations we believe to be valid 
and appropriate.

The Company maintains a system of internal control over financial reporting, 
including the safeguarding of assets against unauthorized acquisition, use or 
disposition, which is designed to provide reasonable assurance to the 
Company's management and Board of Directors regarding the preparation of 
reliable published financial statements and such asset safeguarding.  The 
system includes a documented organizational structure and division of 
responsibility, established policies and procedures including a code of 
conduct to foster a strong ethical climate, which are communicated throughout 
the Company, and the careful selection, training and development of our 
people.  Internal auditors monitor the operation of the internal control 
system and report findings and recommendations to management and the Audit 
Committee of the Board of Directors, and corrective actions are taken to 
address control deficiencies and other opportunities for improving the system 
as they are identified.  The board, operating through its Audit Committee, 
which is composed entirely of directors who are not officers or employees of 
the Company, provides oversight to the financial reporting process.

There are inherent limitations in the effectiveness of any system of internal 
control, including the possibility of human error and the circumvention or 
overriding of controls.  Accordingly, even an effective internal control 
system can provide only reasonable assurance with respect to financial 
statement preparation.  Further, because of changes in conditions, internal 
control system effectiveness may vary over time.

The Company assessed its internal control system as of December 31, 1996 in 
relation to criteria for effective internal control over financial reporting 
described in "Internal Control - Integrated Framework" issued by the 
Committee of Sponsoring Organizations of the Treadway Commission.  Based on 
the results of its assessment, the Company believes that, as of December 31, 
1996, the Company's system of internal control over external financial 
reporting, including the safeguarding of assets against unauthorized 
acquisition, use or disposition, met those criteria.



W. Wayne Brown                         Wayne H. Brunetti
Principal Accounting Officer           Chief Executive Officer

February 24, 1997



                                      34
<PAGE>

                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

TO PUBLIC SERVICE COMPANY OF COLORADO

We have audited the accompanying consolidated balance sheets of Public 
Service Company of Colorado (a Colorado corporation) and subsidiaries as of 
December 31, 1996 and 1995, and the related consolidated statements of 
income, shareholders' equity and cash flows for each of the three years in 
the period ended December 31, 1996.  These financial statements and the 
schedule referred to below are the responsibility of the Company's 
management.  Our responsibility is to express an opinion on these financial 
statements and schedule based on our audits.

We conducted our audits in accordance with generally accepted auditing 
standards.  Those standards require that we plan and perform the audit to 
obtain reasonable assurance about whether the financial statements are free 
of material misstatement.  An audit includes examining, on a test basis, 
evidence supporting the amounts and disclosures in the financial statements. 
An audit also includes assessing the accounting principles used and 
significant estimates made by management, as well as evaluating the overall 
financial statement presentation. We believe that our audits provide a 
reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in 
all material respects, the  financial position of Public Service Company of 
Colorado and subsidiaries as of December 31, 1996 and 1995, and the results 
of their operations and their cash flows for each of the three years in the 
period ended December 31, 1996, in conformity with generally accepted 
accounting principles.

As more fully discussed in Note 11 to the consolidated financial statements, 
effective January 1, 1994, the Company changed its method of accounting for 
postemployment benefits.

Our audits were made for the purpose of forming an opinion on the basic 
financial statements taken as a whole.  The schedule listed in the index of 
financial statements is presented for purposes of complying with the 
Securities and Exchange Commission's rules and is not part of the basic 
financial statements.  This schedule has been subjected to the auditing 
procedures applied in our audits of the basic financial statements and, in 
our opinion, fairly states in all material respects the financial data 
required to be set forth therein in relation to the basic financial 
statements taken as a whole. 

We have also audited, in accordance with generally accepted auditing 
standards, the consolidated balance sheets as of December 31, 1994, 1993 and 
1992 and the related consolidated statements of income, shareholders' equity 
and cash flows for each of the two years in the period ended December 31, 
1993, (none of which are presented herein) and have expressed an unqualified 
opinion on those financial statements.  In our opinion, the information set 
forth in the selected financial data for each of the five years in the period 
ended December 31, 1996 appearing in Item 6 of this Form 10-K, other than the 
ratios and percentages therein, is fairly stated, in all material respects, 
in relation to the financial statements from which it has been derived.



                                                             ARTHUR ANDERSEN LLP
Denver, Colorado
February 24, 1997



                                      35
<PAGE>

                       PUBLIC SERVICE COMPANY OF COLORADO
                               AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS
                            (THOUSANDS OF DOLLARS)
                          DECEMBER 31, 1996 AND 1995
                                       
                                    ASSETS


<TABLE>
                                                                 1996           1995
                                                              ----------     ----------
<S>                                                           <C>            <C>
Property, plant and equipment, at cost:
  Electric.................................................   $3,931,413     $3,751,321
  Gas......................................................    1,035,394        989,215
  Steam and other..........................................       78,225         88,446
  Common to all departments................................      418,262        380,809
  Construction in progress.................................      181,597        192,580
                                                              ----------     ----------
                                                               5,644,891      5,402,371
  Less: accumulated depreciation...........................    2,045,996      1,921,659
                                                              ----------     ----------
      Total property, plant and equipment..................    3,598,895      3,480,712
                                                              ----------     ----------



Investments, at cost, and receivables......................       46,550         21,776
                                                              ----------     ----------



Current assets:
  Cash and temporary cash investments......................        9,406         14,693
  Accounts receivable, less reserve for uncollectible 
    accounts ($4,049 at December 31, 1996; 
    $3,630 at December 31, 1995) (Schedule II).............      218,132        124,731
  Accrued unbilled revenues (Note 1).......................       85,894         96,989
  Recoverable purchased gas and electric energy costs - 
    net (Note 1)...........................................       31,288              -
  Materials and supplies, at average cost..................       48,972         56,525
  Fuel inventory, at average cost..........................       24,739         35,654
  Gas in underground storage, at cost (LIFO)...............       42,826         44,900
  Current portion of accumulated deferred income taxes 
    (Note 13)..............................................            -         19,229
  Regulatory assets recoverable within one year (Note 1)...       44,110         40,247
  Prepaid expenses and other...............................       41,790         35,619
                                                              ----------     ----------
      Total current assets.................................      547,157        468,587
                                                              ----------     ----------



Deferred charges:
  Regulatory assets (Note 1)...............................      304,456        321,797
  Unamortized debt expense.................................       10,975         10,460
  Other....................................................       64,615         48,457
                                                              ----------     ----------
      Total deferred charges...............................      380,046        380,714
                                                              ----------     ----------
                                                              $4,572,648     $4,351,789
                                                              ----------     ----------
                                                              ----------     ----------
</TABLE>

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



                                      36
<PAGE>

                      PUBLIC SERVICE COMPANY OF COLORADO
                               AND SUBSIDIARIES
                                       
                          CONSOLIDATED BALANCE SHEETS
                             (THOUSANDS OF DOLLARS)
                          DECEMBER 31, 1996 AND 1995
                                       
                           CAPITAL AND LIABILITIES


<TABLE>
                                                                 1996           1995
                                                              ----------     ----------
<S>                                                           <C>            <C>
Common stock (Note 5)......................................   $1,048,447     $  997,106
Retained earnings..........................................      389,841        346,539
                                                              ----------     ----------
      Total common equity..................................    1,438,288      1,343,645

Preferred stock (Note 5):
  Not subject to mandatory redemption......................      140,008        140,008
  Subject to mandatory redemption at par...................       39,913         41,289
Long-term debt (Note 6)....................................    1,259,528      1,195,553
                                                              ----------     ----------
                                                               2,877,737      2,720,495
                                                              ----------     ----------

Noncurrent liabilities:
  Employees' postretirement benefits other 
    than pensions (Note 11)................................       55,677         49,198
  Employees' postemployment benefits (Note 11).............       25,182         23,500
  Defueling and decommissioning liability (Note 2).........            -         23,115
                                                              ----------     ----------
      Total noncurrent liabilities.........................       80,859         95,813
                                                              ----------     ----------

Current liabilities:
  Notes payable and commercial paper (Note 7)..............      244,725        288,050
  Long-term debt due within one year.......................      155,030         82,836
  Preferred stock subject to mandatory redemption 
    within one year (Note 5)...............................        2,576          2,576
  Accounts payable.........................................      254,256        156,109
  Dividends payable........................................       36,973         35,284
  Recovered purchased gas and electric energy costs - 
    net (Note 1)...........................................            -          9,508
  Customers' deposits......................................       21,441         17,462
  Accrued taxes............................................       58,990         55,393
  Accrued interest.........................................       33,797         32,071
  Current portion of defueling and decommissioning 
    liability (Note 2).....................................        8,665         24,055
  Current portion of accumulated deferred income taxes 
    (Note 13)..............................................        4,560              -
  Other....................................................       69,203         78,451
                                                              ----------     ----------
      Total current liabilities............................      890,216        781,795
                                                              ----------     ----------

Deferred credits:
  Customers' advances for construction.....................       50,269         99,519
  Unamortized investment tax credits.......................      105,928        113,184
  Accumulated deferred income taxes (Note 13)..............      539,082        508,143
  Other....................................................       28,557         32,840
                                                              ----------     ----------
      Total deferred credits...............................      723,836        753,686

                                                              ----------     ----------
Commitments and contingencies (Note 9).....................   $4,572,648     $4,351,789
                                                              ----------     ----------
                                                              ----------     ----------
</TABLE>
                                       
          The accompanying notes to consolidated financial statements
              are an integral part of these financial statements.



                                      37

<PAGE>

                      PUBLIC SERVICE COMPANY OF COLORADO
                               AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF INCOME
                 (THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA)
                 YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994


<TABLE>
                                                          1996         1995         1994  
                                                       ----------   ----------   ----------
<S>                                                    <C>          <C>          <C>
Operating revenues:
  Electric..........................................   $1,488,990   $1,449,096   $1,399,836
  Gas...............................................      640,497      624,585      624,922
  Other.............................................       41,899       36,920       32,626
                                                       ----------   ----------   ----------
                                                        2,171,386    2,110,601    2,057,384

Operating expenses:
  Fuel used in generation...........................      195,442      181,995      198,118
  Purchased power...................................      490,428      481,958      437,087
  Gas purchased for resale..........................      393,163      392,680      397,877
  Other operating expenses..........................      336,100      346,026      369,094
  Maintenance.......................................       63,908       64,069       67,097
  Defueling and decommissioning (Note 2)............            -            -       43,376
  Depreciation and amortization.....................      154,631      141,380      139,035
  Taxes (other than income taxes)...................       82,899       81,319       86,408
  Income taxes (Note 13)............................       96,331       95,357       48,500
                                                       ----------   ----------   ----------
                                                        1,812,902    1,784,784    1,786,592
                                                       ----------   ----------   ----------
Operating income....................................      358,484      325,817      270,792
Other income and deductions:
  Allowance for equity funds used during 
    construction....................................          757        3,782        3,140
  Gain on sale of WestGas Gathering, Inc. 
    (Note 4)........................................            -            -       34,485
  Miscellaneous income and deductions - net 
    (Notes 1 and 3).................................      (19,015)      (6,837)      (6,014)
                                                       ----------   ----------   ----------
                                                          (18,258)      (3,055)      31,611

Interest charges:
  Interest on long-term debt........................       92,205       85,832       89,005
  Amortization of debt discount and expense 
    less premium....................................        3,621        3,278        3,126
  Other interest....................................       57,398       58,109       44,021
  Allowance for borrowed funds used during 
    construction....................................       (3,344)      (3,313)      (4,018)
                                                       ----------   ----------   ----------
                                                          149,880      143,906      132,134
                                                       ----------   ----------   ----------
Net income..........................................      190,346      178,856      170,269
Dividend requirements on preferred stock............       11,848       11,963       12,014
                                                       ----------   ----------   ----------
Earnings available for common stock.................   $  178,498   $  166,893   $  158,255
                                                       ----------   ----------   ----------
                                                       ----------   ----------   ----------
Shares of common stock outstanding (thousands):
     Year-end.......................................       64,819       63,358       62,155
                                                       ----------   ----------   ----------
                                                       ----------   ----------   ----------

     Weighted average...............................       64,187       62,932       61,547
                                                       ----------   ----------   ----------
                                                       ----------   ----------   ----------

Earnings per weighted average share of 
  common stock outstanding..........................   $     2.78   $     2.65   $     2.57
                                                       ----------   ----------   ----------
                                                       ----------   ----------   ----------
</TABLE>
                                       
          The accompanying notes to consolidated financial statements
              are an integral part of these financial statements.



                                      38
<PAGE>

                       PUBLIC SERVICE COMPANY OF COLORADO
                               AND SUBSIDIARIES

                CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
                (THOUSANDS OF DOLLARS, EXCEPT SHARE INFORMATION)
                  YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994


<TABLE>
                                       COMMON STOCK, $5 PAR VALUE   
                                       --------------------------   PREMIUM ON     RETAINED
                                           SHARES        AMOUNT    COMMON STOCK    EARNINGS        TOTAL
                                         ----------     ---------    --------     ---------     ----------
<S>                                      <C>            <C>          <C>          <C>           <C>
Balance at December 31, 1993..........   60,457,375     $302,287     $608,561     $ 273,335     $1,184,183
Net income............................            -            -            -       170,269        170,269
Dividends declared
  Common stock, $2.00 per share.......            -            -            -      (123,379)      (123,379)
  Preferred stock, $100 par value.....            -            -            -        (9,071)        (9,071)
  Preferred stock, $25 par value......            -            -            -        (2,940)        (2,940)
Issuance of common stock
  Employees' Savings Plan.............      334,223        1,671        8,439             -         10,110
  Dividend Reinvestment Plan..........    1,355,104        6,775       31,308             -         38,083
  Omnibus Incentive Plan..............        7,892           39          188             -            227
                                         ----------     --------     --------     ---------     ----------

Balance at December 31, 1994..........   62,154,594      310,772      648,496       308,214      1,267,482
Net income............................            -            -            -       178,856        178,856
Dividends declared
  Common stock, $2.04 per share.......            -            -            -      (128,587)      (128,587)
  Preferred stock, $100 par value.....            -            -            -        (9,004)        (9,004)
  Preferred stock, $25 par value......            -            -            -        (2,940)        (2,940)
Issuance of common stock
  Employees' Savings Plan.............      310,546        1,553        8,152             -          9,705
  Dividend Reinvestment Plan..........      889,331        4,447       23,575             -         28,022
  Omnibus Incentive Plan..............        3,657           19           92             -            111
                                         ----------     --------     --------     ---------     ----------

Balance at December 31, 1995..........   63,358,128      316,791      680,315       346,539      1,343,645
Net income............................            -            -            -       190,346        190,346
Dividends declared
  Common stock, $2.10 per share.......            -            -            -      (135,111)      (135,111)
  Preferred stock, $100 par value.....            -            -            -        (8,889)        (8,889)
  Preferred stock, $25 par value......            -            -            -        (2,940)        (2,940)
Issuance of common stock
  Employees' Savings Plan.............      274,934        1,374        8,420             -          9,794
  Dividend Reinvestment Plan..........      809,603        4,048       24,580             -         28,628
  Omnibus Incentive Plan..............       58,346          292        1,427             -          1,719
  Acquisitions (Note 4)...............      317,748        1,589        9,611             -         11,200
Capital Stock Expense.................            -            -            -          (104)          (104)
                                         ----------     --------     --------     ---------     ----------

Balance at December 31, 1996..........   64,818,759     $324,094     $724,353     $ 389,841     $1,438,288
                                         ----------     --------     --------     ---------     ----------
                                         ----------     --------     --------     ---------     ----------
</TABLE>

Authorized shares of common stock were 160 million at December 31, 1996, 
1995 and 1994.
                                       
          The accompanying notes to consolidated financial statements
              are an integral part of these financial statements.



                                       39

<PAGE>
                                       
                      PUBLIC SERVICE COMPANY OF COLORADO
                               AND SUBSIDIARIES
                                       
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                             (THOUSANDS OF DOLLARS)
                  YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994


<TABLE>
                                                                1996          1995          1994
                                                             ---------     ---------     ---------
<S>                                                          <C>           <C>           <C>
Operating activities:
  Net income..............................................   $ 190,346     $ 178,856     $ 170,269
  Adjustments to reconcile net income to net
    cash provided by operating activities (Note 1):
      Depreciation and amortization.......................     159,400       145,370       142,843
      Defueling and decommissioning expenses..............           -             -        43,376
      Gain on sale of WestGas Gathering, Inc..............           -             -       (34,485)
      Amortization of investment tax credits..............      (7,256)       (5,348)       (5,799)
      Deferred income taxes...............................      60,899        39,170        34,234
      Allowance for equity funds used during 
        construction......................................        (757)       (3,782)       (3,140)
      Change in accounts receivable.......................     (88,680)       38,734       (16,281)
      Change in inventories...............................      20,542         4,246        10,007
      Change in other current assets......................     (31,169)        7,618        (1,695)
      Change in accounts payable..........................      88,473       (20,922)      (35,364)
      Change in other current liabilities.................     (36,615)       24,230       (39,730)
      Change in deferred amounts..........................     (19,550)      (20,385)      (33,920)
      Change in noncurrent liabilities....................      (9,779)       (5,367)       15,321
      Other...............................................       1,760         3,279            92
                                                             ---------     ---------     ---------
          Net cash provided by operating activities.......     327,614       385,699       245,728

Investing activities:
  Construction expenditures...............................    (321,162)     (285,516)     (317,138)
  Allowance for equity funds used during construction.....         757         3,782         3,140
  Proceeds from sale of WestGas Gathering, Inc............           -             -        87,000
  Proceeds from disposition of property, plant and 
    equipment.............................................      20,454         2,470        49,438
  Payment for purchase of companies, net of cash 
    acquired (Note 4).....................................       3,649             -             -
  Purchase of other investments...........................     (11,485)      (10,249)         (955)
  Sale of other investments...............................         664         4,898         1,148
                                                             ---------     ---------     ---------
          Net cash used in investing activities...........    (307,123)     (284,615)     (177,367)

Financing activities:
  Proceeds from sale of common stock (Note 1).............      30,115        28,030        38,086
  Proceeds from sale of long-term notes and bonds 
    (Note 1)..............................................     217,415       101,860       250,068
  Redemption of long-term notes and bonds.................     (83,356)      (44,713)     (281,835)
  Short-term borrowings - net.............................     (43,325)      (36,750)       47,925
  Redemption of preferred stock...........................      (1,376)       (1,376)         (213)
  Dividends on common stock...............................    (133,394)     (127,352)     (122,531)
  Dividends on preferred stock............................     (11,857)      (11,973)      (12,016)
                                                             ---------     ---------     ---------
          Net cash used in financing activities...........     (25,778)      (92,274)      (80,516)
                                                             ---------     ---------     ---------
          Net increase (decrease) in cash and temporary 
            cash investments..............................      (5,287)        8,810       (12,155)
          Cash and temporary cash investments at 
            beginning of year.............................      14,693         5,883        18,038
                                                             ---------     ---------     ---------
          Cash and temporary cash investments at end 
            of year.......................................   $   9,406     $  14,693     $   5,883
                                                             ---------     ---------     ---------
                                                             ---------     ---------     ---------
</TABLE>
                                       
         The accompanying notes to consolidated financial statements
             are an integral part of these financial statements.



