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, 1995
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________
Commission file number 1-3280
PUBLIC SERVICE COMPANY OF COLORADO
(Exact name of registrant as specified in its charter)
COLORADO 84-0296600
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
1225 17TH STREET, DENVER, COLORADO 80202
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (303) 571-7511
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. [X]
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
$2,264,862,654 BASED ON THE LAST SALE PRICE THEREOF REPORTED ON THE CONSOLIDATED
TAPE FOR FEBRUARY 20, 1996.
AT FEBRUARY 20, 1996, 63,798,948 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 1996 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 l. Business....................................... 1
The Company.......................................... 1
Electric Operations.................................. 1
Peak Load.......................................... 2
Purchased Power.................................... 2
Construction Program............................... 4
Fort St. Vrain..................................... 5
Electric Fuel Supply................................. 5
Coal............................................... 5
Natural Gas and Fuel Oil........................... 6
Natural Gas Operations............................... 6
Gas Supply......................................... 7
YGSC............................................... 7
WGI................................................ 8
WGT................................................ 8
Fuelco............................................. 8
e prime............................................ 8
Regulation and Rates................................. 8
1995 Merger Rate Filings........................... 8
State Regulation................................... 9
CPUC............................................. 9
Electric and Gas Adjustment Clauses.............. 9
Incentive Regulation and Demand Side Management.. 10
1993 Rate Case................................... 10
IRP - Electric................................... 10
WPSC............................................. 11
Federal Energy Regulatory Commission............... 11
Environmental Matters................................ 12
Competition.......................................... 13
Industry Outlook................................... 13
State Regulatory Environment....................... 13
Electric........................................... 14
Natural Gas........................................ 14
Franchises........................................... 14
Employees & Union Contracts.......................... 14
Research and Development............................. 15
Consolidated Electric Operating Statistics........... 16
Consolidated Gas Operating Statistics................ 17
Electric Transmission Map............................ 18
Item 2. Properties..................................... 19
Electric Property.................................... 19
Nuclear Property..................................... 19
Transmission and Distribution Property............... 19
Gas Property......................................... 20
Other Property....................................... 20
Property of Subsidiaries............................. 20
Character of Ownership............................... 21
Item 3. Legal Proceedings.............................. 21
i
Item 4. Submission of Matters to a Vote of Security Holders...................... 21
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.... 22
Item 6. Selected Financial Data.................................................. 23
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations...................................................... 24
Industry Outlook............................................................... 24
Corporate Overview............................................................. 24
Earnings....................................................................... 25
Electric Operations............................................................ 25
Gas Operations................................................................. 26
Non-Fuel Operating Expenses.................................................... 27
Financial Position............................................................. 28
Recently Issued Accounting Standards Not Yet Adopted........................... 28
Commitments and Contingencies.................................................. 28
Common Stock Dividend.......................................................... 29
Liquidity and Capital Resources................................................ 29
Cash Flows................................................................... 29
Prospective Capital Requirements............................................. 30
Capital Sources.............................................................. 30
Item 8. Financial Statements and Supplementary Data.............................. 33
Report of Independent Public Accountants....................................... 33
Consolidated Balance Sheets.................................................... 34
Consolidated Statements of Income.............................................. 36
Consolidated Statements of Shareholders' Equity................................ 37
Consolidated Statements of Cash Flows.......................................... 38
Notes to Consolidated Financial Statements..................................... 39
Schedule II....................................................................... 67
Exhibit 12(a)..................................................................... 68
Exhibit 12(b)..................................................................... 69
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure............................................... 70
PART III
Item 10. Directors and Executive Officers of the Registrant....................... 70
Item 11. Executive Compensation................................................... 72
Item 12. Security Ownership of Certain Beneficial Owners and Management........... 72
Item 13. Certain Relationships and Related Transactions........................... 72
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.......... 73
ii
Experts................................................. 75
Consent of Independent Public Accountants............... 76
Power of Attorney....................................... 76
Signatures.............................................. 77
Exhibit Index........................................... 79
iii
TERMS
The abbreviations or acronyms used in the text and notes are defined below:
ABBREVIATION OR ACRONYM TERM
- -------------------------------------------------------------------------------
AFDC................................Allowance for Funds Used During Construction
Amax..........................................................Amax Coal Company,
a subsidiary of Cyprus/Amax Coal Company
Arapahoe..............................Arapahoe Steam Electric Generating Station
BLM....................................................Bureau of Land Management
Boulder District Court...........District Court in and for the County of Boulder
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..............Public Service Company of Colorado (excluding subsidiaries)
COM...................................................Continuous opacity monitor
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
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.
GCA..........................................................Gas Cost Adjustment
Hayden..................................Hayden Steam Electric Generating Station
IBM..............................................................IBM Corporation
Interstate.......................................Colorado Interstate Gas Company
IPPF.......................................Independent Power Production Facility
IRP.....................................................Integrated Resource Plan
IRS.....................................................Internal Revenue Service
ISFSI................................Independent Spent Fuel Storage Installation
ISSC....................................Integrated Systems Solutions Corporation
KN Energy........................................................KN Energy, Inc.
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
PSCO Gas Companies..........Gas Operations of Public Service Company of Colorado
(excluding subsidiaries) and Cheyenne Light, Fuel
and Power Company
PSRI.......................................................PSR Investments, Inc.
PUHCA.................................Public Utility Holding Company Act of 1935
QF...........................................................Qualifying Facility
QFCCA.............................Qualifying Facilities Capacity Cost Adjustment
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"
SO2...............................................................Sulfur Dioxide
SPS..........................................Southwestern Public Service Company
Synhytech........................................................Synhytech, Inc.
Tri-State................Tri-State Generation and Transmission Association, Inc.
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
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 2.9
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. Further information on the merger is provided in Note 3. Merger in Item
8. Financial Statements And Supplementary Data.
As of December 31, 1995, the Company owned all of the outstanding capital
stock of Cheyenne, WGI, e prime, Fuelco, YGSC, 1480 Welton, Inc., PSRI, PSCCC
and Green and Clear Lakes Company. In addition, the Company owned 80% of the
capital stock of Natural Fuels. These subsidiaries are included in the Company's
consolidated financial statements as is WGT, whose interest in the TransColorado
Project was sold and the company subsequently dissolved, effective December 1,
1995 (see "Natural Gas Operations - WGT").
Cheyenne is an electric and gas utility operating principally in Cheyenne,
Wyoming; WGI is a natural gas transmission company operating in Colorado and
Wyoming; e prime is engaged or intends to engage in energy-related activities
and the provision of consumer services which include, but are not limited to
electric and gas brokering, energy consulting and project development services
and information processing and other technology based services; Fuelco has been
engaged in the exploration for, and the development and production of, natural
gas and oil principally in Colorado; YGSC owns a 47.5% interest in the Young
Storage partnership which owns and operates a gas storage facility in
northeastern Colorado and, effective February 1, 1996, became a subsidiary of e
prime; 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; and 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. 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.
Information regarding industry segments is set forth in Note 14. Segments
of Business in Item 8. Financial Statements And Supplementary Data.
ELECTRIC OPERATIONS
In the Company's IRP, which was approved by the CPUC in 1994 (see
"Regulation and Rates - State Regulation - IRP - Electric"), and its IRP Annual
Progress Report filed with the CPUC in October 1995, the Company proposes to use
the following resources to meet its net dependable system capacity: 1) the
Company's
1
electric generating stations (see Electric Property in Item 2.
Properties); 2) purchases from other utilities and from QFs and IPPFs; 3)
demand-side options and 4) new generation alternatives, including repowering
Fort St. Vrain.
PEAK LOAD
During 1996, net firm system peak demand for the Company and Cheyenne is
estimated to be 4,187 Mw, assuming normal weather conditions. Net dependable
system capacity is projected to be, after accounting for 68 Mw of demand-side
options, 5,097 Mw (generating capacity of 3,313 Mw and firm purchases of 1,784
Mw) at the time of the anticipated 1996 system peak (summer season), resulting
in a reserve margin of approximately 22%.
The net firm system peak demand for the Company and Cheyenne for each of
the last five years was as follows:
1991 1992 1993 1994 1995
----- ----- ----- ----- -----
Net Firm System Peak Demand* (Mw) 3,568 3,757 3,869 3,972 4,248
______________
* Excludes station housepower, nonfirm electric furnace load and controlled
interruptible loads (of which approximately 162 Mw, 156 Mw, 164 Mw, 160 Mw
and 148 Mw in the years 1991-1995, respectively, was not interrupted at the
time of the system peak).
The net firm system peak demand for the Company and Cheyenne for the years
1991-1995 occurred in the summer. The net firm system peak demand for 1995,
which occurred on August 11, 1995, was 4,248 Mw. At that time, the net
dependable system capacity totaled 4,911 Mw (generating capacity of 3,186 Mw,
together with firm purchases of 1,725 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 purchase 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. 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 1996 net firm system peak demand through the expiration
of the contracts:
2
Mw Contracted
For at the Time
of the Anticipated
Generating Summer 1996 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 134 2000
PacifiCorp (d) PacifiCorp Resource Pool 176 2011
Platte River Power Authority (a) (e) Craig Units 1 and 2; 197 2004
Rawhide Unit 1
Tri-State 475 (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
---------
1,784
=========
____________
(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) The current Cheyenne contract originally expired April 1, 1997. However, a
new Cheyenne contract was executed in 1995 with an effective date of
January 1, 1997. As in the previous contract, the new 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: 1996 - 150 Mw, 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.
3
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 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 36% of the total electric system energy input for 1996, the same
as in 1995. In addition, based on the capacity associated with the purchase
power contracts described above, approximately 35% of the total net dependable
system capacity for the estimated summer 1996 net firm system peak demand for
the Company and Cheyenne will be provided by purchased power, compared to
approximately 35% in 1995.
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 1995, approximately 14%
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 higher-cost 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 1995.
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, 1995, the Company and its subsidiaries estimated the cost
of their total construction program, including AFDC, to be approximately $323
million in 1996, and approximately $308 million in both
4
1997 and 1998 (see Item 7. Management's Discussion And Analysis Of Financial
Condition And Results Of Operations).
FORT ST. VRAIN
See Note 2. Fort St. Vrain in Item 8. Financial Statements And
Supplementary Data.
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 subsidiaries 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 $
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
1991...... 1.176 98 1.991 2 1.198
* The average cost per ton of coal, including freight, for years 1991 through
1995 shown above was $22.40, $21.14, $21.03, $20.57 and $19.06,
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 for existing plants through 1997.
Any shortfall will be provided by purchases on the spot market. During the year
ended December 31, 1995, the Company's coal requirements for existing plants
were approximately 8,721,970 tons, a substantial portion of which was supplied
pursuant to long-term supply contracts. Coal supply inventories at December 31,
1995 were approximately 55 days usage, based on the average peak burn rate for
all the Company's coal-fired plants.
The following table is a synopsis of the basic supply provisions of the
existing long-term contracts, which provide a minimum delivery of approximately
86 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 ).
5
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, 1995, 75,103,562 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 1995 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, 1995, 1,583,587 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, 1995, 19,039,334
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 1995 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.
NATURAL GAS OPERATIONS
During the period 1991-1995, the PSCo Gas Companies experienced growth in
the number of commercial and residential customers ranging from 1.3% to 3.1%
annually. Since 1991, commercial and residential gas volumes sold have averaged
152.7 Bcf annually, while industrial volumes sold have declined from 2.5 Bcf in
1991 to 0.05 Bcf in 1995. The growth of commercial and residential sales has
been moderate to strong
6
due primarily to economic conditions in Colorado and Wyoming. Industrial sales
have declined primarily because a majority of industrial customers have switched
to purchasing gas directly from suppliers. In most cases, the PSCo Gas Companies
transport gas from the suppliers to such industrial customers through the PSCo
Gas Companies' transmission and distribution facilities. Fees for this
transportation service, which are paid by these industrial customers,
substantially offset the effect on net income of the revenue loss from decreased
sales of gas to these industrial customers. During 1995, transportation services
of the PSCo Gas Companies generated revenues of $23.8 million compared to $23.5
million in 1994 and $23.2 million in 1993.
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), but is seeking approval
from the SEC to maintain these businesses. If divestiture is ultimately
required, the SEC has historically allowed companies sufficient time to
accomplish divestitures in a manner that protects shareholder value.
Additionally, in the event that divestiture of the gas business is required, the
Company will pursue an alternative corporate organizational structure that will
permit retention of the gas business.
GAS SUPPLY
The PSCo Gas Companies have attempted to maintain low cost, reliable gas
supplies by optimizing the balance between long- and short-term gas purchase
contracts. During 1995, the PSCo Gas Companies purchased 137.0 Bcf (at 14.65
pounds per square inch) from approximately 77 suppliers, including the following
major suppliers: Interstate (38.2 Bcf); Amoco (10.5 Bcf); Barrett Resources
(5.9 Bcf); Coastal Gas Marketing (5.3 Bcf); and KN Gas Supply Services, Inc.
(5.1 Bcf). In 1995, the average delivered cost per Mcf for the PSCo Gas
Companies was $2.31 compared to $2.86 per Mcf in 1994 and $2.82 per Mcf in 1993.
As indicated above, Interstate was the largest supplier to the PSCo Gas
Companies in 1995. During 1993, the PSCo Gas Companies entered into two non-
regulated supply agreements, as allowed under FERC Order 636. Under the
agreement with Interstate, which covers the period from October 1, 1993 through
September 30, 1996, the annual quantities to be purchased declined from 44 Bcf
in the first year to 33 Bcf in the second year and are declining to 22 Bcf in
the third year. Under the agreement with KN Gas Supply Services, Inc., which
covers the period from September 1, 1993 through August 31, 1996, the annual
quantities to be purchased are fixed at 4 Bcf. The Company is in the process of
evaluating its future gas contract requirements and related opportunities.
This continued purchase of gas quantities from Interstate and KN Gas Supply
Services, Inc. will eliminate any Gas Supply Realignment costs otherwise
applicable under FERC Order 636. 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.
YGSC
On June 27, 1995, the Company purchased all the outstanding common stock of
YGSC. YGSC, as a general partner, owns a 47.5% interest in Young Storage, a
partnership between YGSC, CIG Gas Storage Company (a 47.5% general partner), and
the City of Colorado Springs Department of Public Utilities (a 5% limited
partner). Young Storage owns and operates an underground gas storage facility
in northeastern Colorado. The Young Storage facility, when fully developed by
1998, will have a maximum working gas capacity of 5.3 Bcf and a maximum daily
deliverability of 200,000 Mcf. Effective February 1, 1996, the outstanding
common stock of YGSC was transferred to e prime.
On September 13, 1993, the Company signed a thirty year contract with Young
Storage for natural gas storage services with a maximum available capacity of
4.77 Bcf and a maximum daily injection/withdrawal capacity of 180,000 Mcf per
day. The remainder of the storage capacity has been contracted by the City of
Colorado Springs. Young Storage is subject to FERC regulation.
7
WGI
WGI is 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 3.1 Bcf for 1995.
WGT
WGT held a one-third interest in the TransColorado Project, a partnership
for developing a pipeline to transport natural gas out of western Colorado and
the Rocky Mountain Regions into major western and midwestern markets. On
September 25, 1995, WGT sold its interest in the TransColorado Project to El
Paso Natural Gas Co at book value. WGT was dissolved effective December 1, 1995.
(See Note 4. Divestiture of Nonutility Assets - WestGas TransColorado, Inc. in
Item 8. Financial Statements And Supplementary Data.)
FUELCO
Fuelco has been engaged principally in the exploration for, and the
development and production of, natural gas and crude oil. Fuelco also marketed
and brokered natural gas to re-marketers and directly to end users. As part of
the Company's strategy to focus its efforts on its core electric and gas
businesses, during 1994 and 1993, the Company disposed of certain assets related
to the Company's investment in Fuelco and its wholly-owned subsidiary,
Synhytech. The Company is pursuing the divestiture of Fuelco's remaining
assets, which is expected to be completed in 1996 (see Note 4. Divestiture of
Nonutility Assets - Fuel Resources Development Co. in Item 8. Financial
Statements And Supplementary Data).
E PRIME
e prime is engaged or intends to engage in energy related activities and
the provision of consumer 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 has filed an application with the FERC requesting all
requisite approvals and waivers to act as a power marketer.
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 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. 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 holds a FERC certificate which allows it to
transport natural gas in interstate commerce pursuant to the provisions of the
Natural Gas Act. WGI is subject to FERC jurisdiction.
1995 Merger Rate Filings
In connection with the merger with SPS, on November 9, 1995, the Company
filed comprehensive proposals with the CPUC, the FERC and the WPSC to obtain
approval from such regulatory agencies. The CPUC proposal included, among other
things, implementing an electric rate moratorium for five years, allowing for
the sharing of
8
earnings in excess of 12.5% return on equity (determined by utilizing the
combined operations of the electric, gas and steam departments) on a 50/50 basis
between shareholders and customers, retaining the Company's ECA, GCA, and QFCCA
mechanisms, implementing quality of service measures and recovering costs
incurred in connection with the merger (see Note 3. Merger in Item 8 Financial
Statements And Supplementary Data). The quality of service measures included in
the CPUC proposal relate to the following four areas: 1) customer complaints, 2)
phone response time to customer inquiries, 3) response time to customer-
initiated gas odor complaints, and 4) electric service availability. In the
event that the Company does not meet the proposed quality of service measures,
earnings may be reduced by up to $4 million on an annual basis. Additionally,
the proposed sharing of earnings in excess of 12.5% return on equity would
supersede the QFCCA earnings test discussed below. The CPUC has scheduled
hearings on this matter for July and August 1996. The FERC and WPSC have not yet
scheduled any proceedings related to the proposed merger. However, during
January 1996, the FERC issued a Notice of Inquiry concerning its merger policy
under the Federal Power Act to determine whether the criteria and policies for
evaluating mergers need to be revised.
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.
Electric and Gas Adjustment Clauses
The Company's ECA was revised and a new QFCCA was implemented on December
1, 1993, along with the base rate changes resulting from the 1993 rate case (see
"1993 Rate Case"). Under the revised ECA, fuel used for generation and
purchased energy costs from utilities, QFs and IPPFs (excluding all purchased
capacity costs) to serve retail customers, are recoverable. Purchased capacity
costs are recovered as a component of base rates, except as described below.
The ECA rate is revised annually on October 1 and whenever total costs
recoverable through the ECA change by $0.001 per kilowatt hour or more.
Recovered energy costs are compared with actual costs on a monthly basis and
differences, including interest, are deferred. Under the QFCCA, all purchased
capacity costs from new QF projects, not otherwise reflected in base rates, are
recoverable similar to the ECA.
