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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.
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
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
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
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
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
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
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
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
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
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:
Mw Contracted
For at the Time
of the Anticipated
Generating Summer 1997 Net Firm Contract
Company Source System Peak Demand Expiration
- ------- ---------- -------------------- ----------
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
-----
-----
- -------------------
(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.
(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
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
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
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 ).
MINIMUM MAXIMUM CONTRACT
DELIVERY DELIVERY MAXIMUM
PER CONTRACT YEAR PER CONTRACT YEAR SULFUR
COAL SUPPLIER AND DELIVERY YEAR IN TONS IN TONS CONTENT
- ------------------------------- ----------------- ----------------- --------
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)
(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
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
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
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
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
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
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
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
CONSOLIDATED ELECTRIC OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------
1996 1995 1994 1993 1992
----------- ------------ ------------ ----------- -----------
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
- -------------------
(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
CONSOLIDATED GAS OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------
1996 1995 1994 1993 1992
----------- ------------ ------------ ----------- -----------
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
- -------------------
(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
PUBLIC SERVICE COMPANY OF COLORADO
ELECTRIC TRANSMISSION INTERCONNECTED SYSTEM
[MAP]
17
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:
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
--------------- --------- ---------------------- ------
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
-------- --------
-------- --------
- -------------------
* 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
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
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
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
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.
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS-EXCEPT PER SHARE DATA & RATIOS)
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
- -------------------------
(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
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
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
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
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
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
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
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
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
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
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
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
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
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
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
DECEMBER 31, 1996 AND 1995
ASSETS
1996 1995
---------- ----------
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
---------- ----------
---------- ----------
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
36
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
DECEMBER 31, 1996 AND 1995
CAPITAL AND LIABILITIES
1996 1995
---------- ----------
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
---------- ----------
---------- ----------
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
37
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
1996 1995 1994
---------- ---------- ----------
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
---------- ---------- ----------
---------- ---------- ----------
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
38
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
COMMON STOCK, $5 PAR VALUE
-------------------------- PREMIUM ON RETAINED
SHARES AMOUNT COMMON STOCK EARNINGS TOTAL
---------- --------- -------- --------- ----------
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
---------- -------- -------- --------- ----------
---------- -------- -------- --------- ----------
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
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF DOLLARS)
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
1996 1995 1994
--------- --------- ---------
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
--------- --------- ---------
--------- --------- ---------
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
40
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:
RECOVERY
1996 1995 THROUGH
-------- -------- ------------
(THOUSANDS OF DOLLARS)
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
-------- --------
-------- --------
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
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
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
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
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
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
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
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
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
1996 1995
----------------------- ------------------------
SHARES AMOUNT SHARES AMOUNT
--------- ----------- --------- -----------
(THOUSANDS (THOUSANDS
OF DOLLARS) OF DOLLARS)
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
--------- -------- --------- --------
--------- -------- --------- --------
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
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
1996 1995
---------- ----------
(THOUSANDS OF DOLLARS)
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
---------- ----------
---------- ----------
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
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
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
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
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
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
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
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
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
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:
PLANT CONSTRUCTION
IN ACCUMULATED WORK IN
SERVICE DEPRECIATION PROGRESS OWNERSHIP %
-------- ------------- ------------ -----------
(THOUSANDS OF
DOLLARS)
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
-------- -------- ------
-------- -------- ------
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
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:
1996 1995 1994
-------- --------- --------
(THOUSANDS OF DOLLARS)
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
-------- --------- --------
-------- --------- --------
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:
APR - DEC JAN - MAR
1996 1995 1994 1994
---- ---- --------- ---------
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%
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
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
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:
1996 1995 1994
-------- -------- --------
(THOUSANDS OF DOLLARS)
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
-------- -------- --------
-------- -------- --------
Significant assumptions used in determining net periodic postretirement
benefit cost were:
APR - DEC JAN - MAR
1996 1995 1994 1994
---- ---- --------- ---------
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%
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
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:
1996 1995 1994
------------------------- ------------------------ -------------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
SHARES EXERCISE PRICE SHARES EXERCISE PRICE SHARES EXERCISE PRICE
------- -------------- ------- -------------- ------- --------------
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
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.