                                      40
<PAGE>
                                       
                      PUBLIC SERVICE COMPANY OF COLORADO
                               AND SUBSIDIARIES

                 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                              DECEMBER 31, 1996


1.  SUMMARY OF SIGNIFICANT 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 CPUC with respect to its retail electric and gas 
operations and the FERC with respect to its wholesale electric operations and 
accounting policies and practices.  Over 90% of the Company's electric and 
gas revenues are subject to CPUC jurisdiction.  Cheyenne is subject to the 
jurisdiction of the WPSC.  WGI and TOP are subject to the jurisdiction of the 
FERC.  The gas marketing, power brokering and other operations of e prime and 
TOG are not regulated.


    REGULATORY ASSETS AND LIABILITIES

    The Company and its regulated subsidiaries prepare their financial 
statements in accordance with the provisions of SFAS 71, as amended.  SFAS 71 
recognizes that accounting for rate regulated enterprises should reflect the 
relationship of costs and revenues introduced by rate regulation.  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.  On January 1, 1996, the Company adopted SFAS 121 which 
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 adoption of this statement did not 
have a material impact on the Company's results of operations, financial 
position or cash flow. The following regulatory assets are reflected in the 
Company's consolidated balance sheets:

<TABLE>
                                                                          RECOVERY
                                                    1996       1995        THROUGH
                                                  --------   --------   ------------
                                                 (THOUSANDS OF DOLLARS)
<S>                                               <C>        <C>        <C>
Nuclear decommissioning costs (Note 2).........   $ 89,731   $ 97,801       2005
Income taxes (Note 13).........................     98,355    110,617       2006
Employees' postretirement benefits 
  other than pensions (Note 11)................     54,449     47,600       2013
Early retirement costs (Note 11)...............     15,505     24,366       1998
Employees' postemployment benefits (Note 11)...     24,797     23,500   Undetermined
Demand-side management costs...................     41,462     30,188       2002
Unamortized debt reacquisition costs...........     19,914     21,940       2024
Other..........................................      4,353      6,032       1999
                                                  --------   --------
  Total........................................    348,566    362,044
Classified as current..........................     44,110     40,247
                                                  --------   --------
Classified as noncurrent.......................   $304,456   $321,797
                                                  --------   --------
                                                  --------   --------
</TABLE>

    Certain costs associated with the Company's DSM programs are deferred and 
recovered, along with the associated return, in rates over  five to seven 
year periods through the DSMCA.  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 applicable regulatory authority.



                                      41
<PAGE>

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

    The regulatory assets of the Company and its regulated subsidiaries as of 
December 31, 1996, are reflected in rates charged to customers over the 
recovery periods noted above.  The Company believes it will continue to be 
subject to rate regulation.  In the event that a portion of the Company's 
operations is no longer subject to the provisions of SFAS 71 as a result of a 
change in regulation or the effects of competition, the Company could be 
required to write-off related regulatory assets, determine any impairment to 
other assets resulting from deregulation and write-down any impaired assets 
to their estimated fair value.

    On January 27, 1997, the CPUC issued its order on the Company's 1996 gas 
rate case.  The CPUC allowed recovery of postemployment benefit costs on an 
accrual basis under SFAS 112 and denied amortization of the approximately 
$8.7 million regulatory asset recognized upon the adoption of SFAS 112 (see 
Note 11. Employee Benefits - Postemployment Benefits).  The Company is 
appealing the decision related to this issue and addressing the impact of 
this decision on the future recovery of the electric jurisdictional portion 
of postemployment benefit costs totaling approximately $13.8 million.  The 
Company believes that it will be successful on appeal and that the associated 
regulatory asset is realizable. If the appeal is unsuccessful, these amounts 
will be written off.


    RECOVERED/RECOVERABLE PURCHASED GAS AND ELECTRIC ENERGY COSTS - NET

    The Company's and Cheyenne's 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.  Currently, 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.  The CPUC's order related 
to the Company's merger rate filing modified and replaced the Company's ECA 
with an ICA, which allows for a 50%/50% sharing of certain fuel and energy 
cost increases and decreases among customers and shareholders (see Note 9.  
Commitments and Contingencies - Regulatory Matters).


    OTHER PROPERTY

    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.


    NON-UTILITY SUBSIDIARIES

    The Company's net investment in its non-utility subsidiaries approximated 
4.5% of common equity at December 31, 1996.  The subsidiaries are principally 
involved in non-regulated energy services, the management of real estate and 
certain life insurance policies and the financing of certain current assets 
of the Company.


MANAGEMENT ESTIMATES

    The preparation of financial statements, in conformity with generally 
accepted accounting principles, requires management to make estimates and 
assumptions that affect the reported amounts of assets and liabilities and 
the disclosure of contingent assets and liabilities at the date of the 
financial statements and the reported amounts of revenues and expenses during 
the reporting period.  Actual results could differ from those estimates.


CONSOLIDATION 

    The Company follows the practice of consolidating the accounts of its 
significant subsidiaries.  All intercompany items and transactions have been 
eliminated.  Certain prior year amounts have been reclassified to conform to 
the current year's presentation.



                                      42

<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

REVENUE RECOGNITION 

    The Company and Cheyenne accrue for estimated unbilled revenues for 
services provided after the meters were last read on a cycle billing basis 
through the end of each year.


STATEMENTS OF CASH FLOWS 

    For purposes of the consolidated statements of cash flows, the Company 
and its subsidiaries consider all temporary cash investments to be cash 
equivalents. These temporary cash investments are securities having original 
maturities of three months or less or having longer maturities but with put 
dates of three months or less.

    INCOME TAXES AND INTEREST (EXCLUDING AMOUNTS CAPITALIZED) PAID:

                                       1996       1995       1994
                                     --------   --------   --------
                                         (THOUSANDS OF DOLLARS)

Income taxes......................   $ 66,871   $ 58,662   $ 41,763
Interest..........................   $144,533   $140,823   $126,250


    NON-CASH TRANSACTIONS:

    Shares of common stock (274,934 in 1996, 310,546 in 1995 and 334,223 in 
1994), valued at the market price on date of issuance (approximately $10 
million for each year), 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 (6,673 in 1996, 3,390 in 1995 and 7,892 in 1994), valued at the market 
price on the date of issuance ($0.2 million in 1996, $0.1 million in 1995 and 
$0.2 million in 1994), were issued to certain executives pursuant to the 
applicable provisions of the executive compensation plans.

    During 1996, the Company exchanged 317,748 shares of its common stock 
valued at approximately $11.2 million in connection with the acquisition of 
TOG. During 1994, the Company sold all of its outstanding common stock of WGG 
(see Note 4. Acquisition and Divestiture of Investments).  Cash flows from 
operating activities reflect the changes in assets and liabilities, net of 
the effects from these acquisitions and divestiture.

    The stock issuances referenced above were non-cash financing activities 
and are not reflected in the consolidated statements of cash flows.

    A $40.5 million capital lease obligation was recognized in 1995 in 
connection with a 30-year gas storage facility agreement.  Additionally, 
other capital lease obligations totaling approximately $0.1 million were 
recognized in 1995.  A $16.8 million capital lease obligation was incurred 
for computer equipment in 1994.


PROPERTY, DEPRECIATION AND AMORTIZATION

    Replacements and betterments representing units of property are 
capitalized.  Maintenance and repairs of property and replacements of items 
of property determined to be less than a unit of property are charged to 
operations as maintenance.  The cost of units of property retired, together 
with cost or removal, less salvage, is charged against accumulated 
depreciation.

    Provisions for depreciation of property, plant and equipment for 
financial accounting purposes are based on straight-line composite rates 
applied to the various classes of depreciable property.  Depreciation rates 
include provisions for disposal and removal costs of property, plant and 
equipment.  Depreciation expense, expressed as a percentage of average 
depreciable property, approximated 2.7% for the year ended December 31, 1996 
and 2.6% 

                                       43 
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

for the years ended December 31, 1995 and 1994.  For income tax purposes, the 
Company and its subsidiaries use accelerated depreciation and other elections 
provided by the tax laws. Intangible assets are amortized on a straight line 
basis over their estimated useful lives.

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION 

    AFDC, as defined in the system of accounts prescribed by the FERC and the 
CPUC, represents the net cost during the period of construction of borrowed 
funds used for construction purposes, and a reasonable rate on funds derived 
from other sources. AFDC does not represent current cash earnings.  The 
Company capitalizes AFDC as a part of the cost of utility plant.  The AFDC 
rates or ranges of rates used during 1996, 1995 and 1994 were 5.67%-6.78%, 
7.97% and 6.81%-8.75%, respectively.


MISCELLANEOUS INCOME AND DEDUCTIONS - NET

    Miscellaneous income and deductions - net includes items which are 
non-operating in nature or, in general, are not considered in the ratemaking 
process.  Such items include, among other things, merger related costs, 
contributions, gains and losses on the sale of property and certain 
litigation, severance and environmental costs.  Individually, these amounts 
did not have a material impact on the Company's results of operations.


INCOME TAXES 

    The Company and its subsidiaries file consolidated Federal and state 
income tax returns.  Income taxes are allocated to the subsidiaries based on 
separate company computations of taxable income or loss.  Investment tax 
credits have been deferred and are being amortized over the service lives of 
the related property.  Deferred taxes are provided on temporary differences 
between the financial accounting and tax bases of assets and liabilities 
using the tax rates which are in effect at the balance sheet date (see Note 
13.  Income Taxes).


STOCK-BASED COMPENSATION

    As allowed by SFAS 123, the Company uses the intrinsic value based method 
of accounting prescribed by APB Opinion No. 25, in accounting for its 
stock-based compensation plan (see Note 11.  Employee Benefits - Incentive 
Compensation).   


GAS IN UNDERGROUND STORAGE

    Gas in underground storage is accounted for under the last-in, first-out 
(LIFO) cost method.  The estimated replacement cost of gas in underground 
storage at December 31, 1996 and 1995 exceeded the LIFO cost by approximately 
$52.2 million and $5.3 million, respectively.


CASH SURRENDER VALUE OF LIFE INSURANCE POLICIES

    The following amounts related to COLI contracts, issued by one major 
insurance company, are recorded as a component of Investments, at cost and 
receivables, on the consolidated balance sheets:

                                                     1996       1995 
                                                   --------   --------
                                                  (THOUSANDS OF DOLLARS)

Cash surrender value of contracts...............   $359,136   $311,097
Borrowings against contracts....................    356,421    308,833
                                                   --------   --------
  Net investment in life insurance contracts....   $  2,715   $  2,264
                                                   --------   --------
                                                   --------   --------



                                       44 
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

2. FORT ST. VRAIN

OVERVIEW

    In 1989, the Company announced its decision to end nuclear operations at 
Fort St. Vrain and to proceed with the defueling and decommissioning of the 
reactor. While the defueling of the reactor to the ISFSI was completed in 
June 1992, several issues related to the ultimate storage/disposal of Fort 
St. Vrain's spent nuclear fuel remained unresolved. During 1994, the Company 
recognized additional expenses aggregating approximately $43.4 million for 
increased costs associated with defueling and decommissioning and the 
impairment of certain property and inventory. The additional expense was 
primarily associated with radiation levels in the reactor core being higher 
than originally anticipated and increased uncertainty related to spent fuel 
issues. In 1996, the Company and the DOE entered into a contract resolving 
all the defueling issues.  Additionally, in early 1996, the Company announced 
that the physical decommissioning work at the facility was completed. NRC 
site release activities are continuing.  The Company requested the NRC to 
terminate the Part 50 license and it is anticipated that the license will be 
terminated by mid-1997.

    Fort St. Vrain is being repowered as a gas fired combined cycle steam 
plant consisting of two combustion turbines and two heat recovery steam 
generators totaling 471 Mw.  The CPCN, which was received in July 1994, 
provides for the repowering of Fort St. Vrain in a phased approach as 
follows:  Phase 1A - 130 Mw, commercial operations commenced on May 1, 1996, 
Phase 1B - 102 Mw, currently under construction with a 1998 expected in 
service date and Phase 2 - 239 Mw in 2000.  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.  As part of 
this agreement, the Company has agreed to the following: 1) the DOE assumed 
title to the fuel currently stored in the ISFSI, 2) the DOE will assume title 
to the ISFSI and will be responsible for the future defueling and 
decommissioning of the facility, 3) the DOE agreed to pay the Company $16 
million for the settlement of claims associated with the ISFSI, 4) ISFSI 
operating and maintenance costs, including licensing fees and other 
regulatory costs, will be the responsibility of the DOE, and 5) the Company 
provided to the DOE a full and complete release of claims against the DOE 
resolving all contractual disputes related to storage/disposal of Fort St. 
Vrain spent nuclear fuel.  On December 17, 1996, the DOE submitted a request 
to the NRC to transfer the title of the ISFSI. This request is being reviewed 
by the NRC and the Company anticipates approval in mid-1997.

    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, pre-tax earnings for 1996 were positively impacted by 
approximately $16 million.  In accordance with the 1991 CPUC approval to 
recover certain decommissioning costs, 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 the 
amount to be refunded to customers has not yet been finally determined, the 
Company established an $8 million liability for such refunds.


DECOMMISSIONING

    Following the 1991 CPUC approval, effective July 1, 1993 the Company 
began collecting from customers decommissioning costs expected to total 
approximately $124.4 million (plus a 9% carrying cost).  Such amount, which 
is being 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 December 
31, 1996, approximately $89.7 million of such amount remains to be collected 
from customers and, therefore, is reflected as a regulatory asset on the 
consolidated balance sheet. The amount recovered from customers each year is 
approximately $13.9 million.  

                                       45 
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

    On March 22, 1996, the Company and the decommissioning contractors 
announced that the physical decommissioning activities at the facility have 
been completed.  Additionally, the final site survey was completed in late 
October 1996 with only the NRC site release remaining to be obtained. At 
December 31, 1996, a remaining $8.7 million defueling and decommissioning 
liability was reflected on the consolidated balance sheet. The Company 
believes this remaining decommissioning liability is adequate to complete all 
final decommissioning activities.

    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, which for 
several years included obtaining an unsecured irrevocable letter of credit. 
In December 1996, the Company placed $8.5 million in a trust to satisfy  the 
remaining funding requirements. These funds are restricted for 
decommissioning expenditures and any unspent funds will remain in this trust 
until the NRC releases the Company from further obligation, which is 
anticipated to occur by mid-1997.


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, SPS, a New Mexico corporation, and NCE, 
a newly formed Delaware corporation, entered into a Merger Agreement 
providing for a business combination as peer firms involving the Company and 
SPS in a "merger of equals" transaction.  Based on outstanding common stock 
of the Company and SPS at December 31, 1996, the Merger would result in the 
common shareholders of the Company owning 63% of the common equity of NCE and 
the common shareholders of SPS owning 37% of the common equity of NCE.  In 
January 1996, NCE filed its application with the 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.  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 in addition to the expiration 
or termination of the applicable waiting periods under the Hart-Scott-Rodino 
Antitrust Improvements Act of 1976 ("HSR"), as amended.  The required 
authorizations from the CPUC, the Public Utility Commission of Texas, the 
WPSC, the New Mexico Public Utility Commission, the Kansas Corporation 
Commission, the NRC and the U.S. Department of Justice have been obtained. 
The waiting period under the HSR Act has expired. Related to FERC approval, a 
non-unanimous settlement agreement has been reached and hearings were held in 
late September 1996.  On January 23, 1997, the sole party opposing the 
settlement filed a notice with the FERC withdrawing all of its pleadings.  
The Company has requested that the FERC give the matter expedited 
consideration.  A final FERC order is expected in March 1997.  The Company 
expects that the SEC will make its ruling on the Merger within 30-60 days 
following the FERC decision.  While timing of the effective 

                                       46 
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

date of the Merger is primarily dependent on the regulatory process, it is 
currently expected that the Merger will be completed in the second quarter of 
1997.

    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 NCE 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 1997.  The Company recognized 
costs associated with the Merger of approximately $7.2 million in 1996 and 
$4.1 million in 1995. 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 proposed as part of the merger with SPS.  The 
Company is seeking approval from the SEC to maintain these businesses and 
currently does not anticipate that divestiture will be required.  If 
divestiture is ultimately required, the SEC has historically allowed 
companies sufficient time to accomplish divestitures in a manner that 
protects shareholder value.


4.  ACQUISITION AND DIVESTITURE OF INVESTMENTS

PROPOSED ACQUISITION OF YORKSHIRE ELECTRICITY

    On February 24, 1997, the Company and AEP jointly announced that they 
have reached agreement with the board of directors of Yorkshire Electricity, 
a UK regional electricity company, on the terms of a recommended cash tender 
offer for all of the outstanding and to be issued ordinary shares of 
Yorkshire Electricity. The Company and AEP, through a joint venture named 
Yorkshire Holdings, are offering the equivalent of US $15.02 (9.27 pounds) 
per ordinary share, for a total purchase price of approximately US $2.4 
billion (1.5 billion pounds). The board of directors of the Company and AEP 
have approved the transaction. The board of directors of Yorkshire 
Electricity has agreed to recommend the offer to Yorkshire Electricity's 
shareholders. The offer will be made through Yorkshire Holdings, a 
wholly-owned subsidiary of Yorkshire Power, a newly formed UK corporation 
owned equally by the Company and AEP.

    Consummation of the Proposed Acquisition is subject to customary 
conditions in the UK, including regulatory clearance and acceptance of the 
offer by holders of at least 90% of the outstanding shares of Yorkshire 
Electricity. Yorkshire Holdings may waive the latter condition when it has 
received acceptances of its offer and has otherwise acquired shares which in 
total represent more than 50% of the outstanding shares of Yorkshire 
Electricity. The Company cannot predict at this time whether or not these 
conditions will be met or waived.

    If the Proposed Acquisition is completed, the Company would have an 
indirect 50% ownership interest in Yorkshire Electricity, which would be 
accounted for using the equity method of accounting.

ACQUISITION OF TEXAS-OHIO GAS, INC. AND TEXAS-OHIO PIPELINE, INC.

    Effective September 1, 1996, the Company and e prime, a wholly-owned 
subsidiary, acquired all of the outstanding stock of TOG and TOP in exchange 
for a combination of common stock of the Company and cash. Such acquisitions 
were accounted for using the purchase method and the acquired assets and 
liabilities have been valued at their estimated fair market values as of the 
date of acquisition.  These companies are primarily engaged in gas brokering 
and marketing activities and are subsidiaries of e prime.

                                       47 
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

DIVESTITURE OF FUEL RESOURCES DEVELOPMENT CO.

    Since 1993, the Company has been pursuing the divestiture of all 
properties owned by Fuelco, a wholly-owned subsidiary which was primarily 
involved in the exploration and production of oil and natural gas. The 
Company recognized the estimated effects of the divestiture in the fourth 
quarter of 1993 and sold the remaining properties in 1994 and 1996 at 
approximately net book value.


WESTGAS TRANSCOLORADO, INC.

    In September 1995, WGT sold its one-third interest in the TransColorado 
Gas Transmission Company for $3.8 million, which approximated net book value.