With respect to the QFCCA, the CPUC issued a final decision in January 1996
which required the following: 1) an earnings test be implemented with a 50/50
sharing between the ratepayers and shareholders of earnings in excess of 11%,
the Company's authorized rate of return on regulated common equity; 2) the
calculation will be based on the Company's electric department earnings only;
and 3) implementation will be on a prospective basis effective October 1, 1996,
utilizing a test period for the prior twelve months ended June 30, 1996, unless
superseded by a CPUC decision prior to the effective date. The Company intends
to address this issue in connection with the merger rate filing discussed above.
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 as needed, to
coincide with supplier rate changes. Purchased gas costs and revenues received
to recover such gas costs are compared on a monthly basis and differences,
including interest, are deferred.
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. In addition, the CPUC holds hearings to review the
Company's adjustments made during preceding time periods, and the Company is
required to file quarterly reports on matters relevant to the adjustments.
During 1994, the CPUC initiated proceedings for reviewing the justness and
reasonableness of GCA and ECA mechanisms used by gas and electric utilities
within its jurisdiction. On April 14, 1995, the CPUC issued a final order which
retained the GCA with no modifications and closed its investigation of the GCA
mechanism.
9
With respect to the ECA, in compliance with an order issued by the CPUC in March
1995, the Company completed a filing in September 1995 requesting the CPUC to
open a docket to investigate its ECA. The CPUC opened a docket to review whether
the ECA should be maintained in its present form, altered or eliminated. On
January 8, 1996, the CPUC combined this docket with the merger docket discussed
above.
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 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.
In addition, on June 8, 1994, the CPUC approved the recovery of certain
"energy efficiency credits" from retail jurisdiction customers through the DSMCA
(see Note 9. Commitments and Contingencies - Regulatory Matters in Item 8.
Financial Statements And Supplementary Data).
1993 Rate Case
In November 1993, the CPUC issued its final written decision regarding the
Company's 1993 rate case, authorizing the Company to earn a return on regulated
common equity of 11% and an annual rate of return on regulated rate base of
9.4%, lowering the Company's annual base rate revenue requirement by
approximately $5.2 million (a $13.1 million electric revenue decrease partially
offset by a $7.1 million gas revenue increase and a $0.8 million steam revenue
increase). The new rates became effective December 1, 1993.
The Phase II proceedings of the 1993 Rate Case addressed cost allocation
issues and specific rate changes for the various customer classes based on the
results of the Phase I decision. The CPUC approved a settlement agreement
related to gas rates and the new gas rates were implemented effective October 1,
1995. A final CPUC decision on rehearing, reargument and reconsideration for
the Phase II proceedings related to electric rates was issued in February 1996
with new rates expected to be effective in early 1996.
IRP - Electric
The Company filed its first IRP pursuant to the Electric Integrated
Resource Planning Rules of the CPUC in October 1993. It was subsequently
approved in 1994. The Company's IRP described the mix of resources to be
utilized and/or acquired by the Company for the following three years, including
the repowering of Fort St. Vrain as a gas fired combined cycle steam plant (see
Note 2. Fort St. Vrain in Item 8. Financial Statements And Supplementary Data).
In addition, certain DSM measures were identified and programs implemented which
are intended to reduce the amount of additional capacity required to be supplied
by the Company in the
10
future (see "Electric Operations"). The Company's next IRP is scheduled to be
filed with the CPUC in October 1996.
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 for Cheyenne which are similar
to the Company's ECA and GCA.
FEDERAL ENERGY REGULATORY COMMISSION
On March 29, 1995, the FERC issued a NOPR on Open Access Non-Discriminatory
Transmission Services by Public Utilities and Transmitting Utilities and a
supplemental NOPR on Recovery of Stranded Costs.
The rules proposed in the NOPR are intended to facilitate competition among
electric generators for sales to the bulk power supply market. If adopted, the
NOPR on open access transmission would require public utilities under the
Federal Power Act to provide open access to their transmission systems and would
establish guidelines for their doing so. A final rule would define the terms
under which independent power producers, neighboring utilities, and others could
gain access to a utility's transmission grid to deliver power to wholesale
customers, such as municipal distribution systems, rural electric cooperatives,
or other utilities. Under the NOPR, each public utility would also be required
to establish separate rates for its transmission and generation services for new
wholesale service, and to place transmission services, including ancillary
services, under the same tariffs that would be applicable to third-party users
for all of its new wholesale sales and purchases of energy.
The supplemental NOPR on stranded costs provides a basis for recovery by
regulated public utilities of legitimate and verifiable stranded costs
associated with existing wholesale requirements customers and retail customers
who become unbundled wholesale transmission customers of the utility. The FERC
would provide public utilities a mechanism for recovery of stranded costs that
result from municipalization, former retail customers becoming wholesale
customers, or the loss of a wholesale customer. The FERC will consider allowing
recovery of stranded investment costs associated with retail wheeling only if a
state regulatory commission lacks the authority to consider that issue.
On June 26, 1995, the Company filed transmission tariffs with the FERC that
are intended to meet the comparability of service requirements as set out in the
NOPR ("PSCo Tariffs"). Concurrently with the comparability filing, e prime, a
non-regulated energy services subsidiary of the Company, filed a power marketer
application with the FERC. Subsequently on August 18, 1995, Cheyenne filed
transmission tariffs with the FERC that are intended to meet the NOPR
comparability of service requirements ("Cheyenne Tariffs"). In an order issued
on October 13, 1995, the FERC accepted the PSCo Tariffs and the Cheyenne
Tariffs, subject to modification based on the outcome of the NOPR proceeding,
effective as of August 25, 1995. It is anticipated a final rule, which could be
modified from the current proposal, could take effect in 1996. The FERC also
set the rates in the PSCo Tariffs and Cheyenne Tariffs for hearing. On January
24, 1996, e prime filed with the FERC an amended power marketer application. On
January 26, 1996, PSCo and Cheyenne filed revised tariffs containing terms and
conditions conforming to the FERC's pro forma tariffs as set out in the NOPR.
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.
11
ENVIRONMENTAL MATTERS
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 environmental site clean-up, the Clean Air Act Amendments of
1990 and other environmental matters not discussed below.
At December 31, 1995, the estimated 1996, 1997 and 1998 expenditures for
environmental air and water emission control facilities were $8.8 million, $23.1
million and $23.4 million, respectively. These figures include estimated
expenditures to install SO2 and NOx reduction equipment for the years 1996, 1997
and 1998 of $2.4 million, $5.1 million and $12.8 million, respectively.
The Metro Denver Brown Cloud II Study, designed to investigate the
formation of secondary particulates in the Denver metropolitan area, began in
July 1990 and the results were released in December 1993. The study was
inconclusive and did not offer any policy recommendations. As a result, the
study will not impact the Company's current programs to reduce SO2 and NOx
emissions. However, the Metro area brown cloud continues to be of concern and
the Company is participating in the Metro Area Brown Cloud III Study.
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. Testing at Cherokee Unit 3 was completed in
1995 and testing at the Arapahoe Unit 4 has been extended and is expected to be
completed in July 1996.
The Mount Zirkel Wilderness Area Reasonable Attribution Study, which is
designed to ascertain the contribution of various emission sources to visibility
impairment in the Mount Zirkel Wilderness Area began in 1994. The Company is a
participant in the Hayden and Craig generating stations, in the nearby Yampa
Valley. Additionally, as a result of certain litigation among the joint owners
of the Hayden facility and a conservation organization (see Note 9. Commitments
and Contingencies - Environmental Issues in Item 8. Financial Statements And
Supplementary Data) a settlement is expected to be achieved in the near-term
which the Company believes will result in a requirement to install certain
additional pollution control equipment at the plant.
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 May 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 and 7) Cameo,
effective December 1, 1994. Permit renewal applications were submitted for the
Comanche generating station and Leyden Gas Storage prior to the expiration of
their existing permits. All discharge permits that are not renewed by the 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 IV of the 1990 Clean Air Act Amendments. Permits
were submitted to the state health department to meet 1995 submittal deadlines.
Environmental regulations at the Federal, state and local levels, including
the Clean Air Act Amendments of 1990, some of which are discussed in Note 8.
Commitments and Contingencies - Environmental Issues in Item 8. Financial
Statements And Supplementary Data, are expected to have a continuing impact on
the Company's operations. The Company continues to strive to achieve compliance
with all environmental
12
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.
COMPETITION
INDUSTRY OUTLOOK
Unprecedented change has begun to occur 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, coupled with
the availability of alternative supplies (IPPFs, QFs, EWGs and power marketers),
have created significant pressure for open access to the utility transmission
grid and the creation of 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 1995, the FERC issued a NOPR on Open Access Non-
Discriminatory Transmission Services by Public Utilities and a supplemental NOPR
on the Recovery of Stranded Costs (together, the "FERC Mega NOPR").
Furthermore, an increasing number of states have recently begun to evaluate or
pursue regulatory reform in an effort to proactively respond to this changing
business environment and address the issue of retail wheeling.
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. The concept of a vertically integrated
utility, coupled with current regulatory practices, remain increasingly
incongruent with the economic forces shaping the 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, changes in state and federal utility regulation, and changes in
federal securities laws and securities markets. 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 affect adversely 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 also is changing. 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 Assets and
Liabilities and Note 9. Commitments and Contingencies - Regulatory Matters in
Item 8. Financial Statements And Supplementary Data).
13
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. Since
1992, the Company has had a FERC-approved transmission tariff, which provides
for open access, with certain limitations. In response to the FERC Mega NOPR,
the Company and Cheyenne have filed tariffs containing terms and conditions
conforming to the FERC's pro forma tariffs as set out in the FERC Mega NOPR.
The Company does not anticipate that these provisions will have a material
impact on its operations in the near-term. For 1995, the Company's wholesale
revenues totaled approximately 9% 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 11 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 who 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.
FRANCHISES
The Company and its subsidiaries held nonexclusive franchises to provide
electric or gas service or both services in 119 incorporated cities and towns at
December 31, 1995. These franchises consist of 68 combined gas and electric
service franchises, 28 electric service franchises and 23 gas service
franchises. The Company is currently providing gas and electric service to one
previously franchised municipality while a new franchise is being negotiated.
In 1996, the Company expects to renegotiate two additional 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
5,160 at December 31, 1994 to 4,776 at December 31, 1995. The primary reason for
the decrease was the outsourcing of approximately 370 positions as part of a
ten-year agreement with ISSC, a subsidiary of IBM, to manage most of the
Company's information technology systems and network infrastructure.
Approximately, 2,150 employees, or 45% of the
14
Company's total workforce, are represented by the International Brotherhood of
Electrical Workers, Local 111. The number of employees covered by collective
bargaining agreements at December 31, 1995 approximated 2,340.
In early December 1995, the Company's contracts with the International
Brotherhood of Electrical Workers, Local 111 expired. Previously, an arbitrator
had rejected the Company's attempt to cancel the contract. The parties have been
unable to reach agreement through the negotiation process and, as a result, will
enter binding arbitration on March 20, 1996, as required under the provisions of
the contracts. Contract provisions will be determined as part of the binding
arbitration process including the length of the contract extension and wages.
In addition, the International Brotherhood of Electrical Workers, Local 111 has
filed a grievance relating to the employment of certain non-union personnel to
perform services for the Company, which matter is currently in arbitration.
RESEARCH AND DEVELOPMENT
The Company and its utility subsidiaries spent approximately $3.6 million
in 1995, $3.8 million in 1994 and $4.3 million in 1993 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.
15
CONSOLIDATED ELECTRIC OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- -----------
Energy Generated, Received, & Sold (Thousands of Kwh):
Net Generated:
Steam, Fossil........................................... 16,053,928 15,949,980 15,470,247 14,972,688 13,164,941
Combustion Turbine...................................... 5,251 41,705 39,228 47,194 7,643
Pumped Storage.......................................... 68,400 126,721 118,593 79,609 68,988
Hydro................................................... 208,104 176,264 198,272 175,010 147,686
----------- ----------- ----------- ----------- -----------
Total Net Generation.................................. 16,335,683 16,294,670 15,826,340 15,274,501 13,389,258
Energy Used for Pumping................................. 109,632 201,744 185,850 126,266 111,008
----------- ----------- ----------- ----------- -----------
Total Net System Input................................ 16,226,051 16,092,926 15,640,490 15,148,235 13,278,250
Purchased Power and Net Interchange...................... 9,794,968 9,653,067 9,631,982 8,663,339 8,738,907
----------- ----------- ----------- ----------- -----------
Total System Input.................................... 26,021,019 25,745,993 25,272,472 23,811,574 22,017,157
Used by Company......................................... 64,885 66,348 60,396 64,125 71,506
Other(1)................................................ 1,526,358 1,670,591 2,001,832 1,932,333 1,493,291
----------- ----------- ----------- ----------- -----------
Total Energy Sold..................................... 24,429,776 24,009,054 23,210,244 21,815,116 20,452,360
=========== =========== =========== =========== ===========
Electric Sales (Thousands of Kwh)(2):
Residential............................................. 6,281,911 6,119,914 5,969,529 5,747,048 5,699,374
Commercial.............................................. 9,284,577 8,931,962 10,797,272 10,350,155 10,307,829
Industrial.............................................. 5,747,534 5,726,837 3,289,501 3,375,638 3,334,405
Public Authorities...................................... 188,363 187,939 186,397 187,500 184,315
Other Utilities(3)...................................... 2,927,391 3,042,402 2,967,545 2,154,775 926,437
----------- ----------- ----------- ----------- -----------
Total Energy Sold..................................... 24,429,776 24,009,054 23,210,244 21,815,116 20,452,360
=========== =========== =========== =========== ===========
Number of Customers at End of Period(2):
Residential............................................. 936,759 913,582 898,752 894,217 880,676
Commercial.............................................. 123,277 120,886 120,317 120,198 119,118
Industrial.............................................. 378 384 157 194 179
Public Authorities...................................... 79,154 77,842 76,476 647 660
Other Utilities(3)...................................... 17 18 20 34 29
----------- ----------- ----------- ----------- -----------
Total Customers...................................... 1,139,585 1,112,712 1,095,722 1,015,290 1,000,662
=========== =========== =========== =========== ===========
Electric Revenues (Thousands of Dollars)(2):
Residential............................................. $ 477,740 $ 453,614 $ 433,521 $ 413,655 $ 403,095
Commercial.............................................. 552,905 519,340 602,187 572,780 568,588
Industrial.............................................. 257,189 252,552 142,146 148,951 147,997
Public Authorities...................................... 23,029 21,950 20,828 20,221 19,256
Other Utilities (3)..................................... 114,514 120,238 116,937 80,290 35,480
Other Electric Revenues................................. 23,719 32,142 21,434 24,872 6,085
----------- ----------- ----------- ----------- -----------
Total Electric Revenues............................... $ 1,449,096 $ 1,399,836 $ 1,337,053 $ 1,260,769 $ 1,180,501
=========== =========== =========== =========== ===========
Average Annual Kwh Sales per Residential Customer........ 6,794 6,770 6,717 6,533 6,563
Average Annual Revenue per Residential Customer.......... $516.70 $501.82 $487.81 $470.26 $464.17
Average Residential Revenue per Kwh...................... 7.61c 7.41c 7.26c 7.20c 7.07c
Average Commercial Revenue per Kwh....................... 5.96c 5.81c 5.58c 5.53c 5.52c
Average Industrial Revenue per Kwh....................... 4.47c 4.41c 4.32c 4.41c 4.44c
Average Other Utilities Revenue per Kwh.................. 3.91c 3.95c 3.94c 3.73c 3.83c
- -------------------------
(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.
(3) Includes sales to four additional wholesale customers, resulting from the
April 1992 Colorado-Ute asset acquisition.
16
CONSOLIDATED GAS OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1995 1994 1993 1992 1991
-------- -------- --------- -------- --------
Natural Gas Purchased and Sold (Thousands of Mcf)(1):
Purchased from Interstate.............................. 45,248 53,337 64,494 69,309 68,398
Purchased from Others.................................. 118,431 104,102 103,609 92,302 96,358
Purchased for e prime Marketing........................ 277 - - - -
-------- -------- -------- -------- --------
Total Purchased..................................... 163,956 157,439 168,103 161,611 164,756
Company Use............................................ 1,555 2,817 2,750 3,041 2,262
Other(2)............................................... 6,616 4,515 (2,111) 7,070 2,628
-------- -------- -------- -------- --------
Total Gas Sold....................................... 155,785 150,107 167,464 151,500 159,866
======== ======== ======== ======== ========
Gas Deliveries (Thousands of Mcf)(1):
Residential............................................ 96,126 92,036 98,350 87,560 91,807
Commercial............................................. 59,250 57,366 62,193 57,321 61,266
Industrial............................................. 48 118 1,097 1,772 2,468
Public Authorities..................................... - - 88 141 134
Other Utilities........................................ 361 587 5,736 4,706 4,191
-------- -------- -------- -------- --------
Total Gas Sold...................................... 155,785 150,107 167,464 151,500 159,866
Transported Gas........................................ 88,543 78,194 71,922 60,404 54,214
Gathered and Processed Gas(3).......................... 1,627 29,889 42,010 33,052 18,622
-------- -------- -------- -------- --------
Total Deliveries..................................... 245,955 258,190 281,396 244,956 232,702
======== ======== ======== ======== ========
Number of Customers at End of Period:
Residential............................................ 872,777 845,464 820,521 808,722 792,646
Commercial............................................. 89,033 87,077 86,202 85,954 85,317
Industrial............................................. 3 26 25 237 331
Public Authorities..................................... - - - 1 1
Other Utilities........................................ - 8 8 8 9
-------- -------- -------- -------- --------
Total................................................ 961,813 932,575 906,756 894,922 878,304
Transported Gas and Other.............................. 952 786 619 416 275
-------- -------- -------- -------- --------
Total Customers...................................... 962,765 933,361 907,375 895,338 878,579
======== ======== ======== ======== ========
Gas Revenues (Thousands of Dollars):
Residential............................................ $383,719 $375,406 $366,445 $329,406 $343,692
Commercial............................................. 200,490 202,873 201,693 185,851 198,160
Industrial............................................. 223 438 2,887 5,213 7,765
Public Authorities..................................... - - 240 302 371
Other Utilities........................................ 4,961 7,319 13,966 10,099 9,198
Transported Gas........................................ 23,769 23,495 23,176 20,638 18,966
Gathered and Processed Gas............................. 443 8,335 10,575 8,023 5,465
Other Gas Revenues..................................... 10,980 7,056 9,342 9,354 3,992
-------- -------- -------- -------- --------
Total Gas Revenues.................................. $624,585 $624,922 $628,324 $568,886 $587,609
======== ======== ======== ======== ========
Average Annual Mcf Sales per Residential Customer...... 111.87 110.59 120.85 109.5 116.8
Average Annual Revenue per Residential Customer......... $446.58 $451.09 $450.29 $411.94 $437.40
Average Residential Revenue per Mcf..................... $3.992 $4.079 $3.726 $3.762 $3.744
Average Commercial Revenue per Mcf...................... $3.384 $3.536 $3.243 $3.242 $3.234
Average Transport Gas Revenue per Mcf................... $0.268 $0.300 $0.322 $0.342 $0.350
- -------------------------
(1) Volumes are reported at local pressure base.
