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Form 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[ x ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1994
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 $25 per share
8.40% Series New York
Securities Registered Pursuant to Section 12(g) of the Act:
Cumulative Preferred Stock, par value $100 per share
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of the registrant's Common Stock, $5.00 par
value (the only class of voting stock), held by non-affiliates was
$1,888,210,116, based on the last sale price thereof reported on the
consolidated tape for February 24, 1995.
At February 24, 1995, 62,679,174 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 1995 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 . . . . . . . . . . . . . . . . . . . . . 5
Fort St. Vrain . . . . . . . . . . . . . . . . . . . . . . . . 5
Electric Fuel Supply . . . . . . . . . . . . . . . . . . . . . . . 5
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Natural Gas and Fuel Oil . . . . . . . . . . . . . . . . . . . 7
Natural Gas Operations . . . . . . . . . . . . . . . . . . . . . . 7
Gas Supply . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Young Storage . . . . . . . . . . . . . . . . . . . . . . . . . 8
WGI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
WGT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
WGG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Fuelco . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Regulation and Rates . . . . . . . . . . . . . . . . . . . . . . . 9
State Regulation . . . . . . . . . . . . . . . . . . . . . . . 9
CPUC . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Electric and Gas Adjustment Clauses . . . . . . . . . . . . 9
Incentive Regulation and Demand Side Management . . . . . . 10
1993 Rate Case . . . . . . . . . . . . . . . . . . . . . . . 10
IRP - Electric . . . . . . . . . . . . . . . . . . . . . . 11
IRP - Gas . . . . . . . . . . . . . . . . . . . . . . . . . 11
WPSC . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Environmental Matters . . . . . . . . . . . . . . . . . . . . . . 12
Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Industry Outlook . . . . . . . . . . . . . . . . . . . . . . . 13
State Regulatory Environment . . . . . . . . . . . . . . . . . 13
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Franchises . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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 . . . . . . . . . . . . . . . . . . . . . . . . . 20
Transmission and Distribution Property . . . . . . . . . . . . . . 20
Gas Property . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Other Property . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Property of Subsidiaries . . . . . . . . . . . . . . . . . . . . . 21
Character of Ownership . . . . . . . . . . . . . . . . . . . 21
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . 21
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
i
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
Commitments and Contingencies . . . . . . . . . . . . . . . . . . 28
Liquidity and Capital Resources . . . . . . . . . . . . . . . . . 28
Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Prospective Capital Requirements and Sources . . . . . . . . . 29
Item 8. Financial Statements and Supplementary Data . . . . . . . . 32
Report of Independent Public Accountants . . . . . . . . . . . . . 32
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . 33
Consolidated Statements of Income . . . . . . . . . . . . . . . . 35
Consolidated Statements of Shareholders' Equity . . . . . . . . . 36
Consolidated Statements of Cash Flows . . . . . . . . . . . . . . 37
Notes to Consolidated Financial Statements . . . . . . . . . . . . 38
Schedule II . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
Exhibit 12(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67
Exhibit 12(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . 69
PART III
Item 10. Directors and Executive Officers of the Registrant . . . . 69
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . 71
Item 12. Security Ownership of Certain Beneficial Owners and
Management . . . . . . . . . . . . . . . . . . . . . . . . . . . 71
Item 13. Certain Relationships and Related Transactions . . . . . . 71
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
Experts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73
Consent of Independent Public Accountants . . . . . . . . . . . . . . 74
Power of Attorney . . . . . . . . . . . . . . . . . . . . . . . . . . 74
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77
ii
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
BCC . . . . . . . . . . . . . . . . . . . . . Bannock Center Corporation
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
Colorado-Ute . . . . . . . . . . Colorado-Ute Electric Association, Inc.
Comanche . . . . . . . . . . . Comanche Steam Electric Generating Station
Company . . . Public Service Company of Colorado (excluding subsidiaries)
CPCN . . . . . . . . . . Certificate of Public Convenience and Necessity
CPUC . . . . . . . . Public Utilities Commission of the State of Colorado
Craig . . . . . . . . . . . . . . Craig Steam Electric Generating Station
CWIP . . . . . . . . . . . . . . . . . . . Construction Work in Progress
CWQCD . . . . . . . . . . . . . . Colorado Water Quality Control Division
Denver District Court District Court in and for the City and County of Denver
DOE . . . . . . . . . . . . . . . . . . . . . . U.S. Department of Energy
DOJ . . . . . . . . . . . . . . . . . . . . . . U.S. Department of Justice
DSM . . . . . . . . . . . . . . . . . . . . . . . . Demand Side Management
DSMCA . . . . . . . . . . . . . . . Demand Side Management Cost Adjustment
e prime . . . . . . . . . . . . . . . . . . . . . . . . . . e prime, inc.
ECA . . . . . . . . . . . . . . . . . . . . . . . Electric Cost Adjustment
EIS . . . . . . . . . . . . . . . . . . . . Environmental Impact Statement
EPAct . . . . . . . . . . . . . . . . . National Energy Policy Act of 1992
EPA . . . . . . . . . . . . . . . . . U.S. Environmental Protection Agency
EWG . . . . . . . . . . . . . . . . . . . . . . Exempt Wholesale Generator
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.