ACQUISITION OF YOUNG GAS STORAGE COMPANY

    On June 25, 1995, the Company acquired all of the outstanding stock of 
YGSC for $6.3 million. The acquisition was accounted for using the purchase 
method. On February 1, 1996, the Company contributed the common stock of YGSC 
to e prime. YGSC owns a 47.5% general partnership interest in Young Storage, 
which owns and operates an underground facility in northeastern Colorado.


SALE OF  WESTGAS GATHERING, INC.

    In August 1994, the Company sold all of its outstanding common stock of 
WGG, its wholly-owned subsidiary, and certain related operating assets of the 
Company which were used by WGG for approximately $87 million, subject to 
certain final closing adjustments. The Company recognized a pre-tax gain of 
approximately $34.5 million ($19.5 million after-tax or approximately 31 
cents per share). In the first quarter of 1995, the Company recognized $2.1 
million of this gain as an amount to be refunded to customers in accordance 
with a March 30, 1995 settlement with the OCC. The refund was completed in 
late 1995.

5.  CAPITAL STOCK

COMMON STOCK

    During 1991, the Company's Board of Directors declared a dividend of one 
common share purchase right ("right") on each outstanding share of the 
Company's common stock.  All common shares issued will contain this right.  
Each right stipulates an initial purchase price of $55 per share and also 
prescribes a means whereby the resulting effect is such that, under the 
circumstances described below, shareholders would be entitled to purchase 
additional shares of common stock at 50% of the prevailing market price at 
the time of exercise. These rights are not currently exercisable, but would 
become exercisable if certain events occurred related to a person or group 
acquiring or attempting to acquire 20% or more of the outstanding shares of 
common stock of the Company. On August 22, 1995, in connection with the 
proposed merger (see Note 3), the Company's Rights Agreement was amended to 
provide that NCE will not be considered an "Acquiring Person" as a result of 
the execution, delivery, and performance of the Merger Agreement.

    In the event a takeover results in the Company being merged into an 
acquiror, the unexercised rights could be used to purchase shares in the 
acquiror at 50% of market price.  Subject to certain conditions, if a person 
or group acquires at least 20% but no more than 50% of the Company's common 
stock, the Company's Board of Directors may exchange each right held by 
shareholders other than the acquiring person or group for one share of common 
stock (or its equivalent).

    If a person or group successfully acquires 80% of the Company's common 
stock for cash, after tendering for all of the common stock, and satisfies 
certain other conditions, the rights would not operate.  The rights expire 

                                     48

<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

on March 22, 2001; however, each right may be redeemed by the Board of Directors
for one cent at any time prior to the acquisition of 20% of the common stock 
by a potential acquiror.


PREFERRED STOCK 

<TABLE>
                                                            1996                     1995 
                                                   -----------------------  ------------------------
                                                     SHARES       AMOUNT      SHARES        AMOUNT
                                                   ---------   -----------  ---------    -----------
                                                               (THOUSANDS                (THOUSANDS
                                                               OF DOLLARS)               OF DOLLARS)
<S>                                                <C>          <C>         <C>           <C>
Cumulative preferred stock, $100 par value:
  Authorized....................................   3,000,000                3,000,000
                                                   ---------                ---------
                                                   ---------                ---------
  Issued and outstanding:
    Not subject to mandatory redemption:
      4.20% series..............................     100,000    $ 10,000      100,000     $ 10,000
      4 1/4% series (includes $7,500 premium)...     175,000      17,508      175,000       17,508
      4 1/2% series.............................      65,000       6,500       65,000        6,500
      4.64% series..............................     160,000      16,000      160,000       16,000
      4.90% series..............................     150,000      15,000      150,000       15,000
      4.90% 2nd series..........................     150,000      15,000      150,000       15,000
      7.15% series..............................     250,000      25,000      250,000       25,000
                                                   ---------    --------    ---------     --------
        Total...................................   1,050,000    $105,008    1,050,000     $105,008
                                                   ---------    --------    ---------     --------
                                                   ---------    --------    ---------     --------

    Subject to mandatory redemption:
      7.50% series..............................     216,000    $ 21,600      216,000     $ 21,600
      8.40% series..............................     208,892      20,889      222,652       22,265
                                                   ---------    --------    ---------     --------
                                                     424,892      42,489      438,652       43,865
    Less: Preferred stock subject to mandatory
      redemption within one year................     (25,760)     (2,576)     (25,760)      (2,576)
                                                   ---------    --------    ---------     --------
        Total...................................     399,132    $ 39,913      412,892     $ 41,289

Cumulative preferred stock, $25 par value:
  Authorized....................................   4,000,000                4,000,000
                                                   ---------                ---------
                                                   ---------                ---------

  Issued and outstanding:
    Not subject to mandatory redemption:
      8.40% series..............................   1,400,000    $ 35,000    1,400,000     $ 35,000
                                                   ---------    --------    ---------     --------
                                                   ---------    --------    ---------     --------
</TABLE>

    The preferred stock may be redeemed at the option of the Company upon at 
least 30, but not more than 60, days' notice in accordance with the following 
schedule of prices, plus an amount equal to the accrued dividends to the date 
fixed for redemption: 

    CUMULATIVE PREFERRED STOCK, NOT SUBJECT TO MANDATORY REDEMPTION: 

    $100 par value, all series: $101 per share.
    $25 par value, 8.40% series: $25.25 per share.

    CUMULATIVE PREFERRED STOCK, SUBJECT TO MANDATORY REDEMPTION:

    7.50% series: $101.75 per share on or prior to August 31, 1997, reducing 
each year thereafter by $0.25 per share until August 31, 2003, after which 
the redemption price is $100 per share; 8.40% series: $102 per share on or 
prior to July 31, 1997, and reducing each year thereafter by $0.25 per share 
until July 31, 2004, after which the redemption price is $100 per share. 

    In 1997 and in each year thereafter, the Company must offer to repurchase 
12,000 shares of the 7.50% series subject to mandatory redemption at $100 per 
share, plus accrued dividends to the date set for repurchase, and 13,760 
shares of the 8.40% series subject to mandatory redemption at $100 per share, 
plus accrued dividends to the date set for repurchase.  Consequently, this 
preferred stock to be redeemed is classified as preferred stock 

                                     49

<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

subject to mandatory redemption within one year in the December 31, 1996 
consolidated balance sheet. In 1996 and 1995, the Company repurchased 13,760 
shares of the 8.40% cumulative preferred series subject to mandatory 
redemption.  In 1994, the Company repurchased 2,133 shares of the 8.40% 
cumulative preferred series subject to mandatory redemption.  No other changes 
in preferred stock occurred in the three years ended December 31, 1996. 

6. LONG-TERM DEBT

<TABLE>
                                                                     1996           1995
                                                                  ----------     ----------
                                                                    (THOUSANDS OF DOLLARS)
<S>                                                               <C>            <C>
Public Service Company of Colorado:
  First Collateral Trust Bonds:
    6% series, due January 1, 2001.............................   $  102,667     $  102,667
    6 3/8% series, due November 1, 2005........................      134,500        134,500
    7 1/8% series, due June 1, 2006............................      125,000              -
    7 1/4% series, due January 1, 2024.........................      110,000        110,000
  First Mortgage Bonds:
    5 7/8%  - 6 3/4% series, due May 1, 1996 - 
      July 1, 1998.............................................       60,000         95,000
    8 1/8% series, due March 1, 2004...........................      100,000        100,000
    8 3/4% - 9 7/8% series, due July 1, 2020 - 
      March 1, 2022............................................      225,000        225,000
    Pollution Control Series A, 5 7/8%, due March 1, 2004......       22,500         23,000
    Pollution Control Series F, 7 3/8%, due November 1, 2009...       27,250         27,250
    Pollution Control Series G, 5 5/8% - 5 7/8%, 
      due April 1, 2008 - April 1, 2014........................       79,500         79,500
    Pollution Control Series H, 5 1/2%, due June 1, 2012.......       50,000         50,000
  Secured Medium-Term Notes, Series A:
        6.05% - 9.25%, due Jan 15, 1996 - November 25, 2003....      183,500        151,500
  Unamortized premium..........................................           13             24
  Unamortized discount.........................................       (5,032)        (4,568)
  Capital lease obligations, 6.68-14.65%, due in 
    installments through May 31, 2025..........................       49,070         53,567
                                                                  ----------     ----------
                                                                   1,263,968      1,147,440

Cheyenne Light, Fuel and Power Company:
  First Mortgage Bonds:
    7 7/8% series, due April 1, 2003...........................        4,000          4,000
    7.50% series, due January 1, 2024..........................        8,000          8,000
    Industrial Development Revenue Bonds, 7.25%, 
      due September 1, 2021....................................        7,000          7,000

PS Colorado Credit Corporation, Inc.:
  Unsecured Medium-Term Notes, Series A:
    5.75% - 6.03%, due November 24, 1997 - 
      December 1, 1998.........................................      100,000         80,000

1480 Welton, Inc.:
  13.25% secured promissory note, due in 
    installments through October 1, 2016.......................       31,506         31,814

Natural Fuels Corporation:
  Capital lease obligations, 4.21-11.11%, due in 
    installments through November 5, 2000......................           84            135
                                                                  ----------     ----------
                                                                   1,414,558      1,278,389
Less: maturities due within one year...........................      155,030         82,836
                                                                  ----------     ----------
                                                                  $1,259,528     $1,195,553
                                                                  ----------     ----------
                                                                  ----------     ----------
</TABLE>

    Substantially all properties of the Company and its subsidiaries, other 
than expressly excepted property, are subject to the liens securing the 
Company's First Mortgage Bonds or the mortgage bonds and notes of 
subsidiaries. Additionally, there is a second lien on the electric property 
securing the Company's First Collateral Trust Bonds.  The Company's First 
Collateral Trust Bonds are additionally secured by an equal amount of First 
Mortgage Bonds which bear no interest.

                                     50

<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

    The aggregate annual maturities and sinking fund requirements during the 
five years subsequent to December 31, 1996 are (in thousands of dollars):

    YEAR     MATURITIES     SINKING FUND REQUIREMENTS      TOTAL
    1997      $155,030                $810                $155,840
    1998        76,499                 560                  77,059
    1999        44,196                 560                  44,756
    2000        31,656                 560                  32,216
    2001         8,302                 560                   8,862

    The Company and Cheyenne expect to satisfy substantially all of their 
sinking fund obligations through the application of property additions.


7.  NOTES PAYABLE AND COMMERCIAL PAPER 

    Information regarding notes payable and commercial paper for the years 
ended December 31, 1996 and 1995 is as follows: 

                                                           1996        1995
                                                        ---------   ----------
                                                        (THOUSANDS OF DOLLARS)
Notes payable to banks (weighted average interest 
  rates of 5.98% at December 31, 1996 and 6.12% 
  at December 31, 1995)...............................   $ 18,375   $ 45,800
Commercial paper (weighted average interest rates 
  of 6.10% at December 31, 1996 and 6.21% at 
  December 31, 1995)..................................    226,350    242,250
                                                         --------   --------
                                                         $244,725   $288,050
                                                         --------   --------
                                                         --------   --------

Maximum amount outstanding at any month-end during 
  the period..........................................   $306,675   $329,475
                                                         --------   --------
                                                         --------   --------

Weighted average amount (based on the daily 
  outstanding balance) outstanding for the period 
  (weighted average interest rates of 5.63% for the 
  year ended December 31, 1996 and 6.18% for the 
  year ended December 31, 1995).......................   $250,324   $292,226
                                                         --------   --------
                                                         --------   --------


8.  BANK LINES OF CREDIT AND COMPENSATING BANK BALANCES 

    Arrangements by the Company and its subsidiaries for committed lines of 
credit are maintained entirely by fee payments in lieu of compensating 
balances. Arrangements for uncommitted lines of credit have no fee or 
compensating balance requirements.

    The Company, PSCCC, and certain subsidiaries have entered into a credit 
facility with several banks providing $300 million in committed bank lines of 
credit. The credit facility, which is used primarily to support the issuance 
of commercial paper by the Company and PSCCC, alternatively provides for 
direct borrowings thereunder.  Cheyenne, 1480 Welton, Inc., Fuelco, e prime 
and PSRI are provided access to the credit facility with direct borrowings 
guaranteed by the Company.  The facility expires November 17, 2000.

    Individual arrangements for uncommitted bank lines of credit totaled $75 
million at December 31, 1996, of which all remained unused.  The Company may 
borrow under uncommitted preapproved lines of credit upon request; however, 
the banks have no firm commitment to make such loans.


                                     51

<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

9.  COMMITMENTS AND CONTINGENCIES 

REGULATORY MATTERS

MERGER RATE FILINGS

    In connection with the Merger with SPS, in November 1995 the Company 
filed comprehensive proposals with the CPUC, the WPSC and the FERC to obtain 
approval of the Merger and the associated comprehensive proposals from such 
regulatory agencies.

    On November 29, 1996, and as modified on January 15, 1997, the CPUC 
issued a written decision approving the Merger as well the major provisions 
of a stipulation and agreement entered into among the Company, the CPUC 
Staff, the OCC, and substantially all other parties.  The decision 
establishes a five year performance based regulatory plan and acknowledges 
that the Merger is in the public interest.  The major provisions of the 
decision include:

    - $6 million electric rate reduction, which was instituted October 1, 1996,
      to be followed by an additional $12 million electric rate reduction
      effective with the implementation of new gas rates on February 1, 1997
      resulting from the 1996 general gas rate case, 

    - an annual electric department earnings test with the sharing of 
      earnings in excess of an 11% return on equity for the calendar years 
      1997-2001 as follows:

                                 Sharing of Excess Earnings
         Electric Department     --------------------------
          Return on Equity       Customers     Shareholders
         -------------------     ---------     ------------
              11-12%                65%             35%
              12-14%                50%             50%
              14-15%                35%             65%
            over 15%               100%              0%;

    - the termination of the QFCCA earnings test which was to become effective
      on October 1, 1996;

    - a freeze in base electric rates for the period through December 31, 2001
      with the flexibility to make certain other rate changes, including those
      necessary to allow for the recovery of DSM, QF and decommissioning costs;

    - a replacement of the Company's ECA with an ICA to allow for a 50%/50%
      sharing of certain fuel and energy cost increases or decreases among
      customers and shareholders; and

    - the implementation of a QSP which provides for penalties totaling up to 
      $5 million in year one and increasing to $11 million in year five, if 
      the Company does not achieve certain performance measures relating 
      to electric reliability, customer complaints and telephone response to 
      inquiries.  A new docket is expected to be opened to address the 
      implementation of a reward structure for performance above certain 
      standards.

    The rate reductions, the earnings sharing, the QSP and the adoption of an 
ICA will remain in effect even if the Merger is not consummated.  The freeze 
in base electric rates does not prohibit the Company from filing a general 
rate case or deny any party the opportunity to initiate a complaint or show 
cause proceeding.
 
    Approval of the Merger was received from the WPSC on August 16, 1996. 
Hearings in the FERC proceedings were held in September and a non-unanimous 
settlement agreement was reached.  On January 23, 1997, the sole party 
opposing the settlement filed a notice with the FERC withdrawing all of its 
pleadings. The Company has requested that the FERC give the matter expedited 
consideration. A final FERC order is expected in March 1997.

                                     52
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

RATE CASES

    On June 5, 1996, the Company filed a retail rate case with the CPUC 
requesting an annual increase in its jurisdictional gas department revenues 
of approximately $34 million.  Intervenor testimony was filed in the third 
quarter of 1996 with the primary issue being authorized rate of return on 
common equity. In January 1997, the CPUC approved an overall increase of 
$17.6 million with an 11.25% return on equity, effective February 1, 1997. 
On February 20, 1997, the Company filed for rehearing, reargument and 
reconsideration on the treatment of certain issues (see Note 1).

    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 OPEB costs under SFAS 106, postemployment benefit costs under 
SFAS 112 and new depreciation rates based on the Company's most recent 
depreciation study.  Settlement agreements have been reached with all parties 
and filed with the FERC which recognized recovery of the benefit costs 
discussed above and results in an overall slight decrease in rates.  A final 
order is expected to be issued in early 1997.

ELECTRIC AND GAS COST ADJUSTMENT MECHANISMS

    During 1994 and 1995, the CPUC conducted several proceedings to review 
issues related to the ECA. 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 decision on the Merger modified and replaced the ECA with an ICA.  
The ICA, which became effective October 1, 1996, allows for a 50%/50% sharing 
of certain fuel and energy cost increases and decreases among customers and 
shareholders.  

    The CPUC has had an on-going docket to review and prescribe a 
standardized GCA process to determine the prudence of gas commodity and 
pipeline delivery service costs incurred by gas utilities.  Other issues to 
be addressed in this docket include whether the GCA should be maintained in 
its present form, altered or eliminated.  The CPUC conducted hearings 
regarding this matter on February 14, 1997.  Additional hearings have been 
scheduled for March 7, 1997.

    The CPUC approved the recovery of certain energy efficiency credits from 
retail jurisdiction customers through the DSMCA in June 1994.  The OCC filed 
an appeal of the CPUC's decision in the Denver District Court.  The Denver 
District Court approved the collection of these credits in June 1995, subject 
to refund. On April 9, 1996, the Denver District Court issued an order 
affirming the CPUC's decision, however, the OCC appealed this issue to the 
Colorado Supreme Court. On August 20, 1996, the OCC filed a motion for 
voluntary dismissal with prejudice with the Colorado Supreme Court which was 
accepted and effectively resolved this matter.

FEDERAL ENERGY REGULATORY COMMISSION

    On April 24, 1996, the FERC issued Order No. 888, Order No. 889 and a 
NOPR.  Order No. 888 requires jurisdictional utilities owning, controlling, or 
operating transmission facilities to file non-discriminatory open-access 
tariffs that satisfy the comparability standard -- i.e., that offer 
transmission services consistent with what is provided for in their own 
operations.  The FERC required that all such utilities file the single pro 
forma tariff (combined network and point-to-point tariff) by July 9, 1996.  
The Company has filed the required pro forma tariff.  Order No. 888 also 
provides for the recovery of legitimate, prudent, and verifiable stranded 
investment costs incurred when existing wholesale requirements customers and 
retail customers leave utilities' generation systems through FERC 
jurisdictional open-access tariffs and obtain their electric power from other 
energy suppliers. 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 the 
authority to address retail stranded costs at the time when retail wheeling is 
required.
                                     53
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

    Order No. 889 requires utilities to implement standards of conduct and an 
Open Access Same-time Information System ("OASIS") 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.  In summary, it requires that utilities completely 
separate their wholesale power marketing and transmission operations 
functions.  The NOPR on Capacity Reservation Open Access Transmission Tariffs 
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. 

    As required by Order No. 888, the Company filed a compliance transmission 
tariff on behalf of itself and Cheyenne on July 9, 1996.  The Company made 
various additional filings with the FERC throughout 1996 to meet the 
requirements of Order Nos. 888 and 889.  On January 29, 1997, the FERC issued 
an order accepting the non-rate terms and conditions contained in the 
Company's Order No. 888 transmission tariff.  The rates set out in that 
tariff are the same as those proposed by the Company and Cheyenne in an Offer 
of Settlement submitted in an earlier proceeding and now pending before the 
FERC for review.