(2) Primarily includes distribution and transmission line losses and net
changes to gas in storage.
(3) In August 1994, the Company sold its investment in WGG which resulted in
the decline in gathered and processed gas deliveries.
17
MAP OF
ELECTRIC TRANSMISSION
INTERCONNECTED SYSTEM
APPEARS HERE
18
ITEM 2. PROPERTIES
ELECTRIC PROPERTY
The electric generating stations of the Company and its subsidiaries
expected to be available at the time of the anticipated 1996 net firm system
peak demand during the summer season are as follows:
Net Dependable
Capacity
Installed (Mw)
Gross at Time of Anticipated Major
Name of Station Capacity 1996 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
Fort St. Vrain - near Platteville......... 130.00 (b) 126.00 Gas
Hayden-near Hayden........................ 259.47 (c) 236.90 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................................... 3,157.37 2,927.80
Combustion turbines (6 units-various locations).. 209.00 171.00 Gas
Hydro (14 units-various locations) (d)........... 53.35 36.55 (e) Hydro
Cabin Creek Pumped Storage-near Georgetown....... 324.00 (f) 162.00 Hydro
Diesel generators (7 units-various locations).... 15.50 15.50 Oil
-------- --------
Total................................... 3,759.22 3,312.85
======== ========
________________
* 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) It is anticipated that Phase 1A will come on-line in May 1996.
(c) 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.
(d) Includes one station (two units) not owned by the Company but operated
under contract.
(e) 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.
(f) Capability at maximum load.
NUCLEAR PROPERTY
Fort St. Vrain, near Platteville, the Company's only previous nuclear
generating station, ceased operations on August 29, 1989 (see Note 2. Fort St.
Vrain in Item 8. Financial Statements And Supplementary Data) and is in the
process of being repowered as a gas fired electric generating station.
TRANSMISSION AND DISTRIBUTION PROPERTY
On December 31, 1995, the Company's transmission system consisted of
approximately 112 circuit miles of 345 Kv overhead lines; 1,864 circuit miles of
230 Kv overhead lines; 15 circuit miles of 230 Kv underground lines; 65 circuit
miles of 138 Kv overhead lines; 996 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
19
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 18 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, 1995, the distribution systems consisted primarily of
approximately 12,927 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 7,629 cable miles of underground distribution system
(excluding street lighting) located principally in the Denver metropolitan area.
The Company owned 218 substations (four of which are jointly owned) having an
aggregate transformer capacity of 18,619,300 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, 1995 consisted chiefly of
approximately 14,977 miles of distribution mains ranging in size from 0.50 to 30
inches and related equipment. The Denver distribution system consisted of 8,522
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.
OTHER PROPERTY
The Company's steam heating property at December 31, 1995 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.
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, except for the exploration, development and production properties still
held by Fuelco (see Note 4. Divestiture of
20
Nonutility Assets - Fuel Resources Development Co. in Item 8. Financial
Statements And Supplementary Data). Unregulated subsidiary property is
approximately 2% 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 2. Fort St. Vrain and Note 9. Commitments and Contingencies in
Item 8. Financial Statements And Supplementary Data.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On January 31, 1996, the Company held a Special Meeting of Shareholders at
which shareholders were asked to approve the Merger Agreement pursuant to which
the holders of Company common stock and holders of SPS common stock will become
holders of the common stock of NCE upon the completion of the merger. The merger
was approved by the shareholders. Of the shares voted, 50,934,837, 1,366,283,
and 824,460 votes were cast for, against, and abstained, respectively (see Note
3. Merger in Item 8. Financial Statements And Supplementary Data).
Approximately 72% of the Company's outstanding shares of common and preferred
stock were voted in favor of the merger. An affirmative vote of two-thirds of
the outstanding shares was required for approval.
21
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
- ------------------- --------- ----------- -------
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
1994
First Quarter... $ .50 $32 1/8 $28 1/2
Second Quarter.. .50 29 3/4 25 3/8
Third Quarter... .50 27 7/8 24 3/4
Fourth Quarter.. .50 30 1/8 25 7/8
----
$2.00
At December 31, 1995, the book value of the common stock was $21.21 per
share. At February 20, 1996, there were 60,704 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. The Company is subject to numerous uncertainties, including the
approval by various regulatory agencies of the merger between the Company, SPS
and NCE. 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.
22
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, 1995
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,
---------------------------------------------------------------
1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- -----------
(IN THOUSANDS-EXCEPT PER SHARE DATA & RATIOS)
Operating revenues:
Electric............................................ $1,449,096 $1,399,836 $1,337,053 $1,260,769 $1,180,501
Gas................................................. 624,585 624,922 628,324 568,886 587,609
Other............................................... 36,920 32,626 33,308 32,618 26,794
---------- ---------- ---------- ---------- ----------
Total.......................................... 2,110,601 2,057,384 1,998,685 1,862,273 1,794,904
Total operating expenses................................ 1,788,851 1,786,592 1,717,752 1,612,646 1,551,326
Operating income........................................ 321,750 270,792 280,933 249,627 243,578
Total interest charges.................................. 143,906 132,134 130,337 121,116 101,537
Net income.............................................. 178,856 170,269 157,360 136,623 149,693
Dividend requirements on preferred stock................ 11,963 12,014 12,031 12,077 12,234
Earnings available for common stock..................... 166,893 158,255 145,329 124,546 137,459
Per share data applicable to common stock (a):
Earnings............................................ $ 2.65 $ 2.57 $ 2.43 $ 2.16 $ 2.48
Dividends declared.................................. $ 2.04 $ 2.00 $ 2.00 $ 2.00 $ 2.00
Shares of common stock outstanding:
Weighted average.................................... 62,932 61,547 59,695 57,558 55,471
Year-end............................................ 63,358 62,155 60,457 58,477 56,294
Rate of return earned on average common equity
(net to common)..................................... 12.8% 12.9% 12.7% 11.7% 13.8%
Ratio of earnings to fixed charges (b).................. 2.78 2.53 2.54 2.43 2.94
Total assets............................................ $4,354,295 $4,207,832 $4,057,600 $3,759,583 $3,462,668
Total net plant......................................... 3,480,712 3,291,402 3,193,136 3,077,509 2,745,800
Total construction expenditures......................... 285,516 317,138 293,515 261,666 260,704
AFDC.................................................... 7,095 7,158 12,667 11,302 9,437
Cash generated internally as a percent of
construction expenditures (c)....................... 87.4% 35.4% 52.2% 57.5% 69.4%
Total common equity..................................... $1,343,645 $1,267,482 $1,184,183 $1,101,047 $1,034,433
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)........ 43,865 45,241 45,454 45,654 46,368
Long-term debt (including amounts due within one year).. 1,278,389 1,180,580 1,193,668 1,199,779 993,965
Notes payable & commercial paper........................ 288,050 324,800 276,875 250,626 200,640
- -------------------------
(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.
23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
INDUSTRY OUTLOOK
The electric utility industry is continuing to experience unprecedented change
which, in turn, has heightened competitive pressures that are expected to
further increase in the future. In general, the industry is transitioning to a
deregulated environment as discussions on retail wheeling and alternative forms
of regulation are occurring in the majority of states across the country.
However, to date, only a few states have made substantial progress in
establishing competitive markets. Additionally, several factors have
contributed to such change including the EPAct, the FERC's NOPR on Open Access
Non-Discriminatory Transmission Services and an increase in the number of power
marketers which are accelerating the development of a competitive power supply
market. Most recently federal legislation related to deregulation of the
electric utility industry was introduced. During 1995, the SEC completed its
study and recommendations for the reform of PUHCA, the law which regulates the
ownership and operation of public utility holding companies.
Furthermore, customers are focusing on their energy costs and are demanding
lower prices, reliable service and more energy service options. Utilities and
regulators are concerned about meeting customers' needs and maintaining
financial stability during this time of change. In order to survive and succeed
in the increasingly competitive environment, utilities are implementing
strategic plans to cut costs and lower prices. Many of the strategic plans
include restructuring, realigning existing operations or merging with other
utilities to achieve economies of scale and increase overall productivity and
efficiency. While no one can predict how and when this will all be achieved,
the future changes are certain to have a major impact on the industry as we know
it today.
CORPORATE OVERVIEW
The Company is continuing to proactively assess the changes in the industry
and has taken several steps over the past few years which have focused on
improving the Company's overall competitive position. In August 1995, the
Company, SPS and NCE entered into a Merger Agreement providing for a business
combination as peer firms involving the Company and SPS in a "merger of equals"
transaction. The Company believes that the combination with a strong low-cost
utility will better position the Company to take advantage of opportunities in
its core utility and related non-utility businesses. In addition, the merger
will permit the Company to derive benefits from the more efficient and economic
utilization of combined facilities and personnel. Shareholders are expected to
benefit over the long-term from the Company's greater financial strength and
flexibility. The combined service territories will be larger and more diverse,
reducing the Company's exposure to changes in economic, competitive or climatic
conditions. Purchasing savings, increased economical use of generation capacity
and reduced administrative costs are anticipated as well. These benefits are
discussed in more detail in Note 3. Merger in Item 8. Financial Statements And
Supplementary Data.
In 1994, the Company reduced its workforce by approximately 1,100 management
and staff positions, or 17% of its total workforce. This was accomplished
through an early retirement/severance program in early 1994 and an internal
restructuring and involuntary severance program which was completed at the end
of 1994. The net labor and employee benefit cost savings during 1995 from this
downsizing was approximately $26 million. Other cost reduction and marketing
initiatives during 1995 included: 1) the organization of e prime, a wholly owned
subsidiary, to develop and market energy products and services in a non-
regulated environment, 2) the consolidation of customer service offices and 3)
the installation of automated meter reading equipment. Operating priorities in
1996 will continue to be focused on reducing costs and developing new business
opportunities.
Competition in the wholesale energy market, and to a lesser extent in the
retail market, has become more evident within the region served by the Company.
Wholesale electric prices have decreased as the number of energy suppliers,
including power marketers, have entered the market and utilities have become
more aggressive in their pricing. One of the Company's largest wholesale
customers received approval from the CPUC to build a combined-cycle generating
facility in southern Colorado. Previously, this wholesale customer had notified
the Company of its intent to reduce firm and peaking power purchases in the
future. The Company is exploring various opportunities with this customer
related to the construction of the proposed generation facility and the
24
customer's on-going future purchases of electric energy from the Company to
minimize the impact of the potential loss of sales beginning in 1998.
The regulatory environment within Colorado is a primary focus for the Company
and the outcome of the Company's 1995 merger rate filings will likely have long-
term effects on the Company's future financial performance (see Note 9.
Commitments and Contingencies - Regulatory Matters in Item 8. Financial
Statements And Supplementary Data). 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.
EARNINGS
Earnings per share were $2.65, $2.57 and $2.43 during 1995, 1994 and 1993,
respectively. The improved earnings in 1995 are primarily attributable to
increased electric and gas margins resulting from higher sales and lower
operating and maintenance expenses resulting from the cost containment efforts
that were implemented in 1994 and 1995. Earnings in 1994 were favorably
impacted by higher electric sales and the net effects of three one-time items
which increased earnings for that period by approximately $0.22 per share.
These one-time items included: 1) the gain recognized on the sale of WGG, 2) a
tax accrual adjustment, which positively impacted earnings, and 3) additional
expenses associated with the defueling and decommissioning of Fort St. Vrain.
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
1995 1994
---------- ----------
(THOUSANDS OF DOLLARS)
Electric operating revenues:
Retail....................................................................... $ 63,407 $48,774
Wholesale.................................................................... (5,724) 3,301
Other (including unbilled revenues).......................................... (8,423) 10,708
------ -------
Total revenues.............................................................. 49,260 62,783
Fuel used in generation....................................................... (16,123) 3,200
Purchased power............................................................... 44,871 40,134
------ -------
Net increase in electric margin............................................... $ 20,512 $19,449
======= =======
The following table summarizes electric Kwh sales by major customer classes:
MILLIONS OF % CHANGE
KWH SALES FROM PRIOR YEARS
--------------- ----------------
1995 1994 1995 1994
------ ------ ------ ------
Residential................................................................... 6,282 6,120 2.6% 2.5%
Commercial and Industrial..................................................... 15,032 14,659 2.5 4.1
Public Authority.............................................................. 189 188 0.2 0.8
------ -------
Total Retail................................................................ 21,503 20,967 2.6 3.6
Wholesale..................................................................... 2,927 3,042 (3.8) 2.5
------ -------
Total....................................................................... 24,430 24,009 1.8 3.4
====== =======
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 a result of lower wholesale Kwh sales.
The demand for wholesale energy during 1995 has been negatively impacted by an
available supply of low-cost non-firm energy in
25
the region. Electric operating revenues and electric sales were higher in 1994,
when compared to 1993, primarily due to customer growth and favorable weather,
as 1994 was significantly warmer than normal. Electric revenues increased
because of the additional collection of purchased power, decommissioning, and
DSM costs and were negatively impacted by the reduction in retail rates which
resulted from the Company's last retail rate case.
Base rates are changed only through rate proceedings of the Company's and
Cheyenne's regulatory agencies. Effective December 1, 1993, in connection with
the final 1993 rate decision issued by the CPUC, the Company reduced its retail
rates by approximately $5.2 million. This $5.2 million is comprised of a $13.1
million electric revenue decrease, a $7.1 million gas revenue increase and a
$0.8 million steam revenue increase. Also, effective July 1, 1993, a $13.9
million annual revenue increase associated with the recovery of nuclear
decommissioning costs was implemented.
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 1995, 1994
and 1993 had little impact on net income.
Fuel used in generation expense decreased $16.1 million, or 8.1% 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. Fuel used in generation expense
increased 1.6% in 1994, when compared to 1993, due to higher generation levels.
Purchased power expense increased 10.3% in 1995 and 10.1% in 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. A majority of purchased power costs associated with QFs have
historically been collected through the QFCCA, a cost adjustment mechanism;
however, the future recovery of costs under the QFCCA was recently modified by
the CPUC and will be subject to an earnings test, beginning October 1, 1996.
The Company intends to address this issue in connection with the merger rate
filing. This earnings test, if not changed or eliminated, may negatively impact
the ability of the Company to earn a rate of return on common equity in excess
of its current 11% allowed return in the electric department (see Note 9.
Commitments and Contingencies-Regulatory Matters in Item 8. Financial Statements
And Supplementary Data).
GAS OPERATIONS
The following table details the annual change in gas operating revenues and
gas purchased for resale as compared to the preceding year:
INCREASE (DECREASE)
FROM PRIOR YEARS
1995 1994
----------- -----------
(THOUSANDS OF DOLLARS)
Gas operating revenues................................... $ (337) $ (3,402)
Less: gathering, processing and transportation revenues.. (7,618) (1,921)
------- --------
Revenues from gas sales.................................. 7,281 (1,481)
Gas purchased for resale................................. (5,197) 13,484
------- --------
Net increase (decrease) in gas sales margin.............. $12,478 $(14,965)
======= ========
26
The following table summarizes gas Mcf deliveries by major customer classes:
MILLIONS OF % CHANGE
MCF DELIVERIES FROM PRIOR YEARS
-------------- ------------------
1995 1994 1995 1994
------ ------ ------- ---------
Residential................ 96.1 92.0 4.4% (6.4)%
Commercial and Industrial.. 59.3 57.5 3.2 (9.2)
Other...................... 0.4 0.6 (38.6) (89.9)
----- -----
Total Sales............. 155.8 150.1 3.8 (10.4)
Gathering and Processing... 1.6 29.9 (94.6) (28.9)
Transportation............. 88.6 78.2 13.2 8.7
----- -----
Total.................... 246.0 258.2 (4.7) (8.2)
===== =====
Gas sales margin increased in 1995 and declined in 1994 primarily due to
changes in retail gas sales resulting from weather variations. There were
approximately 17% more heating degree days in 1995, as compared to 1994, and
approximately 16% fewer heating degree days in 1994, as compared to 1993.
Moderate customer growth has favorably impacted all periods. The approximate
$7.1 million base rate increase, effective December 1, 1993 (as discussed above)
mitigated some of the effects of lower sales in 1994, compared to the prior
year. The decrease in gathering and processing revenues and deliveries in 1995
and 1994 was primarily due to the sale of WGG in August 1994 (See Note 4.
Divestiture of Nonutility Assets in Item 8. Financial Statements And
Supplementary Data). Gas transportation deliveries have increased in each of
the past two years primarily because of service provided to new QF customers.
The Company and Cheyenne have in place GCA mechanisms for natural gas
sales, which recognize the majority of the effects of changes in the cost of gas
purchased for resale and adjust revenues to reflect such changes in cost on a
timely basis. As a result, the changes in revenues associated with these
mechanisms in 1995 and 1994, 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, affect total gas
purchased for resale along with increases and decreases in the per-unit cost of
gas. 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. The increase in gas purchased for resale for 1994
reflects the higher price of gas purchased from the Company's major suppliers.
NON-FUEL OPERATING EXPENSES
Other operating and maintenance expenses decreased approximately $22
million or 5% 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 $4.0 million of costs related
to the merger (see Note 3. Merger in Item 8. Financial Statements And
Supplementary Data), 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.
Other operating and maintenance expenses decreased $16.7 million during
1994 as compared to 1993, primarily due to lower labor costs resulting from the
early retirement/severance program, decreased maintenance expenses at the
Company's steam generating plants and lower Fuelco operation costs. These
decreases were offset, in part, by increased OPEB costs and the severance costs
associated with the Company's involuntary workforce reduction.
27
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).
Taxes (other than income taxes) decreased $5.1 million in 1995 primarily
due to lower payroll related taxes resulting from the 1994 downsizing.
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). The $12.5 million decrease in
income tax expense in 1994, as compared to 1993, was primarily due to the two
1994 items previously discussed (See Note 13. Income taxes in Item 8. Financial
Statements And Supplementary Data).