1996 1995
----------------------- -----------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
---------- ---------- ---------- ----------
(THOUSANDS OF DOLLARS)
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
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
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:
1996 1995 1994
--------------- -------------- ---------------
(THOUSAND OF DOLLARS)
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%
-------- ---- ------- ---- -------- ----
-------- ---- ------- ---- -------- ----
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
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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. SEGMENTS OF BUSINESS
1996 ELECTRIC GAS OTHER TOTAL
------ ---------- -------- ------- ----------
(THOUSANDS OF DOLLARS)
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
----------
----------
(1) Includes additional expense of approximately $43.4 million for defueling
and decommissioning.
* Before income taxes.
** Includes allocation of common utility property.
67
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.
THREE MONTHS ENDED
---------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- -------- ------------ -----------
1996 (IN THOUSANDS-EXCEPT PER SHARE DATA)
------
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
(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
SCHEDULE II
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
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)
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
------ ------ ---- ------ ------
------ ------ ---- ------ ------
----------------
(1) Uncollectible accounts subsequently recovered, transfers from customers'
deposit, etc.
(2) Uncollectible accounts written off.
69
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)
YEAR ENDED DECEMBER 31,
----------------------------------------------------
1996 1995 1994 1993 1992
-------- -------- -------- -------- --------
(THOUSANDS OF DOLLARS, EXCEPT RATIOS)
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
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
70
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)
YEAR ENDED DECEMBER 31,
----------------------------------------------------
1996 1995 1994 1993 1992
-------- -------- -------- -------- --------
(THOUSANDS OF DOLLARS, EXCEPT RATIOS)
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
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
71
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
PSCO SPS PRO FORMA
----------- ----------- -----------
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
----------- ----------- -----------
----------- ----------- -----------
The accompanying notes to unaudited pro forma combined balance sheet and
statements of income are an integral part of this statement.
72
NEW CENTURY ENERGIES, INC.
UNAUDITED PRO FORMA COMBINED BALANCE SHEET
(THOUSANDS OF DOLLARS)
DECEMBER 31, 1996
CAPITAL AND LIABILITIES
PSCO SPS PRO FORMA
----------- ----------- -----------
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
----------- ----------- -----------
----------- ----------- -----------
The accompanying notes to unaudited pro forma combined balance sheet and
statements of income are an integral part of this statement.
73
NEW CENTURY ENERGIES, INC.
UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA)
YEAR ENDED DECEMBER 31, 1996
PSCO SPS PRO FORMA
----------- ----------- -----------
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
----------- ----------- -----------
----------- ----------- -----------
The accompanying notes to unaudited pro forma combined balance sheet and
statements of income are an integral part of this statement.
74
NEW CENTURY ENERGIES, INC.
UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA)
YEAR ENDED DECEMBER 31, 1995
PSCO SPS PRO FORMA
----------- ----------- -----------
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
----------- ----------- -----------
----------- ----------- -----------
The accompanying notes to unaudited pro forma combined balance sheet and
statements of income are an integral part of this statement.
75
NEW CENTURY ENERGIES, INC.
UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA)
YEAR ENDED DECEMBER 31, 1994
PSCO SPS PRO FORMA
----------- ----------- -----------
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
----------- ----------- -----------
----------- ----------- -----------
The accompanying notes to unaudited pro forma combined balance sheet and
statements of income are an integral part of this statement.
76
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
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.
Name Age Occupation/Title Initial Date as Director
- ---- --- ---------------- ------------------------
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
- ---------------------------------
(a) Member of Executive Committee.
(b) Chairperson of Executive Committee.
(c) Member of Audit Committee.
78
(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.
Executive Officers Initial Effective Date
- ------------------ ----------------------
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
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
* 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
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
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
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
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
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
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
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:
PREVIOUS FILING: PREVIOUS FILING:
FORM; DATE OR EXHIBIT FORM; DATE OR EXHIBIT
DATED AS OF FILE NO. NO. DATED AS OF FILE NO. NO.
----------- -------- --- ----------- -------- ---
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)
87
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
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