    On March 29, 1996, the FERC accepted the request of e prime, a 
non-regulated subsidiary, for authorization to act as a power marketer, 
subject to certain conditions.  On April 15, 1996, e prime made a required 
compliance filing, but also submitted a request for rehearing on one of the 
conditions imposed by the FERC.  The FERC accepted the compliance filing, but 
the request for rehearing is still pending.


ENVIRONMENTAL ISSUES

ENVIRONMENTAL SITE CLEANUP

    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 PRPs.  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. 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.

    Under the CERCLA, the EPA has identified, and a Phase II environmental 
assessment has revealed, low level, widespread contamination from hazardous 
substances at the Barter Metals Company ("Barter")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 and has 
received responses from the Colorado Department of Public Health and 
Environment ("CDPHE") indicating that no further action is required related 
to  these properties.  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 
cleanup costs at Barter.  Several appeals and cross appeals have been filed 
by 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 had 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 
beyond insurance proceeds through the sale of the Barter property and from 
other PRPs.  In August 1996, the Company filed a lawsuit against four PRPs 
seeking recovery of certain Barter related costs.

    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 

                                     54
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

owners resolving all claims.  In December 1995, complaints were filed by the 
Company against all applicable insurance carriers in the Denver District 
Court.  A trial date regarding the insurance carriers has been established for 
August 1997.

    The Ramp Industries disposal facility, located in Denver, Colorado has 
been designated by the EPA as a Superfund hazardous substance site pursuant 
to CERCLA.  On November 29, 1995, the Company received from the EPA a Notice 
of Potential Liability and Request for Information related to such site and 
the Company has responded to this request. 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 PRPs.  As of the end of 1996, 
the EPA has not yet developed a site specific plan for the cleanup or 
remediation, therefore at this time, the Company cannot estimate the amount, 
if any, of its potential liability related to this matter.  It is anticipated 
that the EPA will notify the Company with the results of its investigation 
sometime during 1997.

    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.


ENVIRONMENTAL MATTERS RELATED TO AIR QUALITY AND POLLUTION CONTROL

    Under the Clean Air Act Amendments of 1990, coal burning power plants are 
required to reduce SO2 and NOx emissions to specified levels through a phased 
approach. The Company's facilities must comply with the Phase II requirements 
which will be effective in the year 2000.  The Company expects to meet the 
Phase II 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 the NOx emissions in order to comply with Phase II 
requirements.  The estimated Phase II costs for future plant modifications to 
meet NOx requirements is approximately $13 million.  The Company is studying 
its options to reduce NOx and SO2 emissions and, currently does not 
anticipate that these regulations will significantly impact its operations.  


HAYDEN STEAM ELECTRIC GENERATING STATION

    On May 21, 1996, the Company and the other joint owners of the Hayden 
station reached an agreement, as discussed below,  with a conservation 
organization, the CDPHE and the EPA which provides for a complete and final 
release of all civil claims for violations alleged in complaints filed by the 
conservation organization, the CDPHE and the EPA against the joint owners.   
The complaints filed, pursuant to provisions of the Federal Clean Air Act, by 
a conservation organization and the EPA alleged, among other things, that the 
station exceeded the 20% opacity limitations during various periods extending 
from 1988 to mid-1995.  In August, 1996 the U.S. District Court for the 
District of Colorado entered the settlement agreement which effectively 
resolved this litigation.  The Company is the operator and owns an average 
undivided interest of approximately 53% of the station's two generating units.

    In connection with the above settlement, the joint owners of the Hayden 
station made the following payments in 1996: 1) a $2 million payment to the 
U.S. Treasury, 2) a contribution of $2 million to a "Land Trust Fund" to be 
used for the purchase of land and/or conservation easements in the Yampa 
Valley and 3) a contribution of $250,000 to be used for the conversion of 
vehicles and/or wood burning appliances to natural gas in the Yampa Valley. 
The Company's portion of these costs is approximately $2.3 million, which has 
been expensed in the accompanying financial statements. The joint owners have 
committed to the installation of emission control equipment on both 
generating units to reduce future particulate (opacity), SO2 and NOx 
emissions over the next three years.  The joint owners estimate that the cost 
of installing emission control equipment capable of reducing the emissions to 
the levels required under the agreement, consisting of fabric filter dust 
collectors, lime spray dryers and low NOx burners on both units, is 
approximately $130 million, with the Company's portion totaling approximately 
$70 million. Also, the settlement includes stipulated future penalties for 
failure to comply with the terms of the agreement, including specific 
provisions related to meeting 

                                      55
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

construction deadlines associated with the installation of additional 
emission control equipment and complying with particulate, SO2 and NOx 
emissions limitations.


CRAIG STEAM ELECTRIC GENERATING STATION

    On October 9, 1996, a conservation organization filed a complaint in the 
U.S. District Court pursuant to provisions of the Federal Clean Air Act (the 
"Act") against the joint owners of the Craig Steam Electric Generating 
Station. Tri-State is the operator of the Craig station and the Company owns 
an undivided interest (acquired in April 1992) in each of two units at the 
station totaling approximately 9.7%.  The plaintiff alleged that: 1) the 
station exceeded the 20% opacity limitations in excess of 14,000 six minute 
intervals during the period extending from the first quarter of 1991 through 
the second quarter of 1996, and 2) 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 Act provides for penalties of up to $25,000 per day per 
violation, but the level of penalties imposed in any particular instance is 
discretionary.  The Company does not believe that its potential liability or 
the future impact of this litigation on plant operations will have a material 
impact on the Company's results of operations, financial position or cash 
flows.


VALMONT STEAM ELECTRIC GENERATING STATION

    On July 1, 1996, the Company received a Notice of Violation ("NOV") from 
the CDPHE which alleges inadequate reporting of NOx and SO2 information and 
excess NOx emissions at the Valmont Steam Electric Generating Station for the 
period January 1, 1995 through August 22, 1995.  The Company has responded to 
the NOV and believes that the amount of penalties, if any, that may result 
from such alleged violations would not have a material impact on the 
Company's results of operations, financial position or cash flows.


PURCHASE REQUIREMENTS

COAL PURCHASES AND TRANSPORTATION

    At December 31, 1996, the Company had in place long-term contracts for 
the purchase of coal through 2017.  The minimum remaining quantities to be 
purchased under these contracts total 78 million tons.  The coal purchase 
prices are subject to periodic adjustment for inflation and market 
conditions.  Total estimated obligations, based on current prices, were 
approximately $678 million at December 31, 1996.

    The Company has entered into long-term contracts for the transportation 
of coal by railroad in Company-owned or leased railcars to existing power 
plants. These agreements, expiring in 2000, provide for a minimum remaining 
transport quantity of 15 million tons.  Contract prices for coal 
transportation are negotiated based on market conditions and are adjusted 
periodically for inflation and operating factors.  Total estimated 
obligations, based on current prices, were approximately $31 million at 
December 31, 1996.


NATURAL GAS PURCHASES AND TRANSPORTATION 

    The Company and Cheyenne have entered into long-term contracts for the 
purchase, firm transportation and storage of natural gas.  These contracts, 
excluding the thirty year contract with Young Storage which has been 
accounted for as a capital lease, expire on various dates through 2002.  
During 1996, the Company renegotiated contracts with its primary gas pipeline 
supplier and committed to continue purchasing firm transportation and gas 
storage services through 2002.  At December 31, 1996, the Company and 
Cheyenne have minimum obligations under such contracts of approximately $123 
million in 1997 declining thereafter for a total estimated commitment of 
approximately $516 million.

                                      56

<PAGE>

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

PURCHASED POWER 

    The Company and Cheyenne have entered into agreements with utilities and 
QFs for purchased power to meet system load and energy requirements, replace 
generation from Company-owned units under maintenance and during outages, and 
meet the Company's operating reserve obligation to the Pool.

    The Company has various pay-for-performance contracts with QFs having 
expiration dates through the year 2022.  In general, these contracts provide 
for capacity payments, subject to the QFs meeting certain contract 
obligations, and energy payments based on actual power taken under the 
contracts.  The capacity and energy costs are recovered through base rates, 
the ECA/ICA and the QFCCA. Additionally, the Company and Cheyenne have 
long-term purchased power contracts with various regional utilities expiring 
through 2018.  In general, these contracts provide for capacity and energy 
payments which approximate the cost of the sellers.  Total capacity and 
energy payments associated with such contracts were $453 million, $445 
million, and $427 million in 1996, 1995 and 1994, respectively.

    At December 31, 1996, the estimated future payments for capacity that the 
Company and Cheyenne are obligated to purchase, subject to availability, are 
as follows:

                                            REGIONAL
                                QFS        UTILITIES         TOTAL
                            ----------     ----------     ----------
                                      (THOUSANDS OF DOLLARS)

    1997..................  $  143,236     $  180,896     $  324,132
    1998..................     143,502        184,701        328,203
    1999..................     143,827        175,662        319,489
    2000..................     141,910        164,994        306,904
    2001..................     140,438        143,894        284,332
    2002 and thereafter...   1,000,001      1,270,872      2,270,873
                            ----------     ----------     ----------
      Total...............  $1,712,914     $2,121,019     $3,833,933
                            ----------     ----------     ----------
                            ----------     ----------     ----------

    Historically, all minimum coal, coal transportation, natural gas and 
purchased power requirements have been met.


OTHER PURCHASES 

    Commitments made for the purchase of materials, plant and equipment 
additions, DSM expenditures and other various items aggregated approximately 
$478 million at December 31, 1996.


EMPLOYEE LITIGATION

    Several employee lawsuits have been filed against the Company involving 
alleged discrimination and breach of certain fiduciary duties to employees.  
The Company is actively contesting all such lawsuits and believes that the 
ultimate outcome will not have a material impact on the Company's results of 
operations, financial position or cash flow.

    On August 13, 1996, eighty-eight former Information Technology and 
Systems ("IT&S") employees filed a lawsuit against the Company.  The 
complaint, which was subsequently amended to add two other former IT&S 
employees, alleges that the Company unfairly amended its severance plan in 
connection with a restructuring in late 1994 to exclude the IT&S 
function/positions that were outsourced to IBM, effective February 1, 1995.  
The Company believes that the amended severance plan is lawful and 
enforceable and believes that the ultimate outcome of the lawsuit will not 
have a material impact on the Company's results of operations, financial 
position or cash flows.

    On July 19, 1996, a class action complaint was filed by fourteen 
plaintiffs allegedly on behalf of all non-managerial, non-clerical women in 
the Company's regional facilities. The complaint asserts that the Company has 

                                      57 
<PAGE>

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

engaged in company-wide pattern and practice of sexual discrimination, 
including sexual harassment and retaliation. A previous class complaint filed 
by some of these plaintiffs along with other named plaintiffs, was withdrawn 
after the Company filed its response. It is too early to predict the outcome 
of the class action complaint. The Company intends to actively contest the 
class action and believes the ultimate outcome of the individual plaintiffs' 
cases will not have a material impact on the Company's results of operations, 
financial position or cash flows.

    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.  A jury entered verdicts adverse to the 
Company in two cases which were subsequently appealed by the Company.  On 
February 6, 1997, the Colorado Court of Appeals issued a decision on all 
issues in favor of the Company.  The employees can appeal the decision of the 
Colorado Court of Appeals to the Colorado Supreme Court.  The Company 
believes that the ultimate outcome of the lawsuit will not have a material 
impact on the Company's results of operations, financial position or cash 
flow.


UNION CONTRACTS

    In late December 1995, the Company's contracts with the International 
Brotherhood of Electrical Workers, Local 111 ("IBEW Local 111") expired. 
Previously, an arbitrator had rejected the Company's attempt to terminate the 
contracts on the expiration dates.  Therefore, negotiation of limited issues 
was reopened.  The parties were unable to reach agreement on the contract 
issues reopened through the negotiation process and, as a result, the Company 
and IBEW Local 111 entered into binding arbitration on March 20, 1996, as 
required under the contracts.  On June 4, 1996, the arbitrator ruled that the 
Operations, Production and Maintenance ("OP&M") collective bargaining 
agreement with the Union would continue until May 31, 1997 and that the 
employees covered by the agreement would receive a wage increase of 3.5% 
retroactive to December 1995. Such amount had been previously accrued.  
Subsequent to the arbitrator's decision on the OP&M agreement, the Company 
and IBEW Local 111 came to an agreement on the Meter Reader, Order Reader and 
Field Credit Representative contract with a contract term and a wage increase 
consistent with the OP&M agreement.  At December 31, 1996, approximately 
2,090 employees, or 45% of the Company's total workforce, are represented by 
IBEW Local 111.

    On June 21, 1996, the National Labor Relations Board ordered the Company 
to reinstate approximately 150 union employees laid off or moved to other 
positions in the 1994 restructuring.  The Company was ordered to make whole, 
with interest, any net loss of earnings or other benefits since the layoff.  
Thirty-two employees were reinstated and, while the final costs associated 
with the order have not been determined, the Company accrued $2.0 million 
during 1996 related to this obligation.  

     In addition, IBEW Local 111 filed several grievances during 1996 
relating to the employment of certain non-union personnel to perform services 
for the Company.  A decision has been entered on three of the multiple 
grievances, with two of those decisions requiring that the Company pay union 
wage rates on new construction jobs performed by outside vendors.  The 
Company has filed suit seeking to reverse one of these decisions and 
challenging the subcontracting provision of the labor agreement, all of the 
outstanding subcontracting grievances and both of the existing adverse 
decisions as violations of federal law.  The Company and the union have 
entered into negotiations to resolve this dispute over contracting.  A 
decision is expected in March 1997.


LEASING PROGRAM

    The Company and its subsidiaries lease various equipment and facilities 
used in the normal course of business, some of which are accounted for as 
capital leases.  Expiration of the capital leases range from 1998 to 2025.  
The net book value of property under capital leases was $49.2 million and 
$53.7 million at December 31, 1996, and 1995, respectively.  Assets acquired 
under capital leases are recorded as property at the lower of fair-market 
value or the present value of future lease payments, and are amortized over 
their actual contract term in 

                                      58 
<PAGE>

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

accordance with practices allowed by the CPUC. The related obligation is 
classified as long-term debt.  Executory costs are excluded from the minimum 
lease payments.

    The majority of the operating leases are under a leasing program that has 
initial noncancellable terms of one year, while the remaining leases have 
various terms. These leases may be renewed or replaced. No material 
restrictions exist in these leasing agreements concerning dividends, 
additional debt, or further leasing. Rental expense for 1996, 1995 and 1994 
was $25.0 million, $23.5 million and $29.7 million, respectively.

    Estimated future minimum lease payments at December 31, 1996 are as 
follows:

                                                     CAPITAL     OPERATING
                                                      LEASES      LEASES 
                                                    --------     ---------
                                                    (THOUSANDS OF DOLLARS)

1997..............................................  $  9,585     $ 20,790
1998..............................................     9,392       20,947
1999..............................................     7,903       18,019
2000..............................................     5,097       16,129
2001..............................................     5,035       11,880
All years thereafter..............................    81,177       20,489
                                                    --------     ---------
  Total future minimum lease payments.............   118,189     $108,254
                                                                 ---------
                                                                 ---------
  Less amounts representing interest..............    69,035
                                                    --------
  Present value of net minimum lease payments.....  $ 49,154
                                                    --------
                                                    --------

    The Company has in place a leasing program which includes a provision 
whereby the Company indemnifies the lessor for all liabilities which might 
arise from the acquisition, use, or disposition of the leased property.


10. JOINTLY-OWNED ELECTRIC UTILITY PLANTS

    The Company's investment in jointly-owned plants and its ownership 
percentages as of December 31, 1996 is:

<TABLE>
                                                        PLANT                       CONSTRUCTION
                                                          IN        ACCUMULATED        WORK IN
                                                       SERVICE      DEPRECIATION      PROGRESS       OWNERSHIP %
                                                      --------     -------------    ------------     -----------
                                                                   (THOUSANDS OF 
                                                                      DOLLARS)
<S>                                                   <C>             <C>              <C>           <C>
  Hayden Unit 1....................................   $ 38,213        $ 29,860         $1,526            75.50
  Hayden Unit 2....................................     58,211          32,873            300            37.40
  Hayden Common Facilities.........................      2,117             392          3,287            53.10
  Craig Units 1 & 2................................     57,057          23,352            647             9.72
  Craig Common Facilities Units 1 & 2..............      7,714           3,033            958             9.72
  Craig Common Facilities Units 1, 2 & 3...........      8,371           3,310            407             6.47
  Transmission Facilities, Including Substations...     79,166          22,105             95        42.0-73.0
                                                      --------        --------         ------
                                                      $250,849        $114,925         $7,220
                                                      --------        --------         ------
                                                      --------        --------         ------
</TABLE>

    These assets include approximately 320 Mw of net dependable generating 
capacity.  The Company is responsible for its proportionate share of 
operating expenses (reflected in the consolidated statements of income) and 
construction expenditures.


                                      59 

<PAGE>
                                      
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

11. EMPLOYEE BENEFITS 

PENSIONS 

    The Company and Cheyenne maintain a noncontributory defined benefit 
pension plan covering substantially all employees.  

    The net pension expense in 1996, 1995 and 1994 was comprised of:

<TABLE>
                                                       1996         1995       1994
                                                     --------    ---------   --------
                                                          (THOUSANDS OF DOLLARS)
<S>                                                  <C>         <C>         <C>
Service cost......................................   $ 14,317    $  11,659   $ 16,169
Interest cost on projected benefit obligation.....     46,497       46,570     45,518
Actual return on plan assets......................    (74,646)    (123,531)     5,844
Amortization of net transition asset..............     (3,674)      (3,674)    (3,674)
Other items.......................................     24,362       75,521    (56,996)
                                                     --------    ---------   --------
      Net pension expense.........................   $  6,856    $   6,545   $  6,861
                                                     --------    ---------   --------
                                                     --------    ---------   --------
</TABLE>

    The pension plan was amended in 1994 (as discussed below) requiring the 
use of two sets of assumptions in the calculation of the 1994 net periodic 
pension cost.  Significant assumptions used in determining net periodic 
pension cost were:

<TABLE>
                                                                       APR - DEC   JAN - MAR
                                                       1996     1995      1994       1994
                                                       ----     ----   ---------   ---------
<S>                                                    <C>      <C>       <C>        <C>
Discount rate.......................................   7.25%    8.75%      8.0%       7.5%
Expected long-term increase in compensation level...   4.0 %    5.0 %      5.0%       5.0%
Expected weighted average long-term rate 
  of return on assets...............................   9.75%    9.75%     10.5%      10.5%
</TABLE>

    Variances between actual experience and assumptions for costs and returns 
on assets are amortized over the average remaining service lives of employees 
in the plan. 

    A comparison of the actuarially computed benefit obligations and plan 
assets at December 31, 1996 and 1995, is presented in the following table.  
Plan assets are stated at fair value and are comprised primarily of corporate 
debt and equity securities, a real estate fund and government securities held 
either directly or in commingled funds.  The Company and Cheyenne's funding 
policy is to contribute annually, at a minimum, the amount necessary to 
satisfy the IRS funding standards.