Other income and deductions decreased $30.6 million during 1995 as compared
to the preceding year, 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.
Divestiture of Nonutility Assets in Item 8. Financial Statements And
Supplementary Data) and 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. Other income and deductions increased $24.8 million in 1994, as
compared to 1993, primarily due to the gain on the sale of WGG offset, in part,
by lower AFDC and the reversal of the gas search award.
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. Interest charges increased $1.8 million in 1994, as
compared to 1993, primarily due to increased levels of short-term borrowings
offset, in part, by a decrease in interest on long-term debt, net of
amortization costs because the Company refinanced certain long-term debt issues
with lower-cost debt.
FINANCIAL POSITION
Accounts receivable decreased at December 31, 1995 as compared to 1994,
despite overall sales growth, due to the lower gas costs and because a portion
of the gas refund made late in 1995 was applied directly to customers' accounts.
The decrease in accounts payable is primarily due to lower gas costs and the
implementation of certain cost reduction strategies during 1995.
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED
In March 1995, the FASB issued SFAS 121, which requires the Company to
review long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. This statement also imposes stricter criteria for continued
recognition of regulatory assets by requiring that such assets be probable of
future recovery at each balance sheet date. The Company adopted this standard
on January 1, 1996, the effective date of this new statement, and such adoption
did not have a material impact on the Company's results of operations, financial
position or cash flow.
COMMITMENTS AND CONTINGENCIES
Issues relating to Fort St. Vrain, the merger with SPS, and regulatory and
environmental matters are discussed in Notes 2, 3 and 9, respectively, in Item
8. Financial Statements And Supplementary Data.
28
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 1995, the Company increased 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
1995 1994 1993
------ ------ ------
Net cash provided by operating activities (in millions) $385.7 $245.7 $279.9
Cash provided by operating activities increased $140.0 million in 1995.
Approximately $47.5 million of this increase relates to the collection of
purchased gas and electric energy costs during 1995, as the Company went from an
undercollected position at December 31, 1994 to an overcollected position at
December 31, 1995. During late 1995, the Company made gas refunds totaling
approximately $81 million, including interest. Portions of these refunds were
applied directly to customers' accounts which decreased the accounts receivable
balance at year-end and, accordingly, will result in lower cash receipts in
early 1996. Higher earnings and lower decommissioning and defueling
expenditures in 1995 also contributed to the improved operating cash flows.
At December 31, 1995, the Company's decommissioning liability, excluding
defueling, was approximately $24.0 million. The expenditures related to this
obligation are expected to be incurred over the next year with final completion
of such activities anticipated in 1996. The annual decommissioning amount being
recovered from customers is approximately $13.9 million which will continue
through June 2005. At December 31, 1995, approximately $97.8 million remains to
be collected from customers and is reflected as a regulatory asset on the
consolidated balance sheet. Accordingly, operating cash flows will continue to
be negatively impacted until the decommissioning of Fort St. Vrain is complete.
1995 1994 1993
-------- -------- --------
Net cash used in investing activities (in millions) $(284.6) $(177.4) $(239.3)
Cash used in investing activities for construction expenditures, net of
AFDC, was approximately $281.7 million, $314.0 million and $285.4 million for
1995, 1994 and 1993, respectively. Additionally, in 1995 the Company purchased
YGSC which invested approximately $6 million in Young Storage. Cash used in
investing activities was higher in 1995, as compared to both 1994 and 1993,
primarily due to the sale of WGG in 1994 and the sale of certain Fuelco
properties during 1994 and 1993 (See Note 4. Divestiture of Nonutility Assets in
Item 8. Financial Statements And Supplementary Data).
1995 1994 1993
------- ------- ------
Net cash used in financing activities (in millions) $(92.3) $(80.5) $(73.7)
Cash used in financing activities increased slightly in 1995 over each of
the past two years. Proceeds from the sale of common stock under the Company's
dividend reinvestment and stock purchase plan were $28.0 million, $38.1 million
and $47.9 million for 1995, 1994 and 1993, respectively. The decrease in these
proceeds has reduced the cash proceeds from financing activities. Long-term
debt refinancing activity decreased in 1995, compared to 1994 and 1993, 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.
29
PROSPECTIVE CAPITAL REQUIREMENTS
At December 31, 1995, the Company and its subsidiaries estimated cost of
their construction programs and other capital requirements for the years 1996,
1997 and 1998 are shown in the table below:
1996 1997 1998
-------- -------- --------
(THOUSANDS OF DOLLARS)
Company:
Electric
Production *................................ $ 58,731 $68,197 $112,047
Transmission................................ 25,372 16,669 21,600
Distribution................................ 71,734 82,435 76,443
Gas............................................ 53,135 54,802 53,893
General**...................................... 103,346 81,532 39,987
-------- ------- --------
Total Company............................... 312,318 303,635 303,970
Subsidiaries................................... 11,044 4,250 3,931
-------- -------- --------
Total construction expenditures............. 323,362 307,885 307,901
Less: AFDC..................................... 9,193 7,863 4,842
Add: Sinking funds and debt maturities......... 78,811 70,854 52,905
Add: Fort St. Vrain decommissioning and
defueling.................................... 29,625 333 343
-------- -------- --------
Total capital requirements................. $422,605 $371,209 $356,307
======== ======== ========
* Capital requirements for Electric Production include $84 million for Fort St.
Vrain repowering.
** Capital requirements in the "General" category include assets leased under a
leasing program. The 1996 and 1997 amounts include approximately $92 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. Divestiture of Nonutility Assets and Note 9. Commitments and
Contingencies-Environmental Issues in Item 8. Financial Statements And
Supplementary Data).
CAPITAL SOURCES
At December 31, 1995, the Company and its subsidiaries estimated that their
1996-1998 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 plans of the Company and its
subsidiaries.
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
30
stock through the reinvestment of cash dividends and the purchase of additional
shares of common stock with optional cash payments.
In 1990, the Company filed a registration statement with the SEC for the
issuance of $500 million principal amount of first mortgage bonds of which $200
million was designated for a secured medium-term note program. As of December
31, 1995, $191.5 million principal amount of medium-term notes had been issued,
and $250 million of first mortgage bonds had been issued. In 1993, the Company
filed a registration statement with the SEC for the issuance of $322,667,000
principal amount of first collateral trust bonds for the purpose of refunding
outstanding debt securities and for the payment of short-term indebtedness
incurred for such purposes, of which $212,667,000 principal amount has been
issued.
On August 2, 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 $306.0
million. To date none of these registered securities have been issued.
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, 1995,
the amount of net additions would permit (and the net earnings test would not
prohibit) the issuance of approximately $357 million of new bonds (in addition
to the $200 million principal amount of secured medium-term notes discussed
above) at an assumed annual interest rate of 7.25%. At December 31, 1995, the
amount of retired bonds would permit the issuance of $890 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
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, 1995,
coverage under the net earnings test was in excess of 6 times such annual
interest requirements.
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, 1995, 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 $2.8 billion of additional preferred stock
at an assumed annual dividend rate of 6.60%. Coverage of gross income to
interest charges was 5.49 at December 31, 1995.
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, 1995, the Company had outstanding unsecured indebtedness,
including subsidiary
31
indebtedness with the credit support of the Company, in the amount of $150.6
million. The maximum amount permitted under this limitation was approximately
$393.2 million at December 31, 1995.
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 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,
1995, $12.0 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 $100
million, and all remained unused at December 31, 1995. These individual
arrangements expire on December 31, 1996. 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,
1995, PSCCC had issued and had outstanding $80.0 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 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,
1995 and 1994, and the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1995. 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, 1995 and 1994, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1995, in conformity with generally accepted accounting
principles.
As more fully discussed in Notes 11 and 13 to the consolidated financial
statements, effective January 1, 1993, the Company changed its methods of
accounting for postretirement benefits other than pensions and for income taxes
and, 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, 1993, 1992 and 1991 and the
related consolidated statements of income, shareholders' equity and cash flows
for each of the two years in the period ended December 31, 1992, (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, 1995
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 15, 1996
33
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
DECEMBER 31, 1995 AND 1994
ASSETS
1995 1994
---------- ----------
Property, plant and equipment, at cost:
Electric......................................................................... $3,751,321 $3,641,711
Gas.............................................................................. 989,215 867,239
Steam and other.................................................................. 88,446 86,458
Common to all departments........................................................ 380,809 369,070
Construction in progress......................................................... 192,580 187,577
--------- ---------
5,402,371 5,152,055
Less: accumulated depreciation................................................... 1,921,659 1,860,653
--------- ---------
Total property, plant and equipment............................................. 3,480,712 3,291,402
--------- ---------
Investments, at cost.............................................................. 24,282 18,202
--------- ---------
Current assets:
Cash and temporary cash investments.............................................. 14,693 5,883
Accounts receivable, less reserve for uncollectible accounts ($3,630 at December
31, 1995; $3,173 at December 31, 1994) (Schedule II).......................... 124,731 163,465
Accrued unbilled revenues (Note 1)............................................... 96,989 86,106
Recoverable purchased gas and electric energy costs - net (Note 1)............... - 37,979
Materials and supplies, at average cost.......................................... 56,525 67,600
Fuel inventory, at average cost.................................................. 35,654 31,370
Gas in underground storage, at cost (LIFO)....................................... 44,900 42,355
Current portion of accumulated deferred income taxes (Note 13)................... 19,229 20,709
Regulatory assets recoverable within one year (Note 1)........................... 40,247 39,985
Prepaid expenses and other....................................................... 35,619 16,312
--------- ---------
Total current assets............................................................. 468,587 511,764
--------- ---------
Deferred charges:
Regulatory assets (Note 1)........................................................ 321,797 335,893
Unamortized debt expense.......................................................... 10,460 11,073
Other............................................................................. 48,457 39,498
--------- ---------
Total deferred charges........................................................... 380,714 386,464
--------- ---------
$4,354,295 $4,207,832
========== ==========
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
34
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
DECEMBER 31, 1995 AND 1994
CAPITAL AND LIABILITIES
1995 1994
---------- ----------
Common stock (Note 5).................................................... $ 997,106 $ 959,268
Retained earnings........................................................ 346,539 308,214
---------- ----------
Total common equity.................................................... 1,343,645 1,267,482
Preferred stock (Note 5):
Not subject to mandatory redemption..................................... 140,008 140,008
Subject to mandatory redemption at par.................................. 41,289 42,665
Long-term debt (Note 6).................................................. 1,195,553 1,155,427
---------- ----------
2,720,495 2,605,582
---------- ----------
Noncurrent liabilities:
Defueling and decommissioning liability (Note 2)........................ 23,115 40,605
Employees' postretirement benefits other than pensions (Note 11)........ 51,704 42,106
Employees' postemployment benefits (Note 11)............................ 23,500 20,975
---------- ----------
Total noncurrent liabilities.......................................... 98,319 103,686
---------- ----------
Current liabilities:
Notes payable and commercial paper (Note 7)............................. 288,050 324,800
Long-term debt due within one year...................................... 82,836 25,153
Preferred stock subject to mandatory redemption within one year (Note 5) 2,576 2,576
Accounts payable........................................................ 156,109 177,031
Dividends payable....................................................... 35,284 34,078
Recovered purchased gas and electric energy costs - net (Note 1)........ 9,508 -
Customers' deposits..................................................... 17,462 17,099
Accrued taxes........................................................... 55,393 54,148
Accrued interest........................................................ 32,071 32,265
Current portion of defueling and decommissioning liability (Note 2)..... 24,055 36,365
Other................................................................... 78,451 62,640
---------- ----------
Total current liabilities............................................. 781,795 766,155
---------- ----------
Deferred credits:
Customers' advances for construction.................................... 99,519 96,442
Unamortized investment tax credits...................................... 113,184 118,532
Accumulated deferred income taxes (Note 13)............................. 508,143 485,668
Other................................................................... 32,840 31,767
---------- ----------
Total deferred credits................................................ 753,686 732,409
Commitments and contingencies (Notes 2 and 9)............................
---------- ----------
$4,354,295 $4,207,832
========= =========
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
35
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(THOUSANDS OF DOLLARS EXCEPT PER SHARE DATA)
YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
1995 1994 1993
---------- ---------- ----------
Operating revenues:
Electric.............................................. $1,449,096 $1,399,836 $1,337,053
Gas................................................... 624,585 624,922 628,324
Other................................................. 36,920 32,626 33,308
---------- ---------- ----------
2,110,601 2,057,384 1,998,685
Operating expenses:
Fuel used in generation............................... 181,995 198,118 194,918
Purchased power....................................... 481,958 437,087 396,953
Gas purchased for resale.............................. 392,680 397,877 384,393
Other operating expenses.............................. 350,093 369,094 376,686
Maintenance........................................... 64,069 67,097 76,229
Defueling and decommissioning (Note 2)................ - 43,376 -
Depreciation and amortization......................... 141,380 139,035 140,804
Taxes (other than income taxes)....................... 81,319 86,408 86,775
Income taxes (Note 13)................................ 95,357 48,500 60,994
---------- ---------- ----------
1,788,851 1,786,592 1,717,752
---------- ---------- ----------
Operating income....................................... 321,750 270,792 280,933
Other income and deductions:
Allowance for equity funds used during construction... 3,782 3,140 8,119
Gain on sale of WestGas Gathering, Inc. (Note 4)...... - 34,485 -
Miscellaneous income and deductions - net............. (2,770) (6,014) (1,355)
---------- ---------- ----------
1,012 31,611 6,764
Interest charges:
Interest on long-term debt............................ 85,832 89,005 98,089
Amortization of debt discount and expense less premium 3,278 3,126 2,018
Other interest........................................ 58,109 44,021 34,778
Allowance for borrowed funds used during construction. (3,313) (4,018) (4,548)
---------- ---------- ----------
143,906 132,134 130,337
---------- ---------- ----------
Net income.............................................. 178,856 170,269 157,360
Dividend requirements on preferred stock................ 11,963 12,014 12,031
---------- ---------- ----------
Earnings available for common stock..................... $ 166,893 $ 158,255 $ 145,329
========== ========== ==========
Shares of common stock outstanding (thousands):
Year-end............................................... 63,358 62,155 60,457
========== ========== ==========
Weighted average....................................... 62,932 61,547 59,695
========== ========== ==========
Earnings per weighted average share of common stock
outstanding.......................................... $ 2.65 $ 2.57 $ 2.43
========== ========== ==========
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
36
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(THOUSANDS OF DOLLARS, EXCEPT SHARE INFORMATION)
YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
COMMON STOCK, $5 PREMIUM
PAR VALUE ON
-------------------- COMMON RETAINED
SHARES AMOUNT STOCK EARNINGS TOTAL
---------- -------- -------- ---------- -----------
Balance at January 1, 1993.... 58,476,805 $292,384 $560,938 $ 247,725 $1,101,047
Net income.................... - - - 157,360 157,360
Dividends declared
Common stock, $2.00 per
share...................... - - - (119,722) (119,722)
Preferred stock, $100
par value.................. - - - (9,088) (9,088)
Preferred stock, $25 par
value...................... - - - (2,940) (2,940)
Issuance of common stock
Employees' Savings Plan..... 329,220 1,646 7,716 - 9,362
Dividend Reinvestment Plan.. 1,651,350 8,257 39,907 - 48,164
---------- -------- -------- ---------- -----------
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
========== ======== ======== ========== ===========
Authorized shares of common stock were 160 million at December 31, 1995 and 1994
and 140 million at December 31, 1993.
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 CASH FLOWS
(THOUSANDS OF DOLLARS)
YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
1995 1994 1993
---------- ---------- ----------
Operating activities:
Net income......................................................... $ 178,856 $ 170,269 $ 157,360
Adjustments to reconcile net income to net
cash provided by operating activities (Note 1):
Depreciation and amortization.................................... 145,370 142,843 143,940
Defueling and decommissioning expenses........................... - 43,376 -
Gain on sale of WestGas Gathering, Inc........................... - (34,485) -
Amortization of investment tax credits........................... (5,348) (5,799) (4,917)
Deferred income taxes............................................ 39,170 34,234 33,435
Allowance for equity funds used during construction.............. (3,782) (3,140) (8,119)
Change in accounts receivable.................................... 38,734 (16,281) (3,813)
Change in inventories............................................ 4,246 10,007 (25,378)
Change in other current assets................................... 7,618 (1,695) (14,619)
Change in accounts payable....................................... (20,922) (35,364) 31,909
Change in other current liabilities.............................. 24,230 (39,730) (5,439)
Change in deferred amounts....................................... (20,385) (33,920) (17,483)
Change in noncurrent liabilities................................. (5,367) 15,321 (14,759)
Other............................................................ 3,279 92 7,762
--------- --------- ---------
Net cash provided by operating activities....................... 385,699 245,728 279,879
Investing activities:
Construction expenditures.......................................... (285,516) (317,138) (293,515)
Allowance for equity funds used during construction................ 3,782 3,140 8,119
Proceeds from sale of WestGas Gathering, Inc....................... - 87,000 -
Proceeds from disposition of property, plant and equipment......... 2,470 49,438 43,120
Purchase of other investments...................................... (10,249) (955) (5,660)
Sale of other investments.......................................... 4,898 1,148 8,678
--------- --------- ---------
Net cash used in investing activities........................... (284,615) (177,367) (239,258)
Financing activities:
Proceeds from sale of common stock (Note 1)........................ 28,030 38,086 47,894
Proceeds from sale of long-term notes and bonds (Note 1)........... 101,860 250,068 257,913
Redemption of long-term notes and bonds............................ (44,713) (281,835) (274,829)
Short-term borrowings - net........................................ (36,750) 47,925 26,249
Redemption of preferred stock...................................... (1,376) (213) (200)
Dividends on common stock.......................................... (127,352) (122,531) (118,732)
Dividends on preferred stock....................................... (11,973) (12,016) (12,033)
--------- --------- ---------
Net cash used in financing activities........................... (92,274) (80,516) (73,738)
--------- --------- ---------
Net increase (decrease) in cash and temporary cash investments.. 8,810 (12,155) (33,117)
Cash and temporary cash investments at beginning of year........ 5,883 18,038 51,155
--------- --------- ---------
Cash and temporary cash investments at end of year.............. $ 14,693 $ 5,883 $ 18,038
========= ========= =========
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
38
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995
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 primarily in the Denver
metropolitan area. 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.
Approximately 90% of the Company's electric and gas revenues are subject to CPUC
jurisdiction. Cheyenne and WGI are subject to the jurisdiction of the WPSC and
the FERC, respectively.