                                                             1996        1995
                                                          ---------   ---------
                                                          (THOUSANDS OF DOLLARS)
Actuarial present value of benefit obligations:
  Vested................................................  $ 514,762   $ 523,539
  Nonvested.............................................     28,689      31,678
                                                          ---------   ---------
                                                            543,451     555,217
Effect of projected future salary increases.............     85,216      91,810
                                                          ---------   ---------

Projected benefit obligation for service 
  rendered to date......................................    628,667     647,027

Plan assets at fair value...............................   (634,967)   (588,314)
                                                          ---------   ---------
Projected benefit obligation in excess of 
  plan assets...........................................      6,300     (58,713)
Unrecognized net loss...................................      1,110      62,092
Prior service cost not yet recognized in net 
  periodic pension cost.................................     27,758      30,063
Unrecognized net transition asset at January 1, 1986, 
  being recognized over 17 years........................    (22,042)    (25,716)
                                                          ---------   ---------

Prepaid pension asset...................................  $  13,126   $   7,726
                                                          ---------   ---------
                                                          ---------   ---------

                                     60 
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

    Significant assumptions used in determining the benefit obligations at 
the end of each respective year were:

                                                             1996        1995
                                                          ---------   ---------
Discount rate...........................................      7.75%       7.25%
Expected long-term increase in compensation level.......      4.25%        4.0%

    On January 25, 1994, the Board of Directors approved an amendment to the 
Plan which offered an incentive for early retirement for employees age 55 or 
older with 20 years of service as well as a Severance Enhancement Program 
("SEP") option for these same eligible employees for the period February 4, 
1994 to April 1, 1994.  The Plan amendment generally provided for the 
following retirement enhancements: a) unreduced early retirement benefits, b) 
three years of additional credited service, and c) a supplement of either a 
one-time payment equal to $400 for each full year of service to be paid from 
general corporate funds or a $250 social security supplement each month up to 
age 62 to be paid by the Plan.

    The SEP provided for: a) a one-time severance ranging from $20,000 - 
$90,000, depending on an employee's organization level, b) a continuous years 
of service bonus (up to 30 years), and c) a cash benefit of $10,000.

    Approximately 550 employees elected to participate in the early 
retirement/severance enhancement program, of which approximately 370 
employees elected the early retirement benefit.  The total cost of the 
program was approximately $39.7 million.  These costs were deferred and, 
effective April 1, 1994, are being amortized to expense over approximately 
4.5 years in accordance with rate regulatory treatment.  This amortization 
period represents the participants' average remaining years of service to 
their expected retirement date.

INVOLUNTARY SEVERANCE PROGRAM

    During 1994, in a continuing effort to lower operating costs, the Company 
implemented an involuntary severance program which reduced management and 
staff levels by approximately 550 employees.  Approximately $10.7 million of 
involuntary severance costs were accrued, of which $8.7 million reduced 
pre-tax earnings.

POSTRETIREMENT BENEFITS OTHER THAN PENSIONS 

    The Company and Cheyenne provide certain health care and life insurance 
benefits for retired employees.  A significant portion of the employees 
become eligible for these benefits if they reach either early or normal 
retirement age while working for the Company or Cheyenne.  Historically, the 
Company has recorded the cost of these benefits on a pay-as-you-go basis, 
consistent with the regulatory treatment.  Effective January 1, 1993, the 
Company and Cheyenne adopted SFAS 106 costs based on the level of expense 
determined in accordance with the CPUC and WPSC.  SFAS 106 requires the 
accrual, during the years that an employee renders service to the Company, of 
the expected cost of providing postretirement benefits other than pensions to 
the employee and the employee's beneficiaries and covered dependents.

    The Company is transitioning to full accrual accounting for OPEB costs 
between January 1, 1993 and December 31, 1997, consistent with the accounting 
requirements for rate regulated enterprises.  All OPEB costs deferred during 
the transition period will be amortized on a straight line basis over the 
subsequent 15 years. Effective December 1, 1993, the Company began recovering 
such costs as provided in the Fort St. Vrain Supplemental Settlement 
Agreement. On January 13, 1995, the CPUC approved the 1994 revision to the 
Supplemental Settlement Agreement, which accelerated the recovery of OPEB 
costs to comply with SFAS 106 and approved other changes to certain 
ratemaking principles.  The change in recovery was retroactive to January 1, 
1994, and accordingly, resulted in an increased OPEB expense for that year 
and subsequent years. 

                                     61 
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

    The Company filed a FERC rate case in December 1995 which included a 
request for approval to recover all electric wholesale jurisdiction SFAS 106 
costs (see Note 9.).  Effective January 1, 1993, Cheyenne began recovering 
SFAS 106 costs as approved by the WPSC.  The Company and Cheyenne fund SFAS 
106 costs in external trusts based on the amounts reflected in 
cost-of-service, consistent with the respective rate orders.

    The net periodic postretirement benefit cost in 1996, 1995 and 1994  
under SFAS 106 was comprised of:

<TABLE>
                                                       1996        1995        1994
                                                     --------    --------    --------
                                                          (THOUSANDS OF DOLLARS)
<S>                                                  <C>         <C>         <C>
Service cost......................................   $  6,928    $  6,027    $  6,101
Interest cost on projected benefit 
  obligation......................................     22,982      24,761      24,111
Return on plan assets.............................     (4,500)     (2,578)       (938)
Amortization of net transition obligation 
  at January 1, 1993 assuming a 20 year 
  amortization period.............................     12,710      12,710      12,710
                                                     --------    --------    --------

Net postretirement benefit cost required 
  by SFAS 106.....................................     38,120      40,920      41,984
OPEB expense recognized in accordance with 
  current regulation..............................    (31,271)    (30,893)    (30,266)
                                                     --------    --------    --------
Increase in regulatory asset (Note 1).............      6,849      10,027      11,718
Regulatory asset at beginning of year.............     47,600      37,573      25,855
                                                     --------    --------    --------
Regulatory asset at end of year...................   $ 54,449    $ 47,600    $ 37,573
                                                     --------    --------    --------
                                                     --------    --------    --------
</TABLE>

    Significant assumptions used in determining net periodic postretirement 
benefit cost were:

<TABLE>
                                                                   APR - DEC   JAN - MAR
                                               1996       1995        1994        1994  
                                               ----       ----     ---------   ---------
<S>                                            <C>        <C>        <C>         <C>
Discount rate...............................   7.25%      8.75%       8.0%        7.5%
Expected long-term increase in 
  compensation level........................   4.0 %      5.0 %       5.0%        5.0%
Expected weighted average long-term 
  rate of return on assets..................   9.75%      9.75%      10.5%       10.5%
</TABLE>

    A comparison of the actuarially computed benefit obligations and plan 
assets at December 31, 1996 and 1995 is presented in the following table.  
Plan assets are stated at fair value and are comprised primarily of corporate 
debt and equity securities, a real estate fund, government securities and 
other short-term investments held either directly or in commingled funds.

                                                        1996       1995
                                                     ---------   ---------
                                                     (THOUSANDS OF DOLLARS)
Accumulated postretirement benefit obligation:
    Retirees and eligible beneficiaries...........   $ 110,692   $ 122,395
    Other fully eligible plan participants........      81,676      93,161
    Other active plan participants................      90,559     102,739
                                                     ---------   ---------
      Total.......................................     282,927     318,295
Plan assets at fair value.........................     (63,744)    (41,129)
                                                     ---------   ---------

Accumulated benefit obligation in excess of 
  plan assets.....................................     219,183     277,166
Unrecognized net gain (loss)......................      39,847     (11,905)
Unrecognized transition obligation................    (203,353)   (216,063)
                                                     ---------   ---------
Accrued postretirement benefit obligation.........   $  55,677   $  49,198
                                                     ---------   ---------
                                                     ---------   ---------

    Significant assumptions used in determining the accumulated 
postretirement benefit obligation at the end of each respective year were: 

                                                        1996       1995
                                                     ---------   ---------
Discount rate.....................................       7.75%        7.25%
Ultimate health care cost trend rate..............       5.0 %        4.5 %
Expected long-term increase in 
  compensation level..............................       4.0 %        4.0 %

    The assumed health care cost trend rate for 1997 is 9.0%, decreasing to 
4.5% in 2006 in 0.5% annual increments.  A 1% increase in the assumed health 
care cost trend will increase the estimated total accumulated 

                                     62 
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

benefit obligation by $35.1 million, and the service and interest cost 
components of net periodic postretirement benefit costs by $5.1 million.

POSTEMPLOYMENT BENEFITS 

    The Company and Cheyenne adopted SFAS 112 on January 1, 1994, the 
effective date of the statement. SFAS 112 establishes the accounting 
standards for employers who provide benefits to former or inactive employees 
after employment but before retirement (postemployment benefits).  At 
December 31, 1996 and 1995, the Company had recorded a $24.8 million and 
$23.5 million regulatory asset and a corresponding liability on the 
consolidated balance sheet, assuming a 7.75% and an 7.25% discount rate, 
respectively.  The Company has historically recorded these costs on a 
pay-as-you-go basis.  The Company filed a FERC rate case in December 1995 and 
a retail gas rate case in June 1996 which included a request for recovery of 
all electric wholesale and retail jurisdiction SFAS 112 costs. For discussion 
regarding the recovery of these costs, see Note 1 and Note 9.


INCENTIVE COMPENSATION 

    The Omnibus Incentive Plan ("OIP") provides for annual and long-term 
incentive awards for officers and management employees.  One million shares 
of common stock have been authorized for awards under the OIP as it allows 
for the issuance of restricted shares and/or stock options.  The Company 
recognizes compensation expense for restricted stock awards based on the fair 
value of the Company's common stock on the date of grant, consistent with 
SFAS 123.  Cash, restricted stock awards (restrictions lapse two years from 
the grant date) and stock option awards (which vest ratably during a 
three-year period) were made under the OIP during 1996, 1995 and 1994.  

    As allowed in SFAS 123, the Company applies APB Opinion No. 25 in 
accounting for its stock-based compensation and, accordingly, no compensation 
cost is recognized for the issuance of stock options as the exercise price of 
the options equals the fair-market value of the Company's common stock at the 
date of grant. Assuming compensation cost for stock options granted in 1996 
and 1995 had been determined consistent with SFAS 123 using the fair-value 
based method, the Company's reported net income would have been reduced by 
$0.3 million in 1996 and $0.2 million in 1995 which would not have impacted 
reported earnings per share for 1996 and 1995. SFAS 123's method of 
accounting for stock-based compensation plans has not been applied to options 
granted prior to January 1, 1995 and as a result the pro forma compensation 
cost may not be representative of that to be expected in future years.

    A summary of the Company's stock options at December 31, 1996, 1995 and 
1994 and changes during the years then ended is presented in the table below:

<TABLE>
                                                1996                       1995                        1994 
                                     -------------------------   ------------------------   -------------------------
                                                   WEIGHTED-                  WEIGHTED-                   WEIGHTED-
                                                    AVERAGE                    AVERAGE                     AVERAGE
                                     SHARES     EXERCISE PRICE   SHARES    EXERCISE PRICE   SHARES     EXERCISE PRICE
                                     -------    --------------   -------   --------------   -------    --------------
<S>                                  <C>            <C>          <C>           <C>          <C>            <C>       
Outstanding at beginning of year     347,931        $29.33       195,744       $28.53        58,544        $28.13 
Granted                              158,270        $35.13       161,000       $30.29       149,700        $28.73 
Exercised                            (51,673)       $30.21          (267)      $29.00             -        $    - 
Forfeited                            (13,301)       $32.84        (8,546)      $29.17       (12,500)       $29.00 
                                     -------                     -------                    ------- 
Outstanding at end of year           441,227        $31.38       347,931       $29.33       195,744        $28.53 
                                     -------                     -------                    ------- 
Exercisable at end of year           158,970        $29.05       125,931       $28.52        19,515        $28.13 
                                     -------                     -------                    ------- 
                                     -------                     -------                    ------- 
Weighted-average fair value of options granted      $ 4.31                     $ 5.39
</TABLE>

                                     63 

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

  The fair value of each option grant is estimated on the date of grant using 
the Black-Scholes Option-Pricing Model with the following weighted-average 
assumptions:

                                                          1996           1995
                                                        --------       --------
Expected  option life...........................        10 years       10 years
Stock volatility................................        11.95%         16.11%
Risk-free interest rate.........................         6.21%          7.45%
Dividend yield..................................         5.8 %          6.6 %

    The Employee Incentive Plan ("EIP") provides for cash awards to all 
employees based on the achievement of corporate goals.  Certain performance 
goals were met in each of the last three years.

    The expenses accrued under the OIP and the EIP totaled approximately $7.8 
million in 1996, $6.4 million in 1995 and $6.0 million in 1994.

    In the event that the Company is subject to a change in control, all 
stock-based awards, such as options and restricted shares, will vest 100% and 
all performance awards will be paid out immediately in cash, as if the 
performance objectives have been obtained through the effective date of the 
change in control.  The Merger, when effective, qualifies as a change in 
control condition.


12. FINANCIAL INSTRUMENTS 

FAIR VALUE OF FINANCIAL INSTRUMENTS 

    The following table presents the carrying amounts and fair values of the 
Company's and subsidiaries' significant financial instruments at December 31, 
1996 and 1995.  The carrying amount of all other financial instruments 
approximates fair value.  SFAS 107 defines the fair value of a financial 
instrument as the amount at which the instrument could be exchanged in a 
current transaction between willing parties, other than in a forced or 
liquidation sale.

<TABLE>
                                               1996                      1995
                                     -----------------------   -----------------------
                                      CARRYING        FAIR      CARRYING       FAIR
                                       AMOUNT        VALUE       AMOUNT       VALUE
                                     ----------   ----------   ----------   ----------
                                                   (THOUSANDS OF DOLLARS)
<S>                                  <C>          <C>          <C>          <C>
  Investments, at cost............   $   30,249   $   30,416   $    7,575   $    7,623
  Preferred stock subject to 
    mandatory redemption..........       42,489       43,685       43,865       45,184
  Long-term debt..................    1,370,423    1,404,972    1,229,231    1,307,128
</TABLE>

    The fair value of the debt and equity securities included in Investments, 
at cost, is estimated based on quoted market prices for the same or similar 
investments.  The debt securities are classified as held-to-maturity and the 
equity securities are classified as available-for-sale.  The unrealized 
holding gains and losses for these debt and equity securities are not 
significant.

    The estimated fair values of preferred stock subject to mandatory 
redemption and long-term debt are based on quoted market prices of the same 
or similar instruments.  Since the Company and Cheyenne are subject to 
regulation, any gains or losses related to the difference between the 
carrying amount and the fair value of these financial instruments would not 
be realized by the Company's shareholders.


OFF-BALANCE-SHEET FINANCIAL INSTRUMENTS

    YGSC, a wholly-owned subsidiary of e prime, and the Company have 
guaranteed 50% of amounts financed under a $32 million Credit Agreement among 
Young Gas and various lending institutions entered into on 


                                     64 
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

June 27, 1995. This debt financing is for the development, construction and 
operation of an underground natural gas storage facility in northeastern 
Colorado.

CONCENTRATION OF CREDIT RISK - ACCOUNTS RECEIVABLE

    No individual customer or group of customers engaged in similar 
activities represents a material concentration of credit risk to the Company 
and its subsidiaries.

13. INCOME TAXES

    The provisions for income taxes for the years ended December 31, 1996, 
1995 and 1994 consist of the following:

                                            1996      1995      1994
                                          -------   -------   -------
                                            (THOUSANDS OF DOLLARS) 
Current income taxes:
  Federal..............................   $41,737   $58,728   $22,081
  State................................       951     2,807    (2,016)
                                          -------   -------   -------
    Total current income taxes.........    42,688    61,535    20,065
                                          -------   -------   -------

Deferred income taxes:
  Federal..............................    53,612    38,006    31,042
  State................................     7,287     1,164     3,192
                                          -------   -------   -------
    Total deferred income taxes........    60,899    39,170    34,234
                                          -------   -------   -------

Investment tax credits - net...........    (7,256)   (5,348)   (5,799)
                                          -------   -------   -------

Total provision for income taxes.......   $96,331   $95,357   $48,500
                                          -------   -------   -------
                                          -------   -------   -------

    During 1994, as a result of a detailed analysis of the income tax 
accounts, the Company recorded a decrease in its income tax liabilities, 
which served to reduce Federal and state income tax expenses by approximately 
$21.3 million, or 34 cents per share.  The detailed analysis was completed in 
conjunction with the Company's implementation of the full normalization 
method of accounting for income taxes as provided for in a rate order from 
the CPUC.  

    A reconciliation of the statutory U.S. income tax rates and the effective
tax rates follows:

<TABLE>
                                                   1996               1995               1994
                                              ---------------    --------------    ---------------
                                                              (THOUSAND OF DOLLARS)
<S>                                           <C>        <C>     <C>       <C>     <C>        <C>
Tax computed at U.S. statutory rate on 
    pre-tax accounting income..............   $100,337   35.0%   $95,975   35.0%   $ 76,569   35.0%
Increase (decrease) in tax from:
  Allowance for funds used 
    during construction....................     (1,438)  (0.5)    (2,495)  (0.9)     (2,449)  (1.1)
  Amortization of investment tax credits...     (7,256)  (2.5)    (5,348)  (1.9)     (5,792)  (2.6)
  Cash surrender value of life
    insurance policies.....................    (11,265)  (3.9)    (9,546)  (3.5)     (7,643)  (3.5)
  Amortization of prior flow-through 
    amounts................................     10,509    3.6     10,509    3.8      10,509    4.8
  Tax accrual adjustment...................          -      -          -      -     (21,262)  (9.7)
  Other-net................................      5,444    1.9      6,262    2.3      (1,432)  (0.7)
                                              --------   ----    -------   ----    --------   ----
      Total income taxes...................   $ 96,331   33.6%   $95,357   34.8%   $ 48,500   22.2%
                                              --------   ----    -------   ----    --------   ----
                                              --------   ----    -------   ----    --------   ----
</TABLE>

    The Company and its regulated subsidiaries have historically provided for 
deferred income taxes to the extent allowed by their regulatory agencies 
whereby deferred taxes were not provided on all differences between financial 
statement and taxable income (the flow-through method).  To give effect to 
temporary differences for which deferred taxes were not previously required 
to be provided, a regulatory asset was recognized.  The regulatory asset 
represents temporary differences primarily associated with prior flow-through 
amounts and the equity component of allowance for funds used during 
construction, net of temporary differences related to 

                                     65 
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

unamortized investment tax credits and excess deferred income taxes that have 
resulted from historical reductions in tax rates (see Note 1).

    The tax effects of significant temporary differences representing deferred 
tax liabilities and assets as of December 31, 1996 and 1995 are as follows:

                                                       1996       1995
                                                     --------   --------
                                                    (THOUSANDS OF DOLLARS)
Deferred income tax liabilities:
  Accelerated depreciation and amortization.......   $412,047   $376,468
  Plant basis differences (prior flow-through)....    132,149    152,631
  Allowance for equity funds used during 
    construction..................................     48,952     50,411
  Pensions........................................     38,790     36,583
  Other...........................................     68,940     50,760
                                                     --------   --------
      Total.......................................    700,878    666,853
Deferred income tax assets:
  Investment tax credits..........................     65,278     69,751
  Contributions in aid of construction............     63,317     55,654
  Other...........................................     28,641     52,534
                                                     --------   --------
      Total.......................................    157,236    177,939
                                                     --------   --------
 Net deferred income tax liability................   $543,642   $488,914
                                                     --------   --------
                                                     --------   --------

    As of December 31, 1996, the Company has cumulative AMT carryforwards of 
approximately $3.8 million and state tax credit carryforwards of 
approximately $1.6 million.  A valuation allowance has not been recorded as 
the Company expects that all deferred income tax assets will be realized in 
the future.


