Regulatory assets and liabilities
The Company and its regulated subsidiaries prepare their financial statements
in accordance with the provisions of SFAS 71. In general, SFAS 71 recognizes
that accounting for rate regulated enterprises should reflect the relationship
of costs and revenues introduced by rate regulation. As a result, a regulated
utility may defer recognition of a cost (a regulatory asset) or recognize an
obligation (a regulatory liability) if it is probable that, through the
ratemaking process, there will be a corresponding increase or decrease in
revenues.
In response to the increasingly competitive environment for utilities, the
regulatory climate also is changing. The Company continues to participate in
regulatory proceedings which could change or impact current regulation. However,
the Company believes it will continue to be subject to rate regulation that will
provide for the recovery of all of its deferred costs. Although the Company
does not currently anticipate such an event, to the extent the Company concludes
in the future that collection of such revenues (or payment of liabilities) is no
longer probable, through changes in regulation and/or the Company's competitive
position, the Company may be required to recognize as expense, at a minimum, all
deferred costs currently recognized as regulatory assets on the consolidated
balance sheet.
In March 1995, the Financial Accounting Standards Board issued 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 Company adopted this standard on January 1,
1996, the effective date of the new statement, and such adoption did not have a
material impact on the Company's results of operations, financial position or
cash flow.
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
The following regulatory assets are reflected in the Company's consolidated
balance sheets:
RECOVERY
1995 1994 THROUGH
-------- -------- ------------
(THOUSANDS OF DOLLARS)
Nuclear decommissioning costs (Note 2)........ $ 97,801 $107,374 2005
Income taxes (Note 13)........................ 110,617 125,832 2006
Employees' postretirement benefits
other than pensions (Note 11)................ 47,600 37,573 2013
Early retirement costs (Note 11).............. 24,366 33,124 1998
Employees' postemployment benefits (Note 11).. 23,500 20,975 Undetermined
Demand-side management costs.................. 30,188 20,831 2002
Unamortized debt reacquisition costs.......... 21,940 22,360 2024
Other......................................... 6,032 7,809 1999
-------- --------
Total....................................... 362,044 375,878
Classified as current......................... 40,247 39,985
-------- --------
Classified as noncurrent...................... $321,797 $335,893
======== ========
Certain costs associated with the Company's DSM programs are deferred and
recovered in rates over five to seven year periods through the DSMCA, which was
implemented July 1, 1993. Non-labor incremental expenses, carrying costs
associated with deferred DSM costs and incentives associated with approved DSM
programs are recovered on an annual basis.
Costs incurred to reacquire debt prior to scheduled maturity dates are
deferred and amortized over the life of the debt issued to finance the
reacquisition or as approved by the regulator.
Recovered/Recoverable purchased gas and electric energy costs - net
The Company'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. These cost adjustment tariffs are revised
periodically, as prescribed by the appropriate regulatory agencies, for any
difference between the total amount collected under the clauses and the
recoverable costs incurred. The cumulative effects are recognized as a current
asset or liability until adjusted by refunds or collections through future
billings to customers.
Other
Property, plant and equipment includes approximately $18.4 million and
$25.4 million, respectively, for costs associated with the engineering design of
the future Pawnee 2 generating station and certain water rights located in
southeastern Colorado, also obtained for a future generating station. The
Company is earning a return on these investments based on the Company's weighted
average cost of debt and preferred stock in accordance with a CPUC rate order.
Non-utility subsidiaries
The Company's net investment in its non-utility subsidiaries approximated
2.5% of common equity at December 31, 1995. 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.
40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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.
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:
1995 1994 1993
-------- -------- --------
(THOUSANDS OF DOLLARS)
Income taxes... $ 58,662 $ 41,763 $ 49,196
Interest....... $140,823 $126,250 $129,844
Non-cash transactions:
Shares of common stock (310,546 in 1995, 334,223 in 1994 and 329,220 in
1993), valued at the market price on date of issuance (approximately $9.7
million in 1995, $10.1 million in 1994 and $9.4 million in 1993), 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 (3,390 in 1995 and 7,892 in 1994), valued at the
market price on the date of issuance ($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. These stock issuances were non-cash
transactions and are not reflected in the consolidated statement 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.
Changes in certain balance sheet accounts, resulting from the sale of WGG
in 1994, have been recognized as non-cash activity.
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
PROPERTY AND DEPRECIATION
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 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 2.6% for the years
ended December 31, 1995 and 1994 and 3.0% for the year ended December 31, 1993.
The average rate for 1995 and 1994 reflects the effects of using a longer
estimated depreciable life for the Company's electric steam production
facilities based on the Company's most recent depreciation study, as approved by
the CPUC. For income tax purposes, the Company and its subsidiaries use
accelerated depreciation and other elections provided by the tax laws.
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 1995, 1994 and 1993 were 7.97%, 6.81%-8.75% and
10.21%, respectively.
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).
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, 1995 and 1994 exceeded the LIFO cost by approximately
$5.3 million and $12.5 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, on the
consolidated balance sheets:
1995 1994
---------- ----------
(THOUSANDS OF DOLLARS)
Cash surrender value of contracts............ $311,097 $267,445
Borrowings against contracts................. 308,833 265,568
-------- --------
Net investment in life insurance contracts.. $ 2,264 $ 1,877
======== ========
42
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 of the reactor to the ISFSI,
which has been completed, as discussed below in the section entitled
"Defueling". The Company is currently decommissioning the facility as described
below in the section entitled "Decommissioning".
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 in 1996, Phase 1B - 102 Mw in 1999 and Phase 2 - 239 Mw in 2000. The
repowering of Phase 1A is substantially complete and it is expected to be on-
line in the second quarter of 1996. The phased repowering allows the Company
flexibility in timing the addition of this generation supply to meet future load
growth.
DEFUELING
The Company has entered into two separate agreements with the DOE for (a)
the temporary storage of segments 1-8 at a DOE facility located in the State of
Idaho (such contract includes a provision to store additional spent fuel
segments if storage space exists) and (b) the disposal of segment 9 at a Federal
repository. Resolution of spent fuel disposal issues has been substantially
delayed due to failure by the DOE to meet legal requirements relating to
storage. It is currently estimated that the Federal repository will not be open
until 2010. While the plant was operating and as part of routine refueling
procedures, three spent fuel segments (segments 1 - 3) were transported to the
Idaho facility. Currently, six segments of Fort St. Vrain's spent nuclear fuel
(segments 4-9) are stored in the ISFSI located at the plant site.
During the last several months, the Company and the DOE have had various
discussions regarding the issues related to the disposal of Fort St. Vrain's
spent nuclear fuel. During January and February 1996, the discussions focused on
the drafting and execution of a contract to resolve these issues and, on
February 9, 1996, the parties executed such contract. In summary, the primary
provisions of the agreement include the following.
- On February 9, 1996, the DOE assumed title to fuel segments 4 - 9, which,
as noted above, currently are stored in the facility.
- The DOE agreed to pay the Company $16 million for settlement of claims
associated with the ISFSI. Title to the ISFSI will pass to the DOE at such
time as all applicable legal requirements for title transfer (including NRC
approval) are met. The DOE deposited $14 million of the $16 million into an
interest bearing escrow account. The initial $2 million was paid to the
Company on February 13, 1996.
- Until the time title to the ISFSI transfers to the DOE, the Company will
be entitled to payments of $2 million per year (escalated annually based on
the Consumer Price Index) plus ISFSI operating and maintenance costs
including licensing fees and other regulatory costs, facility support and
reasonable insurance costs. On the date title transfers, the Company will
be entitled to the remaining funds (principal and interest) in the escrow
account and the agreement will be terminated.
- The term of the agreement will be for a period of up to 15 years, with
one 5 year option to extend. If such option to extend is exercised, the
annual payments increase to $4 million (unescalated). The DOE has the
option to terminate the agreement after the first 8 years.
- Upon termination or expiration of the agreement, the DOE will be
responsible for the defueling and decommissioning of the ISFSI with the
Company being responsible for costs only up to the amount contained in
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
its existing NRC required escrow account. Such amount at December 31, 1995
was approximately $1.7 million.
- The Company provided to the DOE a full and complete release of claims
against the DOE arising out of prior contracts discussed above related to
spent fuel disputes.
In accordance with the 1991 CPUC approval to recover the early
dismantlement/decommissioning costs described below, 50% of any cash amounts
received from the DOE as part of a settlement, net of costs incurred by the
Company, including legal fees, the amount of which has not yet been determined,
is to be refunded or credited to customers.
During 1994, as a result of increased uncertainties related to the ultimate
disposal of Fort St. Vrain's spent nuclear fuel, the Company had recognized an
additional $15 million defueling reserve, determined on a present value basis.
This amount represented the additional estimated cost of operating and
maintaining the ISFSI until 2020 (if required), the earliest date the Company
believed a Federal repository will be available to accept the Company's spent
nuclear fuel. These estimated expenditures were escalated for inflation using
an average rate of 3.5% and discounted to present value at a rate of 8%.
DECOMMISSIONING
The Company has been pursuing the early dismantlement/decommissioning of
Fort St. Vrain following the 1991 CPUC approval of the recovery from customers
of approximately $124.4 million (plus a 9% carrying cost) for such activities,
as well as the 1992 NRC approval of the Company's early
dismantlement/decommissioning plan. The decommissioning amount being recovered
from customers, which began July 1, 1993 and extends over a twelve-year period,
represented the inflation-adjusted estimated remaining cost of the early
dismantlement/decommissioning activities not previously recognized as expense at
the time of CPUC approval. At December 31, 1995, approximately $97.8 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.
The Company has contracted with Westinghouse Electric Corporation and MK-
Ferguson, a division of Morrison Knudsen Corporation, for the early
dismantlement/decommissioning of Fort St. Vrain. At February 9, 1996, the
physical decommissioning work activities had been substantially completed with
only NRC site release remaining to be addressed. It is expected that such NRC
site release activities will be completed in 1996 resulting in the Company's
Part 50 license being terminated.
The decommissioning contract stipulates a fixed price, based on a defined
work scope; however, such price has been and could be further modified due to
changes in work scope related to the final NRC site release described below.
Since the initiation of decommissioning activities, the decommissioning
contractors have notified the Company of several scope changes which were
primarily related to the identification of higher radiation levels in the
reactor core than originally anticipated and regulatory changes related to site
release as discussed below.
On October 25, 1994, the Company and the decommissioning contractors
reached an agreement resolving all issues and claims related to identified and
certain possible future changes in scope of work covered by the contract, with
certain exceptions. In order to complete all decommissioning activities related
to such scope changes, the Company recognized an additional $15 million in
decommissioning expense during 1994.
The significant exceptions to the agreement, which were also areas for
potential changes in the defined work scope under the decommissioning contract,
include changes in law, radioactive material created by activation in the lower
portion of the reactor, as well as changes in the methodology requirements and
guidance established by the NRC for final site release. On January 26, 1995,
the Company received NRC approval of its Final Survey Plan for Site Release
reducing the future uncertainty related to this issue.
44
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
During the third quarter of 1995, the Company and the decommissioning
contractors reached an agreement resolving all issues related to the
identification of radioactive material created by activation in the lower
portion of the reactor. As part of this agreement, the Company paid the
contractors an additional $8 million. While the Company agreed to this change
in work scope, a revision in the defueling and decommissioning liability was not
required as the then cost estimate, prior to such change, included a contingency
provision. Such provision was sufficient to cover the cost of the additional
scope change.
At December 31, 1995, approximately $314.6 million had been spent for
defueling and decommissioning activities with a remaining $47.2 million
defueling and decommissioning liability reflected on the consolidated balance
sheet. While the Company is currently evaluating the financial impact of the
recent DOE settlement, including amounts expected to be refunded to customers as
described above as well as the final evaluation of the remaining decommissioning
costs, it is expected that such settlement will have a positive impact on the
Company's first quarter 1996 pre-tax operating income ranging from approximately
$15 million to $20 million.
FUNDING
Under NRC regulations, the Company is required to make filings with, and
obtain the approval of, the NRC regarding certain aspects of the Company's
decommissioning proposals, including funding. On January 27, 1992, the NRC
accepted the Company's funding aspects of the decommissioning plan. The Company
has also obtained an unsecured irrevocable letter of credit totaling $125
million that meets the NCR's stipulated funding guidelines including those
proposed on August 21, 1991 that address decommissioning funding requirements
for nuclear power reactors that have been prematurely shut down. In accordance
with the NRC funding guidelines, the Company is allowed to reduce the balance of
the letter of credit based upon milestone payments made under the fixed-price
decommissioning contract. As a result of such payments, at December 31, 1995,
the letter of credit had been reduced to $43 million.
NUCLEAR INSURANCE
The Price Anderson Act, as amended, limits the public liability of a
licensee for a single nuclear incident at its nuclear power plant to the amount
of financial protection available through liability insurance and deferred
premium assessment charges, currently approximately $8.9 billion, which includes
a 5% surcharge. The Act requires licensees to participate in an assessable
excess liability program through an indemnity program with the NRC. Under the
terms of this indemnity program, the Company could be liable for retrospective
assessments of approximately $79 million per nuclear incident at any nuclear
power plant. Also, it is provided that not more than $10 million could be
payable per incident in any one year. The Company's primary financial
protection for this exposure was provided in the amount available ($200 million)
by private insurance. In consideration of the shutdown and defueled status of
Fort St. Vrain, the Company requested exemption from the indemnification
obligations under the Act. The NRC granted the Company's request for exemption
from participation in the indemnity program for nuclear incidents occurring
after February 17, 1994 and reduced the amount of primary liability insurance
required to $100 million.
In addition to the Company's liability insurance, Federal regulations
require the Company to maintain $1.06 billion in nuclear property insurance.
Effective February 1, 1991, the NRC granted the Company's exemption request to
reduce the nuclear property insurance coverage from $1.06 billion to a minimum
of $169 million. This lower limit would cover stabilization and decontamination
expenses resulting from a worst case accident. However, on June 7, 1995, the
NRC granted the Company an exemption from the requirement to maintain nuclear
property damage insurance following an environmental assessment and finding of
no significant impact. Accordingly, the Company has reduced such insurance
coverage to $10 million, which is related only to the ISFSI, the obligation for
which will also transfer when title to the ISFSI transfers to the DOE under the
provisions of the February 9, 1996 agreement discussed above.
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
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
Company and SPS in a "merger of equals" transaction. On January 30, 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.
On January 31, 1996, the shareholders of the Company and SPS approved the
Merger Agreement. Additionally, the Merger is subject to customary closing
conditions, including the receipt of all necessary governmental approvals and
the making of all necessary governmental filings, including approvals and
findings of state utility regulators in Colorado, Texas, New Mexico, Wyoming and
Kansas as well as the approval of the FERC, the NRC, the SEC, the Federal Trade
Commission and the U. S. Department of Justice. Applications to the state
regulatory commissions and the FERC have been completed and, on November 28,
1995, the Kansas Corporation Commission issued an order granting SPS's request
for authority for the issuance of common stock to NCE pursuant to the Merger
Agreement. It is expected that the Merger will be completed in the third
quarter 1996; however, the timing of the effective date of the merger is
primarily dependent upon the regulatory process (see Note 9).
Under the terms of the Merger Agreement, each outstanding share of the
Company's Common Stock will be canceled and converted into the right to receive
one share of NCE Common Stock, and each outstanding share of SPS Common Stock
will be canceled and converted into the right to receive 0.95 of one share of
NCE Common Stock. As of December 31, 1995, the Company had 63.4 million common
shares outstanding and SPS had 40.9 million common shares outstanding. Based on
such capitalization, the Merger would result in the common shareholders of the
Company owning 62% of the common equity of NCE and the common shareholders of
SPS owning 38% of the common equity of NCE. The Merger Agreement and the Merger
will not affect the debt, including mortgage bonds, and shares of preferred
stock of the Company and SPS which are outstanding at the time of the Merger.
It is anticipated that NCE will adopt the SPS dividend payment level, adjusted
for the exchange ratio, resulting in a pro forma dividend of $2.32 per share on
an annual basis, following completion of the Merger. The actual dividend level
will be dependent upon NCE's results of operations, financial position, cash
flows and other factors, and will be evaluated by NCE's Board of Directors.
Based on 1995 results, NCE would have proforma combined annual revenues of
approximately $3 billion and total assets of over $6 billion. The Company and
SPS project net synergy savings of approximately $770 million, net of costs to
achieve the merger, in the first 10 years after the transaction is completed.
The Company and SPS estimate that approximately 50 percent of the total
projected savings would result from labor cost savings through the elimination
of duplicate functions. It is expected that employee reductions would be
approximately 8% of the combined work force, or approximately 550 to 600
positions. The remainder would fall under non-labor savings, which would include
approximately 20 percent through deferral of additional capacity and 20 percent
from efficiencies in fuel procurement. The proposed allocation of the net
savings between customers and shareholders was submitted to regulatory agencies
in connection with the November 9, 1995 merger rate filings as discussed in Note
9. The analyses employed to develop estimates of potential savings as a result
of the Merger were necessarily based upon various assumptions which involve
judgments with respect to future national and regional economic and competitive
conditions, inflation rates, regulatory treatment, weather conditions, financial
market conditions, interest rates and future business decisions and conditions,
all of which are difficult to predict and many of which are beyond the control
of the Company and SPS. Accordingly, although the Company and SPS believe that
such assumptions are reasonable for developing estimates of potential savings,
there can be no assurance that these assumptions will approximate actual
experience or the extent to which such savings will be realized.
A transition management team, consisting of executives from each company, has
been formed and is working toward the common goal of creating one company with
integrated operations to achieve a more efficient and economic utilization of
facilities and resources. It is managements' intention that the consolidated
company begin realizing certain savings upon the consummation of the Merger and,
accordingly, costs associated with the Merger and the transition planning and
implementation are expected to negatively impact earnings during 1996 and 1997.
During 1995, the Company recognized approximately $4 million of costs associated
with the Merger. The Merger is expected to qualify as a tax-free reorganization
and as a pooling of interests for accounting purposes.
46
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
The Company recognizes that the divestiture of its existing gas business or
certain non-utility ventures is a possibility under the new registered holding
company structure, but is seeking approval from the SEC to maintain these
businesses. If divestiture is ultimately required, the SEC has historically
allowed companies sufficient time to accomplish divestitures in a manner that
protects shareholder value. Additionally, in the event that divestiture of the
gas business is required, the Company will pursue an alternative corporate
organizational structure that will permit retention of the gas business.
4. DIVESTITURE OF NONUTILITY ASSETS
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.
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 agreement with the OCC. The refund was completed in late 1995.
FUEL RESOURCES DEVELOPMENT CO.