                                      66 
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

14. SEGMENTS OF BUSINESS 

<TABLE>
                   1996                            ELECTRIC       GAS      OTHER       TOTAL
                  ------                          ----------   --------   -------   ----------
                                                             (THOUSANDS OF DOLLARS)   

<S>                                               <C>          <C>        <C>       <C>
Operating revenues.............................   $1,488,990   $640,497   $41,899   $2,171,386
                                                  ----------   --------   -------   ----------
Operating expenses, excluding depreciation
  and income taxes.............................    1,006,904    549,223     5,813    1,561,940
Depreciation and amortization..................      116,801     35,735     2,095      154,631
                                                  ----------   --------   -------   ----------
    Total operating expenses*..................    1,123,705    584,958     7,908    1,716,571
                                                  ----------   --------   -------   ----------
Operating income*..............................      365,285     55,539    33,991      454,815
                                                  ----------   --------   -------   ----------
                                                  ----------   --------   -------   ----------
Plant construction expenditures**..............      223,395     96,842       925      321,162
                                                  ----------   --------   -------   ----------
                                                  ----------   --------   -------   ----------

Identifiable assets:
  Property, plant and equipment**..............    2,733,699    805,372    59,824    3,598,895
  Materials and supplies.......................       41,418      7,325       229       48,972
  Fuel inventory...............................       24,594          -       145       24,739
  Gas in underground storage...................            -     42,826         -       42,826
  Other corporate assets.......................                                        857,216
                                                                                    ----------
                                                                                    $4,572,648
                                                                                    ----------
                                                                                    ----------

                   1995
                  ------

Operating revenues.............................   $1,449,096   $624,585   $36,920   $2,110,601
                                                  ----------   --------   -------   ----------
Operating expenses, excluding depreciation
  and income taxes.............................    1,002,381    538,620     7,046    1,548,047
Depreciation and amortization..................      109,498     29,901     1,981      141,380
                                                  ----------   --------   -------   ----------
    Total operating expenses*..................    1,111,879    568,521     9,027    1,689,427
                                                  ----------   --------   -------   ----------
Operating income*..............................      337,217     56,064    27,893      421,174
                                                  ----------   --------   -------   ----------
                                                  ----------   --------   -------   ----------
Plant construction expenditures**..............      198,341     86,482       693      285,516
                                                  ----------   --------   -------   ----------
                                                  ----------   --------   -------   ----------

Identifiable assets:
  Property, plant and equipment**..............    2,645,045    777,420    58,247    3,480,712
  Materials and supplies.......................       47,636      8,886         3       56,525
  Fuel inventory...............................       35,509          -       145       35,654
  Gas in underground storage...................            -     44,900         -       44,900
  Other corporate assets.......................                                        733,998
                                                                                    ----------
                                                                                    $4,351,789
                                                                                    ----------
                                                                                    ----------

                   1994
                  ------

Operating revenues.............................   $1,399,836   $624,922   $32,626   $2,057,384
                                                  ----------   --------   -------   ----------
Operating expenses, excluding depreciation
  and income taxes (1).........................    1,032,396    558,929     7,732    1,599,057
Depreciation and amortization..................      107,769     29,078     2,188      139,035
                                                  ----------   --------   -------   ----------
    Total operating expenses*..................    1,140,165    588,007     9,920    1,738,092
                                                  ----------   --------   -------   ----------
Operating income*..............................      259,671     36,915    22,706      319,292
                                                  ----------   --------   -------   ----------
                                                  ----------   --------   -------   ----------
Plant construction expenditures**..............      223,773     91,492     1,873      317,138
                                                  ----------   --------   -------   ----------
                                                  ----------   --------   -------   ----------

Identifiable assets:
  Property, plant and equipment**..............    2,543,267    674,974    73,161    3,291,402
  Materials and supplies.......................       55,756     11,782        62       67,600
  Fuel inventory...............................       31,225          -       145       31,370
  Gas in underground storage...................            -     42,355         -       42,355
  Other corporate assets.......................                                        775,105
                                                                                    ----------
                                                                                    $4,207,832
                                                                                    ----------
                                                                                    ----------
</TABLE>

(1) Includes additional expense of approximately $43.4 million for defueling 
    and decommissioning.
*   Before income taxes.
**  Includes allocation of common utility property.



                                      67 
<PAGE>

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 

15. QUARTERLY FINANCIAL DATA (UNAUDITED) 

    The following summarized quarterly information for 1996 and 1995 is 
unaudited, but includes all adjustments (consisting only of normal recurring 
accruals) which the Company considers necessary for a fair presentation of 
the results for the periods. Information for any one quarterly period is not 
necessarily indicative of  the  results which may be expected for a 
twelve-month period due to seasonal and other factors.

<TABLE>
                                                                THREE MONTHS ENDED
                                                ---------------------------------------------------
                                                MARCH 31      JUNE 30    SEPTEMBER 30   DECEMBER 31
                                                --------      --------   ------------   -----------
                    1996                               (IN THOUSANDS-EXCEPT PER SHARE DATA)
                   ------
<S>                                             <C>           <C>          <C>            <C>
Operating revenues...........................   $622,917      $484,787     $476,861       $586,821
Operating income (1).........................   $104,846      $ 73,286     $ 88,222       $ 92,130
Net income...................................   $ 64,429      $ 34,537     $ 39,256       $ 52,124
Earnings available for common stock..........   $ 61,457      $ 31,566     $ 36,294       $ 49,181
Weighted average common shares outstanding...     63,679        63,998       64,324         64,748
Earnings per weighted average common share...   $   0.97      $   0.49     $   0.56       $   0.76

                    1995
                   ------

Operating revenues...........................   $620,596      $498,699     $468,453       $522,853
Operating income (1).........................   $ 91,689      $ 62,736     $ 82,736       $ 88,656
Net income...................................   $ 53,644      $ 28,255     $ 45,819       $ 51,138
Earnings available for common stock..........   $ 50,643      $ 25,255     $ 42,828       $ 48,167
Weighted average common shares outstanding...     62,513        62,846       63,077         63,291
Earnings per weighted average common share...   $   0.81      $   0.40     $   0.68       $   0.76
</TABLE>

(1) Operating income amounts have been restated to reflect the reclassification
    of Merger expenses from operating expenses to miscellaneous income and 
    deductions in accordance with FERC guidance received during the third 
    quarter of 1996. 










                                      68 
<PAGE>

                                                                     SCHEDULE II
                                       
                      PUBLIC SERVICE COMPANY OF COLORADO
                               AND SUBSIDIARIES
                                       
                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                                       
                 YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
                                       

<TABLE>
                                                                 ADDITIONS   
                                                           ---------------------
                                              BALANCE AT   CHARGED   CHARGED TO   DEDUCTIONS    BALANCE
                                              BEGINNING      TO        OTHER         FROM        AT END
                                              OF PERIOD    INCOME    ACCOUNTS(1)  RESERVES(2)   OF YEAR
                                              ---------------------------------------------------------
                                                                (THOUSANDS OF DOLLARS)
<S>                                             <C>         <C>         <C>         <C>      
Reserve deducted from related assets:
  Provision for uncollectible accounts:

    1996...................................     $3,630      $6,741      $477        $6,799      $4,049
                                                ------      ------      ----        ------      ------
                                                ------      ------      ----        ------      ------

    1995...................................     $3,173      $7,815      $  4        $7,362      $3,630
                                                ------      ------      ----        ------      ------
                                                ------      ------      ----        ------      ------

    1994...................................     $3,276      $8,533      $132        $8,768      $3,173
                                                ------      ------      ----        ------      ------
                                                ------      ------      ----        ------      ------
</TABLE>

    ----------------
(1) Uncollectible accounts subsequently recovered, transfers from customers' 
    deposit, etc.
(2) Uncollectible accounts written off.










                                       69
<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>
                                                                            YEAR ENDED DECEMBER 31,
                                                             ----------------------------------------------------
                                                               1996       1995       1994       1993       1992
                                                             --------   --------   --------   --------   --------
                                                                     (THOUSANDS OF DOLLARS, EXCEPT RATIOS)
<S>                                                          <C>        <C>        <C>        <C>        <C>
FIXED CHARGES:

  Interest on long-term debt...............................  $ 92,205   $ 85,832   $ 89,005   $ 98,089   $ 92,581
  Interest on borrowings against COLI contracts............    40,160     34,717     29,786     25,333     18,312
  Other interest...........................................    17,238     23,392     14,235      9,445     12,357
  Amortization of debt discount and expense less premium...     3,621      3,278      3,126      2,018      1,790
  Interest component of rental expense.....................    10,649      6,729      6,888      6,824      7,904
                                                             --------   --------   --------   --------   --------
      Total................................................  $163,873   $153,948   $143,040   $141,709   $132,944
                                                             --------   --------   --------   --------   --------
                                                             --------   --------   --------   --------   --------

EARNINGS (BEFORE FIXED CHARGES AND TAXES ON INCOME):
  Net income...............................................  $190,346    178,856   $170,269   $157,360   $136,623
  Fixed charges as above...................................   163,873    153,948    143,040    141,709    132,944
  Provisions for Federal and state taxes on income,
    net of investment tax credit amortization..............    96,331     95,357     48,500     60,994     53,149
                                                             --------   --------   --------   --------   --------
      Total................................................  $450,550    428,161   $361,809   $360,063   $322,716
                                                             --------   --------   --------   --------   --------
                                                             --------   --------   --------   --------   --------

RATIO OF EARNINGS TO FIXED CHARGES.........................      2.75       2.78       2.53       2.54       2.43
                                                             --------   --------   --------   --------   --------
                                                             --------   --------   --------   --------   --------
</TABLE>










                                       70
<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>
                                                                              YEAR ENDED DECEMBER 31,
                                                               ----------------------------------------------------
                                                                 1996       1995       1994       1993       1992 
                                                               --------   --------   --------   --------   --------
                                                                      (THOUSANDS OF DOLLARS, EXCEPT RATIOS)
<S>                                                            <C>        <C>        <C>        <C>        <C>     
FIXED CHARGES AND PREFERRED STOCK DIVIDENDS:

  Interest on long-term debt................................   $ 92,205   $ 85,832   $ 89,005   $ 98,089   $ 92,581
  Interest on borrowings against COLI contracts.............     40,160     34,717     29,786     25,333     18,312
  Other interest............................................     17,238     23,392     14,235      9,445     12,357
  Amortization of debt discount and expense less premium....      3,621      3,278      3,126      2,018      1,790
  Interest component of rental expense......................     10,649      6,729      6,888      6,824      7,904
  Preferred stock dividend requirement......................     11,848     11,963     12,014     12,031     12,077
  Additional preferred stock dividend requirement...........      5,995      6,377      3,422      4,662      4,699
                                                               --------   --------   --------   --------   --------
      Total.................................................   $181,716   $172,288   $158,476   $158,402   $149,720
                                                               --------   --------   --------   --------   --------
                                                               --------   --------   --------   --------   --------

EARNINGS (BEFORE FIXED CHARGES AND TAXES ON INCOME):
  Net income................................................   $190,346   $178,856   $170,269   $157,360   $136,623
  Interest on long-term debt................................     92,205     85,832     89,005     98,089     92,581
  Interest on borrowings against COLI contracts.............     40,160     34,717     29,786     25,333     18,312
  Other interest............................................     17,238     23,392     14,235      9,445     12,357
  Amortization of debt discount and expense less premium....      3,621      3,278      3,126      2,018      1,790
  Interest component of rental expense......................     10,649      6,729      6,888      6,824      7,904
  Provisions for Federal and state taxes on income,
    net of investment tax credit amortization...............     96,331     95,357     48,500     60,994     53,149
                                                               --------   --------   --------   --------   --------
      Total.................................................   $450,550   $428,161   $361,809   $360,063   $322,716
                                                               --------   --------   --------   --------   --------
                                                               --------   --------   --------   --------   --------

RATIO OF EARNINGS TO FIXED CHARGES
  AND PREFERRED STOCK DIVIDENDS.............................       2.48       2.49       2.28       2.27       2.16
                                                               --------   --------   --------   --------   --------
                                                               --------   --------   --------   --------   --------
</TABLE>





                                      71

<PAGE>

                                                                    EXHIBIT 99
                       NCE UNAUDITED PRO FORMA INFORMATION

     The following unaudited pro forma combined balance sheet at December 31, 
1996 gives effect to the Merger as if it had occurred at December 31, 1996. 
The unaudited pro forma combined statements of income for each of the three 
years ended December 31, 1996 give effect to the Merger as if it had occurred 
on January 1, 1994. These statements are prepared on the basis of accounting 
as required under a pooling of interests and do not reflect any cost savings 
or other synergies anticipated by management as a result of the Merger. 
Accordingly, the pro forma information is not necessarily indicative of the 
financial position or results of operations that would have occurred had the 
Merger been consummated for the periods for which it is given effect, nor is 
it necessarily indicative of future operating results or financial condition.

                           NEW CENTURY ENERGIES, INC. 
                   UNAUDITED PRO FORMA COMBINED BALANCE SHEET
                             (THOUSANDS OF DOLLARS)
                               DECEMBER 31, 1996

                                      ASSETS

<TABLE>
                                                            PSCO            SPS         PRO FORMA
                                                         -----------    -----------    -----------

<S>                                                       <C>            <C>            <C>
Property, plant and equipment, at cost:
  Electric.............................................  $ 3,931,413    $ 2,517,580    $ 6,448,993
  Gas  ................................................    1,035,394              -      1,035,394
  Steam................................................       17,476              -         17,476
  Other................................................       60,749         37,541         98,290
  Common to all departments............................      418,262              -        418,262
  Construction in progress.............................      181,597         79,346        260,943
                                                         -----------    -----------    -----------
                                                           5,644,891      2,634,467      8,279,358
  Less: accumulated depreciation.......................    2,045,996        944,279      2,990,275
                                                         -----------    -----------    -----------
      Total property, plant and equipment..............    3,598,895      1,690,188      5,289,083
                                                         -----------    -----------    -----------

Investments, at cost, and receivables..................       46,550         34,446         80,996

Current assets:
  Cash and temporary cash investments..................        9,406         40,609         50,015
  Accounts receivable - net............................      218,132         67,780        285,912
  Accrued unbilled revenues............................       85,894         20,304        106,198
  Recoverable purchased gas and electric energy costs..       31,288         15,715         47,003
  Materials and supplies, at average cost..............       48,972         17,776         66,748
  Fuel inventory, at average cost......................       24,739          2,320         27,059
  Gas in underground storage, at cost (LIFO)...........       42,826              -         42,826
  Regulatory assets recoverable within one year........       44,110              -         44,110
  Prepaid expenses and other...........................       41,790          7,469         49,259
                                                         -----------    -----------    -----------
      Total current assets.............................      547,157        171,973        719,130
                                                         -----------    -----------    -----------

Deferred charges:
  Regulatory assets....................................      304,456        107,834        412,290
  Unamortized debt expense.............................       10,975          9,864         20,839
  Other................................................       64,615         30,489         95,104
      Total deferred charges...........................      380,046        148,187        528,233
                                                         -----------    -----------    -----------
                                                         $ 4,572,648    $ 2,044,794    $ 6,617,442
                                                         -----------    -----------    -----------
                                                         -----------    -----------    -----------
</TABLE>


   The accompanying notes to unaudited pro forma combined balance sheet and 
         statements of income are an integral part of this statement.



                                     72

<PAGE>

                           NEW CENTURY ENERGIES, INC. 
                   UNAUDITED PRO FORMA COMBINED BALANCE SHEET
                             (THOUSANDS OF DOLLARS)
                               DECEMBER 31, 1996


                            CAPITAL AND LIABILITIES

<TABLE>
                                                                         PSCO          SPS        PRO FORMA
                                                                     -----------   -----------   ----------- 
<S>                                                                  <C>           <C>            <C>
Common stock (2)................................................... $   324,094     $   40,918   $   103,691 
Paid in capital (2)................................................     724,353        307,484     1,293,158 
Retained earnings (5)..............................................     389,841        383,350       764,646 
                                                                    -----------    -----------   ----------- 
      Total common equity..........................................   1,438,288        731,752     2,161,495 

Preferred stock:
  Not subject to mandatory redemption..............................     140,008              -       140,008 
  Subject to mandatory redemption at par...........................      39,913              -        39,913 
Long-term debt.....................................................   1,259,528        720,400     1,979,928 
                                                                    -----------    -----------   ----------- 
                                                                      2,877,737      1,452,152     4,321,344 
                                                                    -----------    -----------   ----------- 

Noncurrent liabilities:
  Employees' postretirement benefits other than pensions...........      55,677          2,967        58,644 
  Employees' postemployment benefits...............................      25,182          2,369        27,551 
                                                                    -----------    -----------   ----------- 
      Total noncurrent liabilities.................................      80,859          5,336        86,195 
                                                                    -----------    -----------   ----------- 

Current liabilities:
  Notes payable and commercial paper...............................     244,725         53,836       298,561 
  Long-term debt due within one year...............................     155,030         15,231       170,261 
  Preferred stock subject to mandatory redemption within one year..       2,576              -         2,576 
  Accounts payable.................................................     254,256         63,004       317,260 
  Dividends payable................................................      36,973              -        36,973 
  Customers' deposits..............................................      21,441          5,842        27,283 
  Accrued taxes....................................................      58,990         19,999        78,989 
  Accrued interest.................................................      33,797         13,151        46,948 
  Current portion of defueling and decommissioning liability.......       8,665              -         8,665 
  Current portion of accumulated deferred income taxes.............       4,560          3,583         8,143 
  Merger costs (5).................................................           -              -         8,545 
  Other............................................................      69,203         28,503        97,706 
                                                                    -----------    -----------   ----------- 
      Total current liabilities....................................     890,216        203,149     1,101,910 
                                                                    -----------    -----------   ----------- 

Deferred credits:
  Customers' advances for construction.............................      50,269            366        50,635 
  Unamortized investment tax credits...............................     105,928          5,719       111,647 
  Accumulated deferred income taxes................................     539,082        367,272       906,354 
  Other............................................................      28,557         10,800        39,357 
                                                                    -----------    -----------   ----------- 
      Total deferred credits.......................................     723,836        384,157     1,107,993 
                                                                    -----------    -----------   ----------- 
                                                                    $ 4,572,648    $ 2,044,794   $ 6,617,442 
                                                                    -----------    -----------   ----------- 
                                                                    -----------    -----------   ----------- 
</TABLE>


   The accompanying notes to unaudited pro forma combined balance sheet and 
         statements of income are an integral part of this statement.



                                     73


<PAGE>

                          NEW CENTURY ENERGIES, INC.
               UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME
                 (THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA)
                          YEAR ENDED DECEMBER 31, 1996

<TABLE>
                                                                       PSCO         SPS        PRO FORMA
                                                                  -----------   -----------   -----------
<S>                                                                <C>           <C>           <C>
Operating revenues:
  Electric....................................................... $ 1,488,990   $   927,549   $ 2,416,539 
  Gas............................................................     640,497             -       640,497 
  Other..........................................................      41,899             -        41,899 
                                                                  -----------   -----------   -----------
                                                                    2,171,386       927,549     3,098,935 
Operating expenses:
  Fuel used in generation........................................     195,442       439,838       635,280 
  Purchased power................................................     490,428        20,154       510,582 
  Gas purchased for resale.......................................     393,163             -       393,163 
  Other operating expenses.......................................     336,100       113,123       449,223 
  Maintenance....................................................      63,908        34,376        98,284 
  Depreciation and amortization..................................     154,631        65,864       220,495 
  Taxes (other than income taxes)................................      82,899        45,306       128,205 
  Income taxes...................................................      96,331        57,322       153,653 
                                                                  -----------   -----------   -----------
                                                                    1,812,902       775,983     2,588,885 
                                                                  -----------   -----------   -----------
Operating income.................................................     358,484       151,566       510,050 

Other income and deductions:
  Allowance for equity funds used during construction............         757           179           936 
  Miscellaneous income and deductions - net......................     (19,015)       (5,018)      (24,033) 
                                                                  -----------   -----------   -----------
                                                                      (18,258)       (4,839)      (23,097)

Interest charges:
  Interest on long-term debt.....................................      92,205        46,096       138,301 
  Amortization of debt discount and expense less premium.........       3,621         2,145         5,766 
  Other interest.................................................      57,398         5,597        62,995 
  Allowance for borrowed funds used during construction..........      (3,344)       (2,601)       (5,945) 
  Dividend requirements on preferred stock of subsidiaries.......           -         1,526        13,495 
                                                                  -----------   -----------   -----------
                                                                      149,880        52,763       214,612 
                                                                  -----------   -----------   -----------
Net income.......................................................     190,346        93,964       272,341 
Dividend requirements on preferred stock.........................      11,848           121             - 
                                                                  -----------   -----------   -----------
Earnings available for common stock.............................. $   178,498   $    93,843   $   272,341 
                                                                  -----------   -----------   -----------
                                                                  -----------   -----------   -----------

Weighted average common shares outstanding (2)..................       64,187        40,918       103,059 
                                                                  -----------   -----------   -----------
                                                                  -----------   -----------   -----------

Earnings per weighted average share of common stock outstanding.. $      2.78   $      2.29   $      2.64 
                                                                  -----------   -----------   -----------
                                                                  -----------   -----------   -----------
</TABLE>

  The accompanying notes to unaudited pro forma combined balance sheet and 
       statements of income are an integral part of this statement.

                                     74

<PAGE>


                          NEW CENTURY ENERGIES, INC.
               UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME
                 (THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA)
                          YEAR ENDED DECEMBER 31, 1995

<TABLE>
                                                                        PSCO          SPS         PRO FORMA
                                                                    -----------   -----------   ----------- 

<S>                                                                  <C>              <C>          <C>
Operating revenues:
  Electric........................................................  $ 1,449,096   $   852,510   $ 2,301,606 
  Gas  ...........................................................      624,585             -       624,585 
  Other...........................................................       36,920             -        36,920 
                                                                    -----------   -----------   ----------- 
                                                                      2,110,601       852,510     2,963,111 

Operating expenses:
  Fuel used in generation.........................................      181,995       376,544       558,539 
  Purchased power.................................................      481,958         6,485       488,443 
  Gas purchased for resale........................................      392,680             -       392,680 
  Other operating expenses(3).....................................      346,025       108,411       454,436 
  Maintenance.....................................................       64,069        27,594        91,663 
  Depreciation and amortization...................................      141,380        62,552       203,932 
  Taxes (other than income taxes).................................       81,319        43,316       124,635 
  Income taxes....................................................       95,357        69,840       165,197 
                                                                    -----------   -----------   ----------- 
                                                                      1,784,783       694,742     2,479,525 
                                                                    -----------   -----------   ----------- 
Operating income..................................................      325,818       157,768       483,586 

Other income and deductions:
  Allowance for equity funds used during construction.............        3,782           245         4,027 
  Miscellaneous income and deductions - net (3)...................       (6,838)        8,141         1,303 
                                                                    -----------   -----------   ----------- 
                                                                         (3,056)        8,386         5,330 

Interest charges:
  Interest on long-term debt......................................       85,832        42,421       128,253 
  Amortization of debt discount and expense less premium..........        3,278         2,048         5,326 
  Other interest..................................................       58,109         1,695        59,804 
  Allowance for borrowed funds used during construction...........       (3,313)       (2,744)       (6,057) 
  Dividend requirements on preferred stock of subsidiaries........            -             -        17,588 
                                                                    -----------   -----------   ----------- 
                                                                        143,906        43,420       204,914 
                                                                    -----------   -----------   ----------- 
Net income........................................................      178,856       122,734       284,002 
Dividend requirements on preferred stock..........................       11,963         5,625             - 
                                                                    -----------   -----------   ----------- 
Earnings available for common stock...............................  $   166,893   $   117,109   $   284,002 
                                                                    -----------   -----------   ----------- 
                                                                    -----------   -----------   ----------- 
Weighted average common shares outstanding (2)....................       62,932        40,918       101,804 
                                                                    -----------   -----------   ----------- 
                                                                    -----------   -----------   ----------- 

Earnings per weighted average share of common stock outstanding...  $      2.65   $      2.86   $      2.79 
                                                                    -----------   -----------   ----------- 
                                                                    -----------   -----------   ----------- 
</TABLE>

  The accompanying notes to unaudited pro forma combined balance sheet and 
       statements of income are an integral part of this statement.

                                     75


<PAGE>

                           NEW CENTURY ENERGIES, INC.
               UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME
                 (THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA)
                          YEAR ENDED DECEMBER 31, 1994


<TABLE>
                                                                       PSCO          SPS        PRO FORMA
                                                                   -----------   -----------  ----------- 

<S>                                                                 <C>           <C>           <C>
Operating revenues:
  Electric........................................................ $ 1,399,836   $   824,008  $ 2,223,844 
  Gas  ...........................................................     624,922             -      624,922 
  Other...........................................................      32,626             -       32,626 
                                                                   -----------   -----------  ----------- 
                                                                     2,057,384       824,008    2,881,392 

Operating expenses:
  Fuel used in generation.........................................     198,118       386,796      584,914 
  Purchased power.................................................     437,087         4,401      441,488 
  Gas purchased for resale........................................     397,877             -      397,877 
  Other operating expenses........................................     369,094       107,130      476,224 
  Maintenance.....................................................      67,097        30,245       97,342 
  Defueling and decommissioning...................................      43,376             -       43,376 
  Depreciation and amortization...................................     139,035        59,759      198,794 
  Taxes (other than income taxes).................................      86,408        42,510      128,918 
  Income taxes....................................................      48,500        57,126      105,626 
                                                                   -----------   -----------  ----------- 
                                                                     1,786,592       687,967    2,474,559 
                                                                   -----------   -----------  ----------- 
Operating income..................................................     270,792       136,041      406,833 
Other income and deductions:
  Allowance for equity funds used during construction.............       3,140           179        3,319 
  Gain on sale of WestGas Gathering, Inc..........................      34,485             -       34,485 
  Miscellaneous income and deductions - net.......................      (6,014)        1,867       (4,147) 
                                                                   -----------   -----------  ----------- 
                                                                        31,611         2,046       33,657 

Interest charges:
  Interest on long-term debt......................................      89,005        37,710      126,715 
  Amortization of debt discount and expense less premium..........       3,126         2,020        5,146 
  Other interest..................................................      44,021         2,028       46,049 
  Allowance for borrowed funds used during construction...........      (4,018)       (1,303)      (5,321) 
  Dividend requirements on preferred stock of subsidiaries........           -             -       16,892 
                                                                   -----------   -----------  ----------- 
                                                                       132,134        40,455      189,481 
                                                                   -----------   -----------  ----------- 
Net income........................................................     170,269        97,632      251,009 
Dividend requirements on preferred stock..........................      12,014         4,878            - 
                                                                   -----------   -----------  ----------- 
Earnings available for common stock............................... $   158,255   $    92,754  $   251,009 
                                                                   -----------   -----------  ----------- 
                                                                   -----------   -----------  ----------- 

Weighted average common shares outstanding (2)....................      61,547        40,918      100,419 
                                                                   -----------   -----------  ----------- 
                                                                   -----------   -----------  ----------- 

Earnings per weighted average share of common stock outstanding... $      2.57   $      2.27  $      2.50 
                                                                   -----------   -----------  ----------- 
                                                                   -----------   -----------  ----------- 
</TABLE>

   The accompanying notes to unaudited pro forma combined balance sheet and
          statements of income are an integral part of this statement.

                                     76

<PAGE>

                          NEW CENTURY ENERGIES, INC.

 NOTES TO UNAUDITED PRO FORMA COMBINED BALANCE SHEET AND STATEMENTS OF INCOME
                              DECEMBER 31, 1996

    (1) The unaudited pro forma combined statements of income have been
prepared from the historical consolidated financial statements of  PSCo and SPS
and are presented as if the companies were combined during all periods presented
herein.

    (2) The unaudited pro forma combined balance sheet and statements of income
reflect the conversion of each outstanding share of PSCo Common Stock into one
share of NCE Common Stock, and each outstanding share of SPS Common Stock into
0.95 of one share of NCE Common Stock in accordance with the terms of the
Merger.

    (3) There were no intercompany transactions and, accordingly, no pro forma
elimination adjustments were made. Certain amounts have been reclassified in
order to provide consistent presentation.

    (4) For a discussion regarding material commitments and contingencies
relating to PSCo, see Note 9. Commitments and Contingencies in Item 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA.  For SPS, reference is made to its 1996
Annual  Report on Form 10-K and its Form 10-Q for the quarter ended November 30,
1996.

    (5) The unaudited pro forma combined financial statements include
nonrecurring charges directly related to the Merger totaling $9.4 million and
$6.8 million for the years ended December 31, 1996 and 1995, respectively. 
These nonrecurring charges include merger transaction costs and benefits expense
resulting from an accelerated vesting of certain benefits. The unaudited pro
forma combined statements of income do not reflect future nonrecurring charges
directly related to the Merger, estimated to total approximately $8.5 million.
The pro forma combined balance sheet at December 31, 1996 has been adjusted to
include these items with the recognition of additional current liabilities and
the reduction of retained earnings.



                                     77

<PAGE>

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
          FINANCIAL DISCLOSURE

    Does not apply.

                                  PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

    Biographies concerning the directors of the registrant are contained under
ELECTION OF DIRECTORS  in the registrant's 1997 Proxy Statement, which is
incorporated herein by reference.  The following table sets forth certain
information concerning the directors and executive officers of the Company as of
December 31, 1996. 
<TABLE>
Name                           Age  Occupation/Title                                     Initial Date as Director
----                           ---  ----------------                                     ------------------------ 

<S>                           <C>    <C>                                                  <C>
D.D. Hock (b)                  61   Chairman of the Board                                          1985

Wayne H. Brunetti              54   President and CEO                                              1994

Collis P. Chandler, Jr. (g)    70   Chairman, Chandler & Associates, Inc., 
                                    Chandler-Simpson, Inc. and Chandler Drilling Corp.             1985

Doris M. Drury, Ph.D. (a)(h)   70   John J. Sullivan Professor of Free Enterprise
                                    Economics at Regis University, and President of the
                                    Center for Business and Economic Forecasting, Inc.             1975

Thomas T. Farley (c)           62   President, Petersen & Fonda, P.C.                              1983

Gayle L. Greer (c)             55   Vice President, Time Warner Cable                              1986

A. Barry Hirschfeld (e)        54   President, A.B. Hirschfeld Press, Inc.                         1988

George B. McKinley (a)(g)      69   Chairman and CEO, First National Banks of 
                                    Evanston and Kemmerer, Wyoming and President &
                                    CEO, First McKinley Corporation                                1976

Will F. Nicholson, Jr. (a)(g)  67   Chairman, Rocky Mountain Bank Card System                      1981

J. Michael Powers (d)          54   President, Powers Products Co. and Powers
                                    Masonry Supply                                                 1978

Thomas E. Rodriguez (c)        52   President and General Manager, Thomas E. Rodriguez
                                    & Associates, P.C.                                             1986

Rodney E. Slifer (e)           62   Partner, Slifer, Smith & Frampton/Vail Associates
                                    Real Estate                                                    1988

W. Thomas Stephens (f)(g)      54   Retired Chairman, Manville Corporation                         1989

Robert G. Tointon (a)(g)       63   President and CEO Phelps-Tointon, Inc.                         1988
</TABLE>

---------------------------------
(a)  Member of Executive Committee.
(b)  Chairperson of Executive Committee.
(c)  Member of Audit Committee.


                                     78

<PAGE>
                                       
(d) Chairperson of Audit Committee.
(e) Member of Pension Investment Committee.
(f) Chairperson of Pension Investment Committee.
(g) Member of Compensation Committee.
(h) Chairperson of Compensation Committee.


<TABLE>

Executive Officers                                                         Initial Effective Date
------------------                                                         ----------------------
<S>                                                                        <C>
D. D. Hock, Age 61 
    Chairman of the Board................................................  February 28, 1989
    Chairman of the Board, Cheyenne Light, Fuel and Power Company........  September 21, 1988
    Chairman of the Board, Fuel Resources Development Co. ...............  March 22, 1989 
    Chairman of the Board, 1480 Welton, Inc. ............................  September 26, 1988
    Chairman of the Board, PSR Investments, Inc. ........................  March 22, 1990
    Chairman of the Board, PS Colorado Credit Corporation................  March 22, 1990
    Chairman of the Board, Green and Clear Lakes Company.................  December 6, 1988
    Chairman of the Board, WestGas InterState, Inc. .....................  April 22, 1993
    Chairman of the Board, Natural Fuels Corporation.....................  June 11, 1993
    Chairman of the Board, e prime, inc. ................................  January 30, 1995
    Chairman of the Board, Young Gas Storage Company.....................  June 27, 1995
    Company Service: September, 1962 

Wayne H. Brunetti, Age 54
    President............................................................  June 28, 1994
      and Chief Executive Officer........................................  January 1, 1996
    President, 1480 Welton, Inc. ........................................  March 29, 1996
    President, PSR Investments, Inc. ....................................  March 29, 1996
    President, PS Colorado Credit Corporation............................  March 29, 1996
    President, WestGas InterState, Inc. .................................  April 19, 1995 
    President, Fuel Resources Development Co. ...........................  April 27, 1995
    President, Natural Fuels Corporation.................................  April 25, 1996
    President, Green and Clear Lakes Company.............................  December 5, 1995
    Company Service: June, 1994

Richard C. Kelly, Age 50
    Senior Vice President, Finance, Treasurer............................  June 28, 1994  
      and Chief Financial Officer........................................  January 23,1990 
    President and Treasurer, New Century Energies, Inc. .................  August 21, 1995
    Vice President, Fuel Resources Development Co. .....................  April 26, 1990 
    Treasurer, Fuel Resources Development Co. ...........................  August 5, 1994
    Vice President, PSR Investments, Inc. ...............................  September 22, 1986
    Vice President, PS Colorado Credit Corporation.......................  March 30, 1987 
    Treasurer, Cheyenne Light, Fuel and Power Company....................  July 15, 1994
    Treasurer, 1480 Welton, Inc. ........................................  July 15, 1994
    Treasurer, Green and Clear Lakes Company.............................  July 15, 1994
    Treasurer, WestGas InterState, Inc. .................................  July 15, 1994
    Vice President and Treasurer, e prime inc. ..........................  January 30, 1995
    Vice President and Treasurer, Young Gas Storage Company..............  June 27, 1995
    Company Service: May, 1968 



                                      79
<PAGE>

Patricia T. Smith, Age 49
    Senior Vice President and General Counsel............................  December 5, 1994
    Company Service: December, 1994

W. Wayne Brown, Age 46
    Controller...........................................................  November 24, 1987
    Corporate Secretary..................................................  November 23, 1993
    Secretary, Cheyenne Light, Fuel and Power Company....................  December 15, 1993
    Secretary, 1480 Welton, Inc. ........................................  December 16, 1993
    Secretary, PSR Investments, Inc. ....................................  December 16, 1993
    Secretary, PS Colorado Credit Corporation............................  December 16, 1993
    Secretary, Green and Clear Lakes Company.............................  December 7, 1993
    Secretary, Fuel Resources Development Co. ...........................  January 27, 1994
    Secretary, WestGas InterState, Inc. .................................  May 2, 1994
    Secretary, e prime, inc. ............................................  January 30, 1995
    Secretary, Young Gas Storage Company.................................  June 27, 1995
    Company Service: June, 1972

A. Clegg Crawford, Age 64 *
    Vice President, Engineering and Operations Support...................  June 28, 1994
    Company Service: May, 1989

Ross C. King, Age 55 
    Vice President, Gas and Electric Distribution........................  June 28, 1994
    President, Cheyenne Light, Fuel and Power Company....................  July 15, 1994
    Company Service:  February, 1966

Earl E. McLaughlin, Jr., Age 56 
    Vice President, Retail Energy Services...............................  June 28, 1994
    Vice President, Cheyenne Light, Fuel and Power Company...............  March 24, 1994
    Company Service: August, 1960

Ralph Sargent III, Age 47
    Vice President, Production and System Operations.....................  June 28, 1994
    Company Service:  July, 1978

Marilyn E. Taylor, Age 54
    Vice President, Human Resources......................................  June 28, 1994
    Company Service: December, 1987 
</TABLE>

    * On February 7, 1997, Mr. Crawford retired from the Company.

    Each of the above executive officers, except Mr. Brunetti and Ms. Smith, 
has been employed by the Company and/or its subsidiaries for more than five 
years in executive or management positions.  Prior to election to the 
positions shown above and since January 1, 1991: 

Mr. Hock has been Chief Operating Officer and President;

Mr. Brunetti has been Chief Operating Officer of the Company and President 
and Chief Executive Officer of Management Systems International from June 
1991 through July 1994 and Executive Vice President of Florida Power & Light 
Company from 1987 through May 1991;



                                      80
<PAGE>

Mr. Kelly has been Vice President, Financial Services, Principal Accounting 
Officer and Senior Vice President, Finance and Administration;

Ms. Smith has been Vice President and General Counsel for South Carolina 
Electric and Gas Company from May 1992 through December 1994 and Vice 
President, Regulatory Affairs and Purchasing from 1988 through May 1992;

Mr. Crawford has been Vice President, Nuclear Operations and Vice President, 
Electric Production;

Mr. King has been Manager, Denver Metro Region; Vice President, Regional 
Customer Operations and Vice President, Metropolitan Customer Operations;

Mr. McLaughlin has been Vice President, Marketing, Customer Services and 
Support Services;  

Mr. Sargent has been Executive Assistant to Chairman, President and Chief 
Executive Officer and Vice President, Finance, Planning and Communications 
and Treasurer;

Ms. Taylor has been Vice President, Human Resources and Vice President 
Administrative Services.