In June 1993, the Company's Board of Directors approved pursuing the
divestiture of Fuelco, a wholly-owned subsidiary primarily involved in the
exploration and production of oil and natural gas. In the fourth quarter of
1993, the Company recorded the estimated effects of the disposition of all
properties, including all costs expected to be incurred through the close of
operations. The effects of these transactions had no material impact on the
Company. The Company has continued to operate one group of assets, the San Juan
Coal Bed Methane properties, which has a book value of approximately $19.3
million at December 31, 1995. The Company believes that the remaining
investment in these assets is realizable and is pursuing the divestiture of
these assets, which is expected to be completed in 1996.
5. CAPITAL STOCK
COMMON STOCK
The Company has filed a registration statement with the SEC relating to the
registration of 1,000,000 common stock shares, $5 par value, and 1,000,000
common share purchase rights. These shares and rights are associated with the
Company's Omnibus Incentive Plan discussed in Note 11.
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.
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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.
PREFERRED STOCK
1995 1994
---------------------- ----------------------
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.............................. 222,652 22,265 236,412 23,641
--------- -------- --------- --------
438,652 43,865 452,412 45,241
Less: Preferred stock subject to mandatory
redemption within one year................ (25,760) (2,576) (25,760) (2,576)
--------- ------- --------- -------
Total.................................... 412,892 $41,289 426,652 $42,665
========= ======= ========= =======
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.
48
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
CUMULATIVE PREFERRED STOCK, SUBJECT TO MANDATORY REDEMPTION:
7.50% series: $102 per share on or prior to August 31, 1996, 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: $102.25 per share on or prior
to July 31, 1996, and reducing each year thereafter by $0.25 per share until
July 31, 2004, after which the redemption price is $100 per share.
In 1996 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 subject to mandatory
redemption within one year in the December 31, 1995 consolidated balance sheet.
In 1995, 1994 and 1993, the Company repurchased 13,760 shares, 2,133 shares and
2,000 shares, respectively, 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, 1995.
6. LONG-TERM DEBT
1995 1994
----------- -----------
(THOUSANDS OF DOLLARS)
Public Service Company of Colorado:
First Collateral Trust Bonds:
6% - 6 3/8% series, due January 1, 2001 - November 1, 2005...................... $237,167 $237,167
7 1/4% series, due January 1, 2024.............................................. 110,000 110,000
First Mortgage Bonds:
5 3/8% - 6 3/4% series, due May 1, 1996 - July 1, 1998......................... 95,000 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........................... 23,000 23,500
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 2, 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:
6.35% - 9.25%, due January 11, 1995 - October 30, 2002........................ 151,500 149,500
Unsecured promissory notes:
11.60% - 12.875%, retired May 1, 1995........................................... - 15,000
Unamortized premium............................................................... 24 43
Unamortized discount.............................................................. (4,568) (5,105)
Capital lease obligations, 6.68-14.65%, due in installments through May 31, 2025.. 53,567 17,093
--------- ---------
1,147,440 1,123,948
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.:
Secured Medium-Term Notes, Series A:
5.75% - 6.03%, due November 24, 1997 - December 1, 1998......................... 80,000 -
1480 Welton, Inc.:
12.50% secured promissory note, due in installments through March 1, 1998......... - 5,480
13.25% secured promissory note, due in installments through October 1, 2016....... 31,814 32,083
Fuel Resources Development Co.:
Capital lease obligations, 7.09%, due in installments through March 1, 1995....... - 13
Natural Fuels Corporation:
Capital lease obligations, 4.21-11.11% , due in installments through
October 1, 2000.................................................................. 135 56
--------- ---------
1,278,389 1,180,580
Less: maturities due within one year............................................... 82,836 25,153
--------- ---------
$1,195,553 $1,155,427
========== =========
49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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 and First Collateral Trust 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.
The aggregate annual maturities and sinking fund requirements during the
five years subsequent to December 31, 1995 are (in thousands of dollars):
YEAR MATURITIES SINKING FUND REQUIREMENTS TOTAL
1996 $ 82,836 $1,160 $ 83,996
1997 135,064 810 135,874
1998 77,270 560 77,830
1999 29,231 560 29,791
2000 1,659 560 2,219
The Company and Cheyenne expect to satisfy substantially all of its
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, 1995 and 1994 is as follows:
1995 1994
---------- ----------
(THOUSANDS OF DOLLARS)
Notes payable to banks (weighted average interest rates of 6.12% at
December 31, 1995 and 6.34% at December 31, 1994)................... $ 45,800 $107,850
Commercial paper (weighted average interest rates of 6.21% at
December 31, 1995 and 6.22% at December 31, 1994)................... 242,250 216,950
-------- --------
$288,050 $324,800
======== ========
Maximum amount outstanding at any month-end during the period........ $329,475 $333,865
======== ========
Weighted average amount (based on the daily outstanding balance)
outstanding for the period (weighted average interest rates of
6.18% for the year ended December 31, 1995 and 4.58% for the year
ended December 31, 1994)............................................ $292,226 $273,015
======== ========
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.
On November 17, 1995, the Company, PSCCC, and certain subsidiaries entered
into a new 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. Under the facility, which was
amended January 31, 1996, 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.
50
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
Individual arrangements for uncommitted bank lines of credit totaled $100
million at December 31, 1995, 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.
9. COMMITMENTS AND CONTINGENCIES
REGULATORY MATTERS
1995 Merger Rate Filings
In connection with the merger with SPS, on November 9, 1995 the Company
filed comprehensive proposals with the CPUC, the FERC and the WPSC to obtain
approval from such regulatory agencies. The CPUC proposal included, among other
things, implementing an electric rate moratorium for five years, allowing for
the sharing of earnings in excess of 12.5% return on equity (determined by
utilizing the combined operations of the electric, gas and steam departments) on
a 50/50 basis between shareholders and customers, retaining the Company's ECA,
GCA, and QFCCA mechanisms, implementing quality of service measures and
recovering costs incurred in connection with the merger (see Note 3). The
quality of service measures included in the CPUC proposal relate to the
following four areas: 1) customer complaints, 2) phone response time to customer
inquiries, 3) response time to customer-initiated gas odor complaints, and 4)
electric service availability. In the event that the Company does not meet the
proposed quality of service measures, earnings may be reduced by up to $4
million on an annual basis. Additionally, the proposed sharing of earnings in
excess of 12.5% return on equity would supersede the QFCCA earnings test
discussed below. The CPUC has scheduled hearings on this matter for July 1996.
The FERC and WPSC have not yet scheduled any proceedings related to the proposed
merger. However, during January 1996, the FERC issued a Notice of Inquiry
concerning its merger policy under the Federal Power Act to determine whether
the criteria and policies for evaluating mergers needs to be revised.
Electric and Gas Cost Adjustment Mechanisms
The Company's ECA was revised and a new QFCCA was implemented on December
1, 1993, along with the base rate changes resulting from the 1993 rate case.
Under the revised ECA, fuel used for generation and purchased energy costs from
utilities, QFs and IPPFs (excluding all purchased capacity costs) to serve
retail customers, are recoverable. Purchased capacity costs are recovered as a
component of base rates, except as described below. The ECA rate is revised
annually on October 1. Recovered energy costs are compared with actual costs on
a monthly basis and differences, including interest, are deferred. Under the
QFCCA, all purchased capacity costs from new QF projects, not reflected in base
rates, are recoverable similar to the ECA.
With respect to the QFCCA, the CPUC issued a final decision in January 1996
which required the following: 1) an earnings test be implemented with a 50/50
sharing between the ratepayers and shareholders of earnings in excess of 11%,
the Company's authorized rate of return on regulated common equity; 2) the
calculation will be based on the Company's electric department earnings only;
and 3) implementation will be on a prospective basis effective October 1, 1996,
utilizing a test period for the prior twelve months ended June 30, 1996, unless
superseded by a CPUC decision prior to the effective date. The Company intends
to address this issue in connection with the merger rate filing discussed above.
During 1994, the CPUC initiated proceedings for reviewing the justness and
reasonableness of GCA and ECA mechanisms used by gas and electric utilities
within its jurisdiction. On April 14, 1995, the CPUC issued a final order which
retained the GCA with no modifications and closed its investigation of the GCA
mechanism. With respect to the ECA, in compliance with an order issued by the
CPUC in March 1995, the Company completed a filing on September 1, 1995
requesting the CPUC to open a docket to investigate its ECA. The CPUC opened a
docket to review whether the ECA should be maintained in its present form,
altered or eliminated. On January 8, 1996, the CPUC combined this docket with
the merger docket discussed above.
51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(COINTINUED)
The CPUC approved the recovery of certain energy efficiency credits from
retail jurisdiction customers through the DSMCA in June 1994. In December 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. Accordingly, effective July 1, 1995, the Company began
collection of the December 31, 1994 balance of unbilled revenue related to these
credits. To date, the Company has recognized approximately $9.6 million of
revenue related to these credits ($6.5 million unbilled). The Company believes
the CPUC's decision will be upheld, however, if the OCC is successful in its
appeal, the Company could be required to reverse these unbilled revenues and
refund to customers the amounts previously collected. It is expected that this
matter will be decided in early 1996 by the Denver District Court based on the
written pleadings submitted in October 1995.
Incentive Regulation and Demand Side Management
The CPUC's investigation into alternative annual revenue reconciliation
mechanisms and incentive mechanisms related to the Company's DSM programs was
completed in 1995. 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.
Rate Cases
In November 1993, the CPUC issued its final written decision regarding the
Company's 1993 rate case, lowering the Company's annual base rate revenue
requirement by approximately $5.2 million (a $13.1 million electric revenue
decrease partially offset by a $7.1 million gas revenue increase and a $0.8
million steam revenue increase) with new rates effective December 1, 1993.
The Phase II proceedings of the 1993 rate case addressed cost allocation
issues and specific rate changes for the various customer classes based on the
results of the Phase I decision. The CPUC approved a settlement agreement
related to gas rates and the new gas rates were implemented effective October 1,
1995. A final decision on rehearing, reargument and reconsideration for the
Phase II proceedings related to electric rates was issued in February 1996 with
new rates expected to be effective in early 1996.
The Company filed a rate case with the FERC on December 29, 1995,
requesting a slight overall rate increase (less than 1%) from its wholesale
electric customers. This filing, among other things, requested approval for
recovery of OPEB costs under SFAS 106, postemployment benefit costs under SFAS
112 and new depreciation rates based on the Company's most recent depreciation
study.
Federal Energy Regulatory Commission
On March 29, 1995, the FERC issued a NOPR on Open Access Non-Discriminatory
Transmission Services by Public Utilities and Transmitting Utilities and a
supplemental NOPR on Recovery of Stranded Costs.
The rules proposed in the NOPR are intended to facilitate competition among
electric generators for sales to the bulk power supply market. If adopted, the
NOPR on open access transmission would require public utilities under the
Federal Power Act to provide open access to their transmission systems and would
establish guidelines for their doing so. A final rule would define the terms
under which independent power producers, neighboring utilities, and others could
gain access to a utility's transmission grid to deliver power to wholesale
customers, such as municipal distribution systems, rural electric cooperatives,
or other utilities. Under the NOPR, each public utility would also be required
to establish separate rates for its transmission and generation services for new
wholesale service, and to place transmission services, including ancillary
services, under the same tariffs that would be applicable to third-party users
for all of its new wholesale sales and purchases of energy.
52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
The supplemental NOPR on stranded costs provides a basis for recovery by
regulated public utilities of legitimate and verifiable stranded costs
associated with existing wholesale requirements customers and retail customers
who become unbundled wholesale transmission customers of the utility. The FERC
would provide public utilities a mechanism for recovery of stranded costs that
result from municipalization, former retail customers becoming wholesale
customers, or the loss of a wholesale customer. The FERC will consider allowing
recovery of stranded investment costs associated with retail wheeling only if a
state regulatory commission lacks the authority to consider that issue.
On June 26, 1995, the Company filed transmission tariffs with the FERC that
are intended to meet the comparability of service requirements as set out in the
NOPR ("PSCo Tariffs"). Concurrently with the comparability filing, e prime, a
non-regulated energy services subsidiary of the Company, filed a power marketer
application with the FERC. Subsequently on August 18, 1995, Cheyenne filed
transmission tariffs with the FERC that are intended to meet the NOPR
comparability of service requirements ("Cheyenne Tariffs"). In an order issued
on October 13, 1995, the FERC accepted the PSCo Tariffs and the Cheyenne
Tariffs, subject to modification based on the outcome of the NOPR proceeding,
effective as of August 25, 1995. It is anticipated that a final rule, which
could be modified from the current proposal, could take effect in 1996. The
FERC also set the rates in the PSCo Tariffs and Cheyenne Tariffs for hearing.
On January 24, 1996, e prime filed with the FERC an amended power marketer
application. On January 26, 1996, PSCo and Cheyenne filed revised tariffs
containing terms and conditions conforming to the FERC's pro forma tariffs as
set out in the NOPR.
ENVIRONMENTAL ISSUES
Overview
As described below, the Company has been or is currently involved with the
clean-up of contamination from certain hazardous substances. In all situations,
the Company is pursuing or intends to pursue insurance claims and believes it
will recover some portion of these costs through such claims. Additionally,
where applicable, the Company intends to pursue recovery from other potentially
responsible parties. To the extent such costs are not recovered, the Company
currently believes it is probable that such costs will be recovered through the
rate regulatory process. However, as part of its merger filings (see discussion
in "Regulatory Matters - 1995 Merger Rate Filings"), the Company has proposed
implementing an electric rate moratorium for five years, and if its regulatory
authorities accept this proposal, the likelihood of the recovery of such clean-
up costs through the regulatory process may be diminished. To the extent any
costs are not recovered through the options listed above, the Company would be
required to recognize an expense for such unrecoverable amounts.
Environmental Site Cleanup
Under the 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 properties located in central Denver.
For an estimated 30 years, the Company sold scrap metal and electrical equipment
to Barter for reprocessing. The Company has completed the cleanup of this site
which began in November 1992. The cost of such clean-up was approximately $9
million as of December 31, 1995. On January 3, 1996, in a lawsuit by the
Company against its insurance providers, the Denver District Court entered final
judgment in favor of the Company in the amount of $5.6 million for certain clean
up costs at Barter. One of the insurance providers has appealed the Court's
judgment to the Colorado Court of Appeals. The insurance provider has posted
supersedeas bonds in the amount of $9.7 million ($7.7 million attributable to
the Barter judgment). Previously, the Company has received certain insurance
settlement proceeds from other insurance providers for Barter and other
contaminated sites and a portion of those funds remains to be allocated to this
site by the trial court. In addition, the Company expects to recoup additional
expenditures by sale of the Barter property.
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 Denver District Court. The action alleged that the
Company was responsible for the
53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
PCB releases and additionally claimed other damages in unspecified amounts. On
August 8, 1994, the Denver District Court entered a judgment approving a $5.3
million offer of settlement between the Company and the building owners
resolving all claims between the Company and the building owners. In December
1995, complaints were filed by the Company against all applicable insurance
carriers in Denver District Court.
The Ramp Industries disposal facility, located in Denver, Colorado has been
designated by the EPA as a Superfund hazardous waste site pursuant to CERCLA
and, on November 29, 1995, the Company received from the EPA a Notice of
Potential Liability and Request for Information related to such site. The EPA
is conducting an investigation of the contamination at this site and is in the
process of identifying the nature and quantities of hazardous wastes delivered
to, processed and currently stored at the site by PRPs. The Company has
responded to the EPA's request. The estimated cost to investigate and remediate
site contamination is not available as the EPA is in the initial stages of its
investigation. At this time, the Company cannot estimate the amount, if any, of
its potential liability related to this matter.
In addition to these sites, the Company has identified several sites where
cleanup of hazardous substances may be required. While potential liability and
settlement costs are still under investigation and negotiation, the Company
believes that the resolution of these matters will not have a material effect on
its financial position, results of operations or cash flows. The Company fully
intends to pursue the recovery of all significant costs incurred for such
projects through insurance claims and/or the rate regulatory process.
Other Environmental Matters
Under the Clean Air Act Amendments of 1990, coal burning power plants are
required to reduce SO2 and NOx emissions to specified levels through a phased
approach. The Company is currently meeting Phase I emission standards placed on
SO2 through the use of low sulfur coal and the operation of pollution control
equipment on certain generation facilities. The Company will be required to
modify certain boilers by the year 2000 to reduce NOx emissions in order to
comply with Phase II requirements. The estimated costs for future plant
modifications total approximately $51.4 million. The Company is studying its
options to reduce SO2 emissions and currently does not anticipate that these
regulations will significantly impact its operations.
In April 1992, the Company acquired interests in the two generating units
at the Hayden Steam Electric Generating Station located near Hayden, Colorado.
The Company currently is the operator of the Hayden station and owns an
undivided interest in each of the two generating units at the station which in
total average approximately 53%.
On August 18, 1993, a conservation organization filed a complaint in the
U.S. District Court for the District of Colorado pursuant to Section 304 of the
Federal Clean Air Act, against the Company and the other joint owners of the
Hayden station. The plaintiff alleges that: 1) the station exceeded the 20%
opacity limitations in excess of 19,000 six minute intervals during the period
extending from the last quarter of 1988 through mid-1993 based on the data and
reports obtained from the station's COM's, which measure average emission stream
opacity in six minute intervals on a continuous basis, 2) the station was
operated for over two weeks in late 1992 without a functioning electrostatic
precipitator which constituted a modification of the station without the
requisite permit from the Colorado Department of Public Health and Environment,
and 3) the owners failed to operate the station in a manner consistent with good
air pollution control practices. The complaint seeks, among other things, civil
monetary penalties and injunctive relief. The joint owners of the station
contest all of these claims and contend that there were no violations of the
opacity limitation, because pursuant to the Colorado state implementation plan,
visual emissions are to be measured by qualified personnel using the EPA's
visual test known as Method 9 and not by any measurements from the station's
COMs as alleged by the plaintiff.
Discovery was completed and oral arguments on summary judgment motions were
heard in mid-May 1995. On July 21, 1995, the U.S. District Court entered
partial summary judgment on liability issues in favor of the plaintiff in
regards to the claims described in items 1) and 3) above and denied the
plaintiff's motion in regards to the claims described in item 2) above. On July
31, 1995, the joint owners filed a petition for an interlocutory appeal with the
10th
54
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
Circuit Court of Appeals. On August 21, 1995, the joint owners' petition
for permission to appeal was denied. Subsequent to the denial of the joint
owners' petition, the U.S. District Court dismissed the plaintiffs claims
described in item 2) above. The joint owners are pursuing a settlement with the
conservation organization, the Colorado Department of Public Health and
Environment and the EPA. If settlement is not reached, court hearings for
injunctive relief, scheduled for May 1996, and the determination of penalties in
connection with the litigation, not yet scheduled, will be held. Further
appeals could be pursued by the joint owners if settlement is not achieved.