    There are no family relationships between executive officers or directors 
of the Company. There are no arrangements or understandings between the 
executive officers individually and any other person with reference to their 
being selected as officers. All executive officers are elected annually by 
the Board of Directors.

    Information concerning the directors of the registrant is contained under 
ELECTION OF DIRECTORS in the registrant's 1997 Proxy Statement, which 
information is incorporated herein by reference. 


ITEM 11. EXECUTIVE COMPENSATION

    Information concerning executive compensation is contained under 
COMPENSATION OF EXECUTIVE  OFFICERS AND DIRECTORS in the registrant's 1997 
Proxy Statement, which information is incorporated herein by reference. 


ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

    Information concerning the security ownership of the directors and 
officers of the registrant is contained under ELECTION OF DIRECTORS in the 
registrant's 1997 Proxy Statement, which information is incorporated herein 
by reference. 


ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

    Information concerning relationships and related transactions of the 
directors and officers of the registrant is contained under CERTAIN 
RELATIONSHIPS AND RELATED TRANSACTIONS in the registrant's 1997 Proxy 
Statement, which information is incorporated herein by reference. 

                                       
                                    PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) Financial Statements, Financial Statement Schedules, and Exhibits. 

                                                                            Page
                                                                            ----
1. Financial Statements:
   Report of the Audit Committee..........................................   33
   Report of Management...................................................   34



                                      81
<PAGE>

   Report of Independent Public Accountants...............................   35

   Consolidated Balance Sheets, December 31, 1996 and 1995................   36

   Consolidated Statements of Income for each of the three
     years in the period ended December 31, 1996..........................   38

   Consolidated Statements of Shareholders' Equity for each
     of the three years in the period ended December 31, 1996.............   39

   Consolidated Statements of Cash Flows for each of the three
     years in the period ended December 31, 1996..........................   40

   Notes to Consolidated Financial Statements.............................   41


2. Financial Statement Schedules:
   II  Valuation and Qualifying Accounts and Reserves
       (Consolidated) for each of the three years in the period
       ended December 31, 1996............................................   69

    All other schedules have been omitted since the required information is 
not present or not present in amounts sufficient to require submission of the 
schedule, or because the information required is included in the consolidated 
financial statements or the notes thereto. 

    Financial statements of several unconsolidated majority-owned 
subsidiaries are omitted since such subsidiaries, considered in the aggregate 
as a single subsidiary, would not constitute a significant subsidiary. 

3. Exhibits:
   Exhibits are listed in the Exhibit Index...............................   87

    The Exhibits include the management contracts and compensatory plans or 
arrangements required to be filed as exhibits to this Form 10-K by Item 601 
(10) (iii) of Regulation S-K.

(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.

    A report on Form 8-K, dated May 21, 1996, was filed on May 22, 1996.  The 
item reported was Item 5 - Other Events, which presented updated information 
on the settlement of environmental matters associated with the operations of 
the Hayden Steam Electric Generating Station.

    A report on Form 8-K, was dated and filed on February 24, 1997. The 
item reported was Item 5 - Other Events, which presented information on the 
Proposed Acquisition of Yorkshire Electricity by the Company and AEP.

                                      82

<PAGE>

                                    EXPERTS

    The consolidated balance sheets of the Company and its subsidiaries as of 
December 31, 1996 and 1995, the related consolidated statements of income, 
shareholders' equity and cash flows for each of the three years in the period 
ended December 31, 1996, and the related financial statement schedule, 
appearing in this Annual Report on Form 10-K, have been audited by Arthur 
Andersen LLP, independent public accountants, and the selected financial data 
for each of the five years in the period ended December 31, 1996, appearing 
in Item 6 of this Annual Report on Form 10-K, other than the ratios and 
percentages therein, have been derived from the consolidated financial 
statements audited by Arthur Andersen LLP, as set forth in their report 
appearing elsewhere herein. The consolidated financial statements, the 
related financial statement schedule and the selected financial data 
appearing in Item 6, other than the ratios and percentages therein, which are 
included in this Annual Report on Form 10-K, are included herein in reliance 
upon the authority of said firm as experts in accounting and auditing in 
giving said report.










                                      83
<PAGE>
                                       
                                                                      EXHIBIT 23
                                       
                   CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
                                       
    As independent public accountants, we hereby consent to the incorporation 
by reference of our report included in this Form 10-K, into the Company's 
previously filed 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; 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; and the Company's Registration Statement (Form 
S-3, File No. 333-14727) pertaining to the shelf-registration of the 
Company's First Collateral Trust Bonds (being one or more series of secured 
medium-term notes) and to all references to our Firm included in this Form 
10-K.



                                                             ARTHUR ANDERSEN LLP

Denver, Colorado 
February 24, 1997





                                                                      EXHIBIT 24
                                       
                               POWER OF ATTORNEY

    Each director and/or officer of Public Service Company of Colorado whose 
signature appears herein hereby appoints W. H. Brunetti and R. C. Kelly, and 
each of them severally, as his or her attorney-in-fact to sign in his or her 
name and behalf, in any and all capacities stated herein, and to file with 
the Securities and Exchange Commission, any and all amendments to this Annual 
Report on Form 10-K. 





                                      84
<PAGE>

                                  SIGNATURES

    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 ON THE 25TH DAY OF FEBRUARY, 1997.

                                       PUBLIC SERVICE COMPANY OF COLORADO

                                       By         /s/ R. C. Kelly
                                          --------------------------------
                                                   R. C. KELLY
                                              SENIOR VICE PRESIDENT,
                                              FINANCE, TREASURER AND
                                             CHIEF FINANCIAL OFFICER


    PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS 
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF PUBLIC 
SERVICE COMPANY OF COLORADO AND IN THE CAPACITIES AND ON THE DATE INDICATED.


          SIGNATURE                         TITLE                    DATE
--------------------------------------------------------------------------------

/s/ W. H. Brunetti
-------------------------------      Principal Executive       February 25, 1997
W. H. Brunetti                       Officer and Director
PRESIDENT AND CHIEF 
EXECUTIVE OFFICER


/s/ R. C. Kelly
-------------------------------      Principal Financial       February 25, 1997
R. C. Kelly                          Officer   
SENIOR VICE PRESIDENT,
FINANCE, TREASURER AND
CHIEF FINANCIAL OFFICER


/s/ W. Wayne Brown
-------------------------------      Principal Accounting      February 25, 1997
W. Wayne Brown                       Officer       
CONTROLLER AND CORPORATE 
SECRETARY





                                       85
<PAGE>



          SIGNATURE                         TITLE                    DATE
--------------------------------------------------------------------------------


/s/ D. D. Hock
-------------------------------      Chairman of the Board     February 25, 1997
D. D. Hock                           and Director   


/s/ Collis P. Chandler
-------------------------------      Director                  February 25, 1997
Collis P. Chandler


/s/ Doris M. Drury
-------------------------------      Director                  February 25, 1997
Doris M. Drury


/s/ Thomas T. Farley
-------------------------------      Director                  February 25, 1997
Thomas T. Farley


/s/ Gayle L. Greer
-------------------------------      Director                  February 25, 1997
Gayle L. Greer


/s/ A. Barry Hirschfeld
-------------------------------      Director                  February 25, 1997
A. Barry Hirschfeld


/s/ George B. McKinley
-------------------------------      Director                  February 25, 1997
George B. McKinley


/s/ Will F. Nicholson, Jr.
-------------------------------      Director                  February 25, 1997
Will F. Nicholson, Jr.


/s/ J. Michael Powers
-------------------------------      Director                  February 25, 1997
J. Michael Powers


/s/ Thomas E. Rodriguez
-------------------------------      Director                  February 25, 1997
Thomas E. Rodriguez


/s/ Rodney E. Slifer
-------------------------------      Director                  February 25, 1997
Rodney E. Slifer


/s/ W. Thomas Stephens
-------------------------------      Director                  February 25, 1997
W. Thomas Stephens


/s/ Robert G. Tointon
-------------------------------      Director                  February 25, 1997
Robert G. Tointon


                                      86

<PAGE>

                            EXHIBIT INDEX

2(a)*     Merger Agreement and Plan of Reorganization dated August 22, 1995
          (Form 8-K dated August 22, 1995, File No. 1-3280 - Exhibit 2).

3(a)1*    Restated Articles of Incorporation of the Registrant dated July 9,
          1990 (Form S-3, File No. 33-54877 - Exhibit 3(a)).

3(a)2*    Articles of Amendment of the Restated Articles of Incorporation of the
          Registrant dated May 11, 1994 (Form S-3, File No. 33-54877 - 
          Exhibit 3(b)).

3(b)*     By-laws dated November 30, 1992 (Form 10-K, 1993 - Exhibit 3(b)).

4(a)(1)*  Indenture, dated as of December 1, 1939, providing for the issuance 
          of First Mortgage Bonds (Form 10 for 1946- Exhibit (B-1)).

4(a)(2)*  Indentures supplemental to Indenture dated as of December 1, 1939:

<TABLE>
                    PREVIOUS FILING:                             PREVIOUS FILING:
                     FORM; DATE OR    EXHIBIT                     FORM; DATE OR         EXHIBIT  
     DATED AS OF        FILE NO.        NO.      DATED AS OF         FILE NO.              NO.
     -----------        --------        ---      -----------         --------              ---

     <C>                <C>            <C>       <C>               <C>                   <C>
     Mar. 14, 1941      10, 1946        B-2      Apr. 25, 1969      8-K, Apr. 1969          1
     May 14, 1941       10, 1946        B-3      Apr. 21, 1970      8-K, Apr. 1970          1
     Apr. 28, 1942      10, 1946        B-4      Sept. 1, 1970      8-K, Sept. 1970         2
     Apr. 14, 1943      10, 1946        B-5      Feb. 1, 1971       8-K, Feb. 1971          2
     Apr. 27, 1944      10, 1946        B-6      Aug. 1, 1972       8-K, Aug. 1972          2
     Apr. 18, 1945      10, 1946        B-7      June 1, 1973       8-K, June 1973          1
     Apr. 23, 1946      10-K, 1946      B-8      Mar. 1, 1974       8-K, Apr. 1974          2
     Apr. 9, 1947       10-K, 1946      B-9      Dec. 1, 1974       8-K, Dec. 1974          1
     June 1, 1947     S-1, (2-7075)     7(b)     Oct. 1, 1975       S-7, (2-60082)       2(b)(3) 
     Apr. 1, 1948     S-1, (2-7671)   7(b)(1)    Apr. 28, 1976      S-7, (2-60082)       2(b)(4) 
     May 20, 1948     S-1, (2-7671)   7(b)(2)    Apr. 28, 1977      S-7, (2-60082)       2(b)(5) 
     Oct. 1, 1948       10-K, 1948      4        Nov. 1, 1977       S-7, (2-62415)       2(b)(3) 
     Apr. 20, 1949      10-K, 1949      1        Apr. 28, 1978      S-7, (2-62415)       2(b)(4) 
     Apr. 24, 1950   8-K, Apr. 1950     1        Oct. 1, 1978         10-K, 1978          D(1)   
     Apr. 18, 1951   8-K, Apr. 1951     1        Oct. 1, 1979       S-7, (2-66484)       2(b)(3)
     Oct. 1, 1951    8-K, Nov. 1951     1        Mar. 1, 1980         10-K, 1980          4(c)
     Apr. 21, 1952   8-K, Apr. 1952     1        Apr. 28, 1981      S-16, (2-74923)       4(c)
     Dec. 1, 1952    S-9, (2-11120)   2(b)(9)    Nov. 1, 1981       S-16, (2-74923)       4(d)
     Apr. 15, 1953   8-K, Apr. 1953     2        Dec. 1, 1981         10-K, 1981          4(c)
     Apr. 19, 1954   8-K, Apr. 1954     1        Apr. 29, 1982        10-K, 1982          4(c)
     Oct. 1, 1954    8-K, Oct. 1954     1        May 1, 1983          10-K, 1983          4(c)
     Apr. 18, 1955   8-K, Apr. 1955     1        Apr. 30, 1984      S-3, (2-95814)        4(c)
     Apr. 24, 1956     10-K, 1956       1        Mar. 1, 1985         10-K, 1985          4(c)
     May 1, 1957     S-9, (2-13260)   2(b)(15)   Nov. 1, 1986         10-K, 1986          4(c)
     Apr. 10, 1958   8-K, Apr. 1958     1        May 1, 1987          10-K, 1987          4(c)
     May 1, 1959     8-K, May 1959      2        July 1, 1990       S-3, (33-37431)       4(c)
     Apr. 18, 1960   8-K, Apr. 1960     1        Dec. 1, 1990         10-K, 1990          4(c)
     Apr. 19, 1961   8-K, Apr. 1961     1        Mar. 1, 1992         10-K, 1992          4(d)
     Oct. 1, 1961    8-K, Oct. 1961     2        Apr. 1, 1993     10-Q, June 30, 1993     4(a)
     Mar. 1, 1962    8-K, Mar. 1962   3(a)       June 1, 1993     10-Q, June 30, 1993     4(b)  
     June 1, 1964    8-K, June 1964     1        Nov. 1, 1993       S-3, (33-51167)     4(a)(3)
     May 1, 1966     8-K, May 1966      2        Jan. 1, 1994         10-K, 1993        4(a)(3)
     July 1, 1967    8-K, July 1967     2        Sept. 2, 1994      8-K, Sept. 1994       4(a)
     July 1, 1968    8-K, July 1968     2        May 1, 1996      10Q, June 30, 1996      4(a)
</TABLE>


                                     87

<PAGE>

4(a)(3)   Supplemental Indenture dated as of November 1, 1996, establishing a
          series of First Mortgage Bonds under the Indenture dated as of 
          December 31, 1939.

4(b)(1)*  Indenture, dated as of October 1, 1993, providing for the issuance of
          First Collateral Trust Bonds (Form 10-Q, September 30, 1993 - 
          Exhibit 4(a)).

4(b)(2)*  Indentures supplemental to Indenture dated as of October 1, 1993:

                               PREVIOUS FILING:
                                FORM; DATE OR         EXHIBIT
          DATED AS OF             FILE NO.              NO.
          -----------             --------              ---

          November 1, 1993     S-3, (33-51167)       4(b)(2)
          January 1, 1994      10-K, 1993            4(b)(3)
          September 2, 1994    8-K, Sept. 1994          4(b)
          May 1, 1996          10-Q, June 30, 1996      4(b)

4(b)(3)    Supplemental Indenture No. 5, dated as of November 1, 1996
           establishing a series of Secured Medium-Term Notes under the 
           Indenture dated as of October 1, 1993.

4(c)(1)*   Rights Agreement dated as of February 26, 1991, between the
           Registrant and Mellon Bank, N.A. (Form 8-A, filed on March 1, 
           1991 - Exhibit 1).

4(c)(2)*   Amendment to the Rights Agreement dated August 22, 1995 (Form 8-K
           dated August 22, 1995, File   No. 1-3280 - Exhibit 99(b)).

10(a)(1)*  Settlement Agreement dated February 9, 1996 between the Company 
           and the United States Department of Energy (10-K, 195 - 
           Exhibit 10(a)(1)).

10(a)(2)*  Settlement Agreement dated June 27, 1979 between the Registrant and
           General Atomic Company (Form S-7, File No. 2-66484 - 
           Exhibit 5(a)(1)).

10(a)(3)*  Services Agreement executed June 27, 1979 and effective as of 
           January 1, 1979 between the Registrant and General Atomic Company 
           (Form S-7, File No. 2-66484 - Exhibit 5(a)(3)).

10(c)(1)*  Amended and Restated Coal Supply Agreement entered into October 1,
           1984 but made effective as of January 1, 1976 between the Registrant
           and Amax Inc. on behalf of its division, Amax Coal Company (10-K, 
           1984 - Exhibit 10(c)(1)).

10(c)(2)*  First Amendment to Amended and Restated Coal Supply Agreement entered
           into May 27, 1988 but made effective January 1, 1988 between the 
           Registrant and Amax Coal Company (10-K, 1988 -Exhibit 10(c)(2).**

10(e)(1)*+ Supplemental Executive Retirement Plan for Key Management
           Employees, as amended and restated March 26, 1991 (10-K, 1991 - 
           Exhibit 10(e)(2)).

10(e)(2)*+ Omnibus Incentive Plan, as amended on January 1, 1996 (10-K, 1995
           - Exhibit 10(e)(2)).

10(e)(3)*+ Executive Savings Plan (10-K, 1991 - Exhibit 10(e)(5)).

10(e)(4)*+ Form of Key Executive Severance Agreement, as amended on August 22,
           and November 27, 1995. (10-K, 1995 - Exhibit 10(3)(4)).



                                     88

<PAGE>

10(f)(1)*+  Form of Director's Agreement (10-K, 1987 - Exhibit 10(f)(1)).

10(f)(2)*+  Form of Officer's Agreement (10-K, 1987 - Exhibit 10(f)(2)).

10(g)(1)*+  Employment Agreement dated April 8, 1994 between the Company and 
            Mr. Delwin D. Hock (10-Q, March 31, 1994 - Exhibit 10).

10(g)(2)*+  Employment Agreement dated July 18, 1994 between the Company and 
            Mr. Wayne H. Brunetti(10-Q, September 30, 1994 - Exhibit 10).

10(g)(3)*+  Employment Agreement dated December 5, 1994 between the Company 
            and Ms. Patricia T. Smith (10-K, 1994 - Exhibit 10(g)(3)).

10(g)(4)*+  Employment Agreement dated March 1, 1994 between the Company and
            Mr. A. Clegg Crawford (10K, 1995 - Exhibit 10(g)(4)).

10(g)(5)*+  Amendment to Employment Agreement dated August 22, 1995 between
            the Company and Mr. Delwin D. Hock. (10-K, 1995 - Exhibit 10(g)(5)).

10(g)(6)*+  Amendment to Employment Agreement dated August 22, 1995 between
            the Company and Mr. Wayne H. Brunetti. (10-K, 1995 - 
            Exhibit 10(g)(6)).

10(g)(7)*+  Amendment to Employment Agreement dated August 22, 1995 between
            the Company and Ms. Patricia T. Smith. (10-K, 1995 - 
            Exhibit 10(g)(7)).

12(a)       Computation of Ratio of Consolidated Earnings to Consolidated Fixed
            Charges is set forth at page 70 herein. 

12(b)       Computation of Ratio of Consolidated Earnings to Consolidated 
            Combined Fixed Charges and Preferred Stock Dividends is set forth 
            at page 71 herein.

21          Subsidiaries

23          Consent of Arthur Andersen LLP is set forth at page 84 herein.

24          Power of Attorney is set forth at page 84 herein.

27          Financial Data Schedule UT

99          NCE Unaudited Pro Forma Financial Information is set forth at 
            pages 72-77 herein.

-----------------
*    Previously filed as indicated and incorporated herein by reference.
**   Confidential Treatment.
+    Management contracts of compensatory plans or arrangements required to be
     filed as exhibits to this Form 10-K by Item 601(10)(iii) of Regulation S-K.



                                     89