In December 1995, the conservation organization filed a motion for summary
judgment which would require the joint owners to come into compliance with the
opacity requirements identified in the August 1993 compliant within 60 days or
submit a plan for the installation of additional pollution control equipment.
On January 26, 1996, the joint owners and the conservation organization reached
an agreement providing for a stay of such litigation for 30 days to allow the
parties to concentrate their efforts on settlement. If settlement is not
achieved by the end of the stay, the Company cannot predict whether litigation
activities would resume, however, it anticipates that settlement discussions
would continue even if litigation activities did resume.
Additionally, the Company had received and responded to a request from the
EPA for information related to the plant and, on January 18, 1996, the EPA
issued a notice of violation stating the plant had exceeded the 20% opacity
limitations in excess of 10,000 additional six-minute intervals during the
period extending from mid-1993 to mid-1995. It is expected that the joint
owners will be able to resolve the issues related to this notice of violation as
part of the settlement discussions previously mentioned.
At this time, the Company is not able to estimate the amount, if any, of
its potential liability for penalties. The plaintiff has requested, among other
things, that the joint owners "pay to the EPA to finance air compliance and
enforcement activities, as provided for by 42 U.S.C. section 7604(g) (1), a
penalty of $25,000 per day for each of their violations of the Clean Air Act."
The statute provides for penalties of up to $25,000 per day per violation, but
the level of penalties imposed in any particular instance is discretionary. In
setting penalties in its own enforcement actions, the EPA relies, in part, on
such factors as the economic benefit of noncompliance, the actual or possible
harm of noncompliance, the size of the violator, the willfulness or negligence
of the violator and its degree of cooperation in resolving the matter. The
Company cannot predict the level of penalties, if any, or the remedies that the
court or the EPA may impose if settlement is not reached or if the joint owners
are unsuccessful in a subsequent appeal.
It is expected that additional pollution control equipment and practices
will be required at the station. The additional equipment and practices would
be designed to address particulate matter, SO2 and NOx emission concerns raised
by this litigation and by the Mt. Zirkel Wilderness Area Reasonable Attribution
Study, which is expected to be finalized during 1996. The Company is evaluating
the economic impact of adding such pollution control equipment and practices on
future plant operations.
The Company believes that, consistent with historical regulatory treatment,
any costs for pollution control equipment to comply with pollution control
regulations would be recovered from its customers. However, no assurance can be
given that this practice will continue in the future.
PURCHASE REQUIREMENTS
Coal purchases and transportation
At December 31, 1995, 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 86 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 $769 million
at December 31, 1995.
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
55
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
a minimum remaining transport quantity of 21 million tons. Coal transport
contract prices are negotiated based on market conditions and are adjusted
periodically for inflation and operating factors. Total estimated obligations,
based on current prices, were approximately $50 million at December 31, 1995.
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 2001. In compliance
with the rules established by FERC Order 636, the Company renegotiated contracts
during 1993 with its two primary gas pipeline suppliers and committed to
continue purchasing gas through 1996. The Company will not incur any gas supply
realignment costs otherwise applicable under FERC Order 636. At December 31,
1995, the Company and Cheyenne have minimum obligations under such contracts of
approximately $46 million in 1996 declining thereafter for a total estimated
commitment of approximately $97 million.
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 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 2026. 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 and 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. These costs have historically been recoverable through the ECA;
however, effective December 1, 1993, the Company's capacity costs were reflected
in base rates. Total capacity and energy payments associated with such
contracts were $445 million, $427 million, and $366 million in 1995, 1994 and
1993, respectively.
At December 31, 1995, 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)
1996................. $ 144,019 $ 176,712 $ 320,731
1997................. 144,102 185,127 329,229
1998................. 143,818 186,733 330,551
1999................. 143,794 178,860 322,654
2000................. 141,878 168,372 310,250
2001 and thereafter.. 1,146,656 1,426,895 2,573,551
---------- ---------- ----------
Total.............. $1,864,267 $2,322,699 $4,186,966
========== ========== ==========
Historically, all minimum coal, coal transportation, natural gas and
purchased power requirements have been met.
56
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
Other purchases
Commitments made for the purchase of materials, plant and equipment
additions, DSM expenditures and other various items aggregated approximately
$599 million at December 31, 1995.
EMPLOYEE LITIGATION
Several employee lawsuites have been filed against the Company involving
alleged sexual/age/race/disability discrimination. The Company is actively
contesting all such lawsuits and believes the ultimate outcome will not have a
material impact on the Company's results of operations, financial position or
cash flow.
In one of the cases, certain employees terminated as part of the Company's
1991/1992 organizational analysis asserted breach of contract and promissory
estoppel with respect to job security and breach of the covenant of good faith
and fair dealing. Of the 21 actions filed, the trial court directed verdicts in
favor of the Company in 19 cases. Two cases went to a jury, which entered
verdicts adverse to the Company. All 21 decisions are currently on appeal, but
the Company believes its liability, if any, will not have a material impact on
the Company's results of operations, financial position or cash flow.
UNION CONTRACTS
In early December 1995, the Company's contracts with the International
Brotherhood of Electrical Workers, Local 111 expired. Previously, an arbitrator
had rejected the Company's attempt to cancel the contract. The parties have
been unable to reach agreement through the negotiation process and, as a result,
will enter binding arbitration on March 20, 1996, as required under the
provisions of the contracts. Contract provisions will be determined as part of
the binding arbitration process, including the length of the contract extension
and wages. In addition, the International Brotherhood of Electrical Workers,
Local 111 has filed a grievance relating to the employment of certain non-union
personnel to perform services for the Company, which matter is currently in
arbitration. Approximately 2,150 employees or 45% of the Company's total
workforce, are represented by Local 111.
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 $53.7 million and $17.1 million at
December 31, 1995, and 1994, 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
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 1995, 1994 and 1993 was $23.5 million, $29.7
million and $28.1 million, respectively.
57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
Estimated future minimum lease payments at December 31, 1995 are as follows:
CAPITAL OPERATING
LEASES LEASES
-------- ---------
(THOUSANDS OF DOLLARS)
1996............................................. $ 9,776 $ 19,953
1997............................................. 9,586 19,947
1998............................................. 9,379 19,053
1999............................................. 7,904 13,320
2000............................................. 5,096 11,643
All years thereafter............................. 86,212 22,041
-------- --------
Total future minimum lease payments.......... 127,953 $105,957
========
Less amounts representing interest........... 74,251
--------
Present value of net minimum lease payments.. $ 53,702
========
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.
FORT ST. VRAIN
See Note 2 for certain contingencies relating to Fort St. Vrain.
10. JOINTLY-OWNED ELECTRIC UTILITY PLANTS
The Company's investment in jointly-owned plants and its ownership percentages
as of December 31, 1995 is:
PLANT CONSTRUCTION
IN ACCUMULATED WORK IN
SERVICE DEPRECIATION PROGRESS OWNERSHIP %
------- ------------ ------------ -----------
(THOUSANDS OF DOLLARS)
Hayden Unit 1................................... $ 37,846 $28,971 $ 702 75.50
Hayden Unit 2................................... 58,039 31,894 116 37.40
Hayden Common Facilities........................ 1,870 349 891 53.10
Craig Units 1 & 2............................... 57,057 22,426 627 9.72
Craig Common Facilities Units 1 & 2............. 7,702 2,957 775 9.72
Craig Common Facilities Units 1,2 & 3........... 8,383 3,159 387 6.47
Transmission Facilities, Including Substations.. 79,069 20,811 111 42.0-73.0
-------- -------- ------
$249,966 $110,567 $3,609
======== ======== ======
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.
11. EMPLOYEE BENEFITS
PENSIONS
The Company and Cheyenne maintain a noncontributory defined benefit pension
plan covering substantially all employees.
58
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
The net pension expense in 1995, 1994 and 1993 was comprised of:
1995 1994 1993
---------- --------- ---------
(THOUSANDS OF DOLLARS)
Service cost................................... $ 11,659 $ 16,169 $ 15,868
Interest cost on projected benefit obligation.. 46,570 45,518 38,106
Actual return on plan assets................... (123,531) 5,844 (52,369)
Amortization of net transition asset........... (3,674) (3,674) (3,674)
Other items.................................... 75,521 (56,996) 8,219
--------- -------- --------
Net pension expense........................... $ 6,545 $ 6,861 $ 6,150
========= ======== ========
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
1995 1994 1994 1993
----- --------- ---------- -----
Discount rate................................................. 8.75% 8.0% 7.5% 8.2%
Expected long-term increase in compensation level............. 5.0% 5.0% 5.0% 5.5%
Expected weighted average long-term rate of return on assets.. 9.75% 10.5% 10.5% 11.0%
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, 1995 and 1994, 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.
1995 1994
---------- ----------
(THOUSANDS OF DOLLARS)
Actuarial present value of benefit obligations:
Vested........................................ $523,539 $410,117
Nonvested..................................... 31,678 30,136
-------- --------
555,217 440,253
Effect of projected future salary increases....... 91,810 87,079
--------- ---------
Projected benefit obligation for service rendered
to date.......................................... 647,027 527,332
Plan assets at fair value......................... (588,314) (491,735)
--------- ---------
Projected benefit obligation in excess of plan
assets........................................... (58,713) (35,597)
Unrecognized net loss............................. 62,092 33,650
Prior service cost not yet recognized in net
periodic pension cost............................ 30,063 32,368
Unrecognized net transition asset at January 1,
1986, being recognized over 17 years............. (25,716) (29,390)
--------- ---------
Prepaid pension asset............................. $ 7,726 $ 1,031
========= =========
Significant assumptions used in determining the benefit obligations at the
end of each respective year were:
1995 1994
----- -----
Discount rate..................................... 7.25% 8.75%
Expected long-term increase in compensation level.. 4.0% 5.0%
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
59
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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.
During 1993, the Board of Directors of the Company approved amendments that:
1) eliminated the minimum age of 21 for receiving credited service, 2) provided
for an automatic increase in monthly payments to a retired plan member in the
event the member's spouse or other contingent annuitant dies prior to the
member, and 3) provided for Average Final Compensation to be based on the
highest average of three consecutive years compensation. These plan changes
increased the projected benefit obligation by approximately $24.6 million.
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 adoption of SFAS 106 did not have a
material impact on the Company's consolidated results of operations, financial
position or cash flow.
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.
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.
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.
60
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
The net periodic postretirement benefit cost in 1995, 1994 and 1993 under
SFAS 106 was comprised of:
1995 1994 1993
--------- ---------- --------
(THOUSANDS OF DOLLARS)
Service cost.............................................................................. $ 6,027 $ 6,101 $ 4,943
Interest cost on projected benefit obligation............................................. 24,761 24,111 20,828
Return on plan assets..................................................................... (2,578) (938) (164)
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...................................... 40,920 41,984 38,317
OPEB expense recognized in accordance with current regulation............................. (30,893) (30,266) (12,462)
-------- -------- --------
Increase in regulatory asset (Note 1)..................................................... 10,027 11,718 25,855
Regulatory asset at beginning of year..................................................... 37,573 25,855 -
-------- -------- --------
Regulatory asset at end of year........................................................... $ 47,600 $ 37,573 $ 25,855
======== ======== ========
Significant assumptions used in determining net periodic postretirement benefit
cost were:
APR -DEC JAN - MAR
1995 1994 1994 1993
-------- -------- -------- -------
Discount rate.......................................................................... 8.75% 8.0% 7.5% 8.2%
Expected long-term increase in compensation level...................................... 5.0% 5.0% 5.0% 5.5%
Expected weighted average long-term rate of return on assets........................... 9.75% 10.5% 10.5% 10.5%
A comparison of the actuarially computed benefit obligations and plan
assets at December 31, 1995 and 1994 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.
1995 1994
------------ --------
(THOUSANDS OF DOLLARS)
Accumulated postretirement benefit obligation:
Retirees and eligible beneficiaries............... $122,395 $95,382
Other fully eligible plan participants............ 93,161 71,683
Other active plan participants.................... 102,739 86,505
--------- --------
Total.............................. 318,295 253,570
Plan assets at fair value, excluding amounts
funded in a non-qualified trust, totaling $2.5
million at December 31, 1995...................... (38,623) (18,114)
--------- ---------
Accumulated benefit obligation in excess of
plan assets....................................... 279,672 235,456
Unrecognized net gain (loss)....................... (11,905) 35,423
Unrecognized transition obligation................. (216,063) (228,773)
--------- ---------
Accrued postretirement benefit obligation.......... $ 51,704 $ 42,106
========= =========
Significant assumptions used in determining the accumulated postretirement
benefit obligation at the end of each respective year were:
1995 1994
----- -----
Discount rate..................................... 7.25% 8.75%
Ultimate health care cost trend rate.............. 4.5% 6.0%
Expected long-term increase in compensation level. 4.0% 5.0%
The assumed health care cost trend rate for 1996 is 9.5%, 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 benefit obligation by
$41.6 million, and the service and interest cost components of net periodic
postretirement benefit costs by $5.1 million.
61
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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, 1995 and 1994,
the Company had recorded a $23.5 million and $21.0 million regulatory asset
(see Note 1) and a corresponding liability on the consolidated balance sheet,
assuming a 7.25% and an 8.0% 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 which included a request for recovery of all
electric wholesale jurisdiction SFAS 112 costs. The Company believes it is
probable that it will receive FERC and other regulatory approvals to recover
these costs in the future.
INCENTIVE COMPENSATION
The Omnibus Incentive Plan 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 Plan as it allows for the issuance of
restricted shares and/or stock options. Cash, restricted stock and stock option
awards were made under the Omnibus Incentive Plan during 1995, 1994 and 1993.
The stock options are issued at the fair market value of the Company's common
stock at the date of issue and vest over a three-year period. During 1995, 1994
and 1993, 161,000, 149,700 and 58,544 options to purchase stock were granted
with weighted-average exercise prices of $30.29, $28.73 and $28.125,
respectively. During 1995, 267 options were exercised at a price of $29.00 per
share. There were no options exercised in 1994 or 1993. At December 31, 1995,
347,931 options were outstanding with a weighted-average exercise price of
$29.33 of which 125,931 shares were exercisable at a weighted-average exercise
price of $28.52. In the event 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 Employee Incentive Plan 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 Omnibus Incentive Plan and the Employee
Incentive Plan totaled approximately $6.4 million in 1995, $6.0 million in 1994
and $5.2 million in 1993.
12. FINANCIAL INSTRUMENTS
FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and fair values of the
Company's significant financial instruments at December 31, 1995 and 1994. 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.
1995 1994
-------------------- ----------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
---------- ---------- ---------- ----------
(THOUSANDS OF DOLLARS)
Investments, at cost............................. $ 10,083 $ 10,131 $ 7,308 $ 7,283
Preferred stock subject to mandatory redemption.. 43,865 45,184 45,241 45,518
Long-term debt................................... 1,229,231 1,307,128 1,168,480 1,119,391
62
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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
In accordance with NRC decommissioning funding requirements for nuclear
power reactors, the Company has a $43 million irrevocable letter of credit which
bears a market interest rate. The NRC is the beneficiary of this letter of
credit. At December 31, 1995 and 1994, no amounts were outstanding under this
letter of credit. In general, such letter of credit may be exercised by the NRC
in the event the Company is in default of its performance obligations under the
decommissioning plan.
YGSC, a wholly-owned subsidiary, 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 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, 1995, 1994
and 1993 consist of the following:
1995 1994 1993
------- ------- -------
(THOUSANDS OF DOLLARS)
Current income taxes:
Federal.............................. $58,728 $22,081 $34,684
State................................ 2,807 (2,016) (2,208)
------- ------- -------
Total current income taxes......... 61,535 20,065 32,476
------- ------- -------
Deferred income taxes:
Federal.............................. 38,006 31,042 27,929
State................................ 1,164 3,192 5,506
------- ------- -------
Total deferred income taxes........ 39,170 34,234 33,435
------- ------- -------
Investment tax credits - net............. (5,348) (5,799) (4,917)
------- ------- -------
Total provision for income taxes......... $95,357 $45,500 $60,994
======= ======= =======
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.
63
NOTES TO CONSOLIDTED FINANCIAL STATEMENTS-(CONTINUED)
A reconciliation of the statutory U.S. income tax rates and the effective
tax rates follows:
1995 1994 1993
--------------- ---------------- ---------------
(THOUSAND OF DOLLARS)
Tax computed at U.S. statutory rate on
pre-tax accounting income................. $95,975 35.0% $ 76,569 35.0% $76,424 35.0%
Increase (decrease) in tax from:
Allowance for funds used
during construction....................... (2,495) (0.9) (2,449) (1.1) (4,369) (2.0)
Amortization of investment tax credits...... (5,348) (1.9) (5,792) (2.6) (4,889) (2.2)
Cash surrender value of life
insurance policies........................ (9,546) (3.5) (7,643) (3.5) (6,386) (2.9)
Capitalized software, net of amortization... - - - - (4,820) (2.2)
Capitalized overheads....................... - - - - 7,170 3.3
Lease amortization.......................... - - - - 3,692 1.7
Amortization of prior flow-through amounts.. 10,509 3.8 10,509 4.8 934 0.4
Adoption of SFAS 109........................ - - - - (1,911) (0.9)
Tax accrual adjustment...................... - - (21,262) (9.7) - -
Other-net................................... 6,262 2.3 (1,432) (0.7) (4,851) (2.2)
------- ---- -------- ---- ------- ----
Total income taxes........................ $95,357 34.8% $ 48,500 22.2% $60,994 28.0%
======= ==== ======== ==== ======= ====
The Company and its subsidiaries adopted SFAS 109 on January 1, 1993. The
impact of adoption was not material to the consolidated results of operations
and, therefore, was not reflected as the cumulative effect of a change in
accounting principle.
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 unamortized investment tax credits and excess
deferred income taxes that have resulted from historical reductions in tax rates
(see Note 1).
Effective December 1, 1993, pursuant to a CPUC order, the Company adopted
full income tax normalization for rate regulatory purposes with the regulatory
tax asset being recovered over a thirteen year period. Effective January 1,
1993, Cheyenne began recovering SFAS 109 costs as approved by the WPSC.
The tax effects of significant temporary differences representing deferred
tax liabilities and assets as of December 31, 1995 and 1994 are as follows:
1995 1994
---------- ----------
(THOUSANDS OF DOLLARS)
Deferred income tax liabilities:
Accelerated depreciation and amortization............ $376,468 $332,222
Plant basis differences (prior flow-through)......... 152,631 188,194
Allowance for equity funds used during construction.. 50,411 49,824
Pensions............................................. 36,583 35,975
Other................................................ 50,760 41,792
-------- --------
Total............................................... 666,853 648,007
Deferred income tax assets:
Investment tax credits............................... 69,751 73,270
Contributions in aid of construction................. 55,654 47,832
Other................................................ 52,534 61,946
-------- --------
Total............................................... 177,939 183,048
-------- --------
Net deferred income tax liability.................... $488,914 $464,959
======== ========
As of December 31, 1995, the Company has cumulative AMT carryforwards of
approximately $5.3 million and state tax credit carryforwards of approximately
$2.3 million. A valuation allowance has not been recorded as the Company
expects that all deferred income tax assets will be realized in the future.
64
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
14. SEGMENTS OF BUSINESS
1995 ELECTRIC GAS OTHER TOTAL
--------- ---------- -------- ------- ----------
(THOUSANDS OF DOLLARS)
Operating revenues.......................... $1,449,096 $624,585 $36,920 $2,110,601
---------- -------- ------- ----------
Operating expenses, excluding depreciation
and income taxes.......................... 1,005,432 539,636 7,046 1,552,114
Depreciation and amortization............... 109,498 29,901 1,981 141,380
---------- -------- ------- ----------
Total operating expenses*................... 1,114,930 569,537 9,027 1,693,494
---------- -------- ------- ----------
Operating income*........................... 334,166 55,048 27,893 417,107
========== ======== ======= ==========
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.................... 736,504
----------
$4,354,295
==========
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
==========
1993
---------
Operating revenues......................... $1,337,053 $628,324 $33,308 $1,998,685
---------- -------- ------- ----------
Operating expenses, excluding depreciation
and income taxes.......................... 953,049 560,593 2,312 1,515,954
Depreciation and amortization............... 109,958 28,305 2,541 140,804
---------- -------- ------- ----------
Total operating expenses*................. 1,063,007 588,898 4,853 1,656,758
---------- -------- ------- ----------
Operating income*........................... 274,046 39,426 28,455 341,927
========== ======== ======= ==========
Plant construction expenditures**........... 205,153 86,867 1,495 293,515
========== ======== ======= ==========
Identifiable assets:
Property, plant and equipment**............ 2,413,585 695,456 84,100 3,193,141
Materials and supplies.................... 64,674 12,993 65 77,732
Fuel inventory............................ 35,337 - 147 35,484
Gas in underground storage................ - 41,130 - 41,130
Other corporate assets.................... 710,113
----------
$4,057,600
==========
(1) Includes additional expense of approximately $43.4 million for defueling
and decommissioning.
* Before income taxes.
** Includes allocation of common utility property.
65
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
15. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following summarized quarterly information for 1995 and 1994 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
-------- --------------- ------------------- -----------
1995 (IN THOUSANDS-EXCEPT PER SHARE DATA)
--------
Operating revenues.......................... $620,596 $498,699 $468,453 $522,853
Operating income............................ $ 91,689 $ 62,634 $ 81,069 $ 86,358
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
1994
--------
Operating revenues.......................... $612,436 $477,563 $431,954 $535,431
Operating income............................ $ 78,430 $ 58,027 $ 47,601 $ 86,734
Net income.................................. $ 46,529 $ 23,875 $ 49,054 $ 50,811
Earnings available for common stock......... $ 43,524 $ 20,870 $ 46,051 $ 47,810
Weighted average common shares outstanding.. 60,919 61,425 61,779 62,064
Earnings per weighted average common share.. $ 0.71 $ 0.34 $ 0.75 $ 0.77
66
SCHEDULE II
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
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:
1995................................. $3,173 $7,815 $ 4 $7,362 $3,630
========== ========= ========== ========== =======
1994................................. $3,276 $8,533 $132 $8,768 $3,173
========== ========= ========== ========== =======
1993................................. $3,388 $6,878 $ 13 $7,003 $3,276
========== ========= ========== ========== =======
- -----------------
(1) Uncollectible accounts subsequently recovered, transfers from customers'
deposit, etc.
(2) Uncollectible accounts written off.
67
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,
------------------------------------------------
1995 1994 1993 1992 1991
-------- -------- -------- -------- --------
(THOUSANDS OF DOLLARS, EXCEPT RATIOS)
FIXED CHARGES:
Interest on long-term debt.............................. $ 85,832 $ 89,005 $ 98,089 $ 92,581 $ 81,666
Interest on borrowings against COLI contracts........... 34,717 29,786 25,333 18,312 8,144
Other interest.......................................... 23,392 14,235 9,445 12,357 14,574
Amortization of debt discount and expense less premium.. 3,278 3,126 2,018 1,790 1,827
Interest component of rental expense.................... 6,729 6,888 6,824 7,904 6,892
-------- -------- -------- -------- --------
Total............................................... $153,948 $143,040 $141,709 $132,944 $113,103
======== ======== ======== ======== ========
EARNINGS (BEFORE FIXED CHARGES AND TAXES ON INCOME):
Net income.............................................. $178,856 $170,269 $157,360 $136,623 $149,693
Fixed charges as above.................................. 153,948 143,040 141,709 132,944 113,103
Provisions for Federal and state taxes on income,
net of investment tax credit amortization............. 95,357 48,500 60,994 53,149 69,288
-------- -------- -------- -------- --------
Total............................................... $428,161 $361,809 $360,063 $322,716 $332,084
======== ======== ======== ======== ========
RATIO OF EARNINGS TO FIXED CHARGES......................... 2.78 2.53 2.54 2.43 2.94
======== ======== ======== ======== ========
68
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,
------------------------------------------------
1995 1994 1993 1992 1991
-------- -------- -------- -------- --------
(Thousand of Dollars, except ratios)
FIXED CHARGES AND PREFERRED STOCK DIVIDENDS:
Interest on long-term debt.............................. $ 85,832 $ 89,005 $ 98,089 $ 92,581 $ 81,666
Interest on borrowings against COLI contracts........... 34,717 29,786 25,333 18,312 8,144
Other interest.......................................... 23,392 14,235 9,445 12,357 14,574
Amortization of debt discount and expense less premium.. 3,278 3,126 2,018 1,790 1,827
Interest component of rental expense.................... 6,729 6,888 6,824 7,904 6,892
Preferred stock dividend requirement.................... 11,963 12,014 12,031 12,077 12,234
Additional preferred stock dividend requirement......... 6,377 3,422 4,662 4,699 5,662
-------- -------- -------- -------- --------
Total................................................. $172,288 $158,476 $158,402 $149,720 $130,999
======== ======== ======== ======== ========
EARNINGS (BEFORE FIXED CHARGES AND TAXES ON INCOME):
Net income.............................................. $178,856 $170,269 $157,360 $136,623 $149,693
Interest on long-term debt.............................. 85,832 89,005 98,089 92,581 81,666
Interest on borrowings against COLI contracts........... 34,717 29,786 25,333 18,312 8,144
Other interest.......................................... 23,392 14,235 9,445 12,357 14,574
Amortization of debt discount and expense less premium.. 3,278 3,126 2,018 1,790 1,827
Interest component of rental expense.................... 6,729 6,888 6,824 7,904 6,892
Provisions for Federal and state taxes on income,
net of investment tax credit amortization.............. 95,357 48,500 60,994 53,149 69,288
-------- -------- -------- -------- --------
Total................................................. $428,161 $361,809 $360,063 $322,716 $332,084
======== ======== ======== ======== ========
RATIO OF EARNINGS TO FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS......................... 2.49 2.28 2.27 2.16 2.54
======== ======== ======== ======== ========
69
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
Information concerning the directors of the registrant is contained under
Election Of Directors in the registrant's 1996 Proxy Statement, which
information is incorporated herein by reference.
Executive Officers (at December 31, 1995 except as noted):
Executive Officers Initial Effective Date
- ------------------ ----------------------
D. D. Hock, Age 60 *
Chairman of the Board................................................ February 28, 1989
and Chief Executive Officer......................................... October 1, 1988
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
President, 1480 Welton, Inc.......................................... March 22, 1990
Chairman of the Board and President, PSR Investments, Inc............ March 22, 1990
Chairman of the Board and President, 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
President, Natural Fuels Corporation................................. November 5, 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 53 *
President and Chief Operating Officer................................ June 28, 1994
President, Young Gas Storage Company................................. June 27, 1995
President, WestGas InterState, Inc................................... April 19, 1995
President, Fuel Resources Development Co............................. April 27, 1995
President, Green and Clear Lakes Company............................. December 5, 1995
Company Service: June, 1994
Richard C. Kelly, Age 49
Senior Vice President, Finance, Treasurer............................ June 28, 1994
and Chief Financial Officer......................................... January 23,1990
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
70
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
Patricia T. Smith, Age 48
Senior Vice President and General Counsel............................ December 5, 1994
Company Service: December, 1994
W. Wayne Brown, Age 45
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 63
Vice President, Engineering and Operations Support................... June 28, 1994
Company Service: May, 1989
Ross C. King, Age 54
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 55
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 46
Vice President, Production and System Operations..................... June 28, 1994
Company Service: July, 1978
Marilyn E. Taylor, Age 53
Vice President, Human Resources...................................... June 28, 1994
Company Service: December, 1987
* On December 19, 1995, the Company announced that D. D. Hock would step
down as Chief Executive Officer ("CEO"), effective January 1, 1996, but would
remain as Chairman of the Board. Wayne H. Brunetti was elected by the board of
directors to succeed Mr. Hock as CEO, effective January 1, 1996.
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:
71
Mr. Hock has been Chief Operating Officer and President;
Mr. Brunetti has been 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;
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.
ITEM 11. EXECUTIVE COMPENSATION
Information concerning executive compensation is contained under
Compensation Of Executive Officers And Directors in the registrant's 1996 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
1996 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 1996 Proxy Statement,
which information is incorporated herein by reference.
72
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 Independent Public Accountants.............................. 33
Consolidated Balance Sheets, December 31, 1995 and 1994............... 34
Consolidated Statements of Income for each of the three
years in the period ended December 31, 1995...................... 36
Consolidated Statements of Shareholders' Equity for each
of the three years in the period ended December 31, 1995......... 37
Consolidated Statements of Cash Flows for each of the three
years in the period ended December 31, 1995...................... 38
Notes to Consolidated Financial Statements............................ 39
2. Financial Statement Schedules:
II Valuation and Qualifying Accounts and Reserves
(Consolidated) for each of the three years in the period
ended December 31, 1995.......................................... 67
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.............................. 79
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 August 22, 1995, was filed on August 23, 1995.
The item reported was Item 5 - Other Events, which presented information on: 1)
the Merger Agreement dated August 22, 1995, by and among the Company, SPS and
NCE (formerly M-P New Co.), a newly formed Delaware corporation, to serve as the
holding company, 2) a joint press release announcing the proposed merger, and 3)
an amendment, dated August 22, 1995 to the Rights Agreement dated as of February
26, 1991 between Public Service Company of Colorado and Mellon Bank, N.A.
A report on Form 8-K, dated December 19, 1995, was filed on December 20,
1995. The item reported was Item 5 - Other Events, announcing that effective
January 1, 1996, D. D. Hock, Chairman and Chief Executive Officer (CEO) of
Public Service Company of Colorado would step down from the CEO position but
73
would remain as Chairman of the Board. Wayne H. Brunetti was elected by the
board of directors to succeed Mr. Hock as CEO, effective January 1, 1996.
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.
74
EXPERTS
The consolidated balance sheets of the Company and its subsidiaries as of
December 31, 1995 and 1994, the related consolidated statements of income,
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 1995, 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, 1995, 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.
75
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 and the Company's Registration
Statement (Form S-3, File No. 33-54877) pertaining to the shelf registration of
the Company's First Collateral Trust Bonds and Cumulative Preferred Stock and to
all references to our Firm included in this Form 10-K.
ARTHUR ANDERSEN LLP
Denver, Colorado
February 27, 1996
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.
76
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 27TH DAY OF FEBRUARY, 1996.
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 27, 1996
W. H. Brunetti Officer and Director
President and Chief Executive
Officer
/s/ R. C. Kelly
__________________________________ Principal Financial February 27,1996
R. C. Kelly Officer
Senior Vice President,
Finance, Treasurer and
Chief Financial Officer
/s/ W. Wayne Brown
__________________________________ Principal Accounting February 27,1996
W. Wayne Brown Officer
Controller and Corporate Secretary
77
SIGNATURE TITLE DATE
________________________________________________________________________________
/s/ D. D. Hock
__________________________________ Chairman of the Board February 27, 1996
Delwin D. Hock and Director
/s/ Collis P. Chandler
__________________________________ Director February 27, 1996
Collis P. Chandler
/s/ Doris M. Drury
__________________________________ Director February 27, 1996
Doris M. Drury
/s/ Thomas T. Farley
__________________________________ Director February 27, 1996
Thomas T. Farley
/s/ Gayle L. Greer
__________________________________ Director February 27, 1996
Gayle L. Greer
/s/ A. Barry Hirschfeld
__________________________________ Director February 27, 1996
A. Barry Hirschfeld
/s/ George B. McKinley
__________________________________ Director February 27, 1996
George B. McKinley
__________________________________ Director February 27, 1996
Will F. Nicholson, Jr.
/s/ J. Michael Powers
__________________________________ Director February 27, 1996
J. Michael Powers
/s/ Thomas E. Rodriguez
__________________________________ Director February 27, 1996
Thomas E. Rodriguez
__________________________________ Director February 27, 1996
Rodney E. Slifer
/s/ W. Thomas Stephens
__________________________________ Director February 27, 1996
W. Thomas Stephens
__________________________________ Director February 27, 1996
Robert G. Tointon
78
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 July 1, 1968 8-K, July 1968 2
May 14, 1941 10, 1946 B-3 Apr. 25, 1969 8-K, Apr. 1969 1
Apr. 28, 1942 10, 1946 B-4 Apr. 21, 1970 8-K, Apr. 1970 1
Apr. 14, 1943 10, 1946 B-5 Sept. 1, 1970 8-K, Sept. 1970 2
Apr. 27, 1944 10, 1946 B-6 Feb. 1, 1971 8-K, Feb. 1971 2
Apr. 18, 1945 10, 1946 B-7 Aug. 1, 1972 8-K, Aug. 1972 2
Apr. 23, 1946 10-K, 1946 B-8 June 1, 1973 8-K, June 1973 1
Apr. 9, 1947 10-K, 1946 B-9 Mar. 1, 1974 8-K, Apr. 1974 2
June 1, 1947 S-1, (2-7075) 7(b) Dec. 1, 1974 8-K, Dec. 1974 1
Apr. 1, 1948 S-1, (2-7671) 7(b)(1) Oct. 1, 1975 S-7, (2-60082) 2(b)(3)
May 20, 1948 S-1, (2-7671) 7(b)(2) Apr. 28, 1976 S-7, (2-60082) 2(b)(4)
Oct. 1, 1948 10-K, 1948 4 Apr. 28, 1977 S-7, (2-60082) 2(b)(5)
Apr. 20, 1949 10-K, 1949 1 Nov. 1, 1977 S-7, (2-62415) 2(b)(3)
Apr. 24, 1950 8-K, Apr. 1950 1 Apr. 28, 1978 S-7, (2-62415) 2(b)(4)
Apr. 18, 1951 8-K, Apr. 1951 1 Oct. 1, 1978 10-K, 1978 D(1)
Oct. 1, 1951 8-K, Nov. 1951 1 Oct. 1, 1979 S-7, (2-66484) 2(b)(3)
Apr. 21, 1952 8-K, Apr. 1952 1 Mar. 1, 1980 10-K, 1980 4(c)
Dec. 1, 1952 S-9, (2-11120) 2(b)(9) Apr. 28, 1981 S-16, (2-74923) 4(c)
Apr. 15, 1953 8-K, Apr. 1953 2 Nov. 1, 1981 S-16, (2-74923) 4(d)
Apr. 19, 1954 8-K, Apr. 1954 1 Dec. 1, 1981 10-K, 1981 4(c)
Oct. 1, 1954 8-K, Oct. 1954 1 Apr. 29, 1982 10-K, 1982 4(c)
Apr. 18, 1955 8-K, Apr. 1955 1 May 1, 1983 10-K, 1983 4(c)
Apr. 24, 1956 10-K, 1956 1 Apr. 30, 1984 S-3, (2-95814) 4(c)
May 1, 1957 S-9, (2-13260) 2(b)(15) Mar. 1, 1985 10-K, 1985 4(c)
Apr. 10, 1958 8-K, Apr. 1958 1 Nov. 1, 1986 10-K, 1986 4(c)
May 1, 1959 8-K, May 1959 2 May 1, 1987 10-K, 1987 4(c)
Apr. 18, 1960 8-K, Apr. 1960 1 July 1, 1990 S-3, (33-37431) 4(c)
Apr. 19, 1961 8-K, Apr. 1961 1 Dec. 1, 1990 10-K, 1990 4(c)
Oct. 1, 1961 8-K, Oct. 1961 2 Mar. 1, 1992 10-K, 1992 4(d)
Mar. 1, 1962 8-K, Mar. 1962 3(a) Apr. 1, 1993 10-Q, June 30, 1993 4(a)
June 1, 1964 8-K, June 1964 1 June 1, 1993 10-Q, June 30, 1993 4(b)
May 1, 1966 8-K, May 1966 2 Nov. 1, 1993 S-3, (33-51167) 4(a)(3)
July 1, 1967 8-K, July 1967 2 Jan. 1, 1994 10-K, 1993 4(a)(3)
Sept. 2, 1994 8-K, Sept. 1994 4(a)
79
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)
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(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(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(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
80
(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.
10(g)(5)+ Amendment to Employment Agreement dated August 22, 1995 between
the Company and Mr. Delwin D. Hock.
10(g)(6)+ Amendment to Employment Agreement dated August 22, 1995 between
the Company and Mr. Wayne H. Brunetti.
10(g)(7)+ Amendment to Employment Agreement dated August 22, 1995 between
the Company and Ms. Patricia T. Smith.
12(a) Computation of Ratio of Consolidated Earnings to Consolidated
Fixed Charges is set forth at page 68 herein.
12(b) Computation of Ratio of Consolidated Earnings to Consolidated
Combined Fixed Charges and Preferred Stock Dividends is set forth
at page 69 herein.
21 Subsidiaries
23 The Consent of Arthur Andersen LLP is set forth at page 76 herein.
24 Power of Attorney is set forth at page 76 herein.
27 Financial Data Schedule UT
_________________
* 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.
81