Natural Fuels . . . . . . . . . . . . . . . . Natural Fuels Corporation
NOx . . . . . . . . . . . . . . . . . . . . . . . . . . . . Nitrogen Oxide
NPDES . . . . . . . . . National Pollution Discharge Elimination System
NRC . . . . . . . . . . . . . . . . . . . Nuclear Regulatory Commission
OCC . . . . . . . . . . . . . . . . Colorado Office of Consumer Counsel
OPEB . . . . . . . . . . . . . . . Other Postretirement Employee Benefits
PCB . . . . . . . . . . . . . . . . . . . . . . . Polychlorinated biphenyl
iii
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"
SO2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sulfur Dioxide
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.
Zuni . . . . . . . . . . . . . . . Zuni Steam Electric Generating Station
iv
PART I
Item l. 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 2.8 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.
As of December 31, 1994, the Company owned all of the outstanding
capital stock of Cheyenne, WGI, WGT, Fuelco, 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 and the
results of operations and cash flows of WGG, which was sold in August
1994, are included in the Company's consolidated financial statements.
Cheyenne is an electric and gas utility operating principally in
Cheyenne, Wyoming; WGI is a natural gas transmission company operating in
Colorado and Wyoming; WGT holds a one-third interest in a natural gas
transmission company which will operate in Colorado; Fuelco has been
engaged in the exploration for, and the development and production of,
natural gas and oil principally in Colorado; 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.
On January 30, 1995, the Company's wholly-owned subsidiary, e prime,
was incorporated. e prime will offer energy related products and services
to energy-using customers and to selected segments of the utility
industry.
Information regarding industry segments is set forth in Note 13.
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
1
"Regulation and Rates-State Regulation-IRP-Electric"), and its IRP Annual
Progress Report filed with the CPUC in October 1994, the Company proposes
to use the following resources to meet its net dependable system capacity:
1) the Company's 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 1995, net firm system peak demand for the Company and
Cheyenne is estimated to be 4,112 Mw, assuming normal weather conditions.
Net dependable system capacity is projected to be, after accounting for 53
Mw of demand-side options, 4,912 Mw (generating capacity of 3,186 Mw and
firm purchases of 1,726 Mw) at the time of the anticipated 1995 system
peak (summer season), resulting in a reserve margin of approximately 19%.
The net firm system peak demand for the Company and Cheyenne for
each of the last five years was as follows:
1990 1991 1992 1993 1994
Net Firm System Peak Demand* (Mw) 3,606 3,568 3,757 3,869 3,972
______________
* Excludes station housepower, nonfirm electric furnace load and
controlled interruptible loads (of which approximately 145 Mw, 162
Mw, 156 Mw, 164 Mw and 160 Mw in the years 1990-1994, 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, 1992, 1993 and 1994 occurred in the summer. The net firm
system peak demand for 1990 occurred in the winter. The net firm system
peak demand for 1994, which occurred on August 26, 1994, was 3,972 Mw. At
that time, the net dependable system capacity totaled 4,980 Mw (generating
capacity of 3,186 Mw, together with firm purchases of 1,794 Mw), which
represented a reserve margin of approximately 25%. 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
1995 net firm system peak demand through the expiration of the contracts:
2
Mw Contracted
For at the Time of the
Generating Summer 1995 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 133 1997
PacifiCorp PacifiCorp Resource 176 2022
Pool
Platte River Power Authority (a) (d) Craig Units 1 and 2; 224 2004
Rawhide Unit 1
Tri-State 425 (e)
Agreements 1, 2, 3 and 4 (a) (e) Laramie River Station
Units 2 and 3;
Craig Units 1, 2 and 3
Agreement 5 (a) (e) 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 593 Various dates
1,726
____________
(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 met 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 summer
season capacity through March 31, 2016 and 25 Mw winter season
capacity through March 31, 2010.
(c) This contract calls for PacifiCorp to sell to Cheyenne the total
electric capacity and energy requirements associated with the
operation of Cheyenne's service area.
(d) The 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.
(e) The Company has entered into five agreements with Tri-State.
Agreements 1, 2, 4 and 5 are contracts for 100 Mw each of capacity
3
and expire in 2001, 2017, 2018 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. The capacity associated
with Agreement 4 escalates to the following amounts in the future:
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 would be as follows from 1999:
1999 - 150 Mw, 2000 -100 Mw, 2001 - 100 Mw, 2002 - 50 Mw and 2003
through 2018 - 0 Mw.
See Note 8. 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 34% of the total electric system energy input for 1995, compared
to approximately 37% in 1994. 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 summer 1995 net firm system peak
demand for the Company and Cheyenne will be provided by purchased power,
compared to approximately 36% in 1994. This decrease is due to the expiration
of a short-term purchase contract with Public Service Company of New Mexico
for 75 Mw. This capacity is no longer required due to the additional 340 Mw
of capacity provided by new QFs in 1994.
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 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 37 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 current CPUC criteria, QFs
could provide up to 20% of the Company's net firm system peak load. In 1994,
approximately 15% of the Company's summer net firm system peak demand was
contracted to be provided by QFs.
In addition to long-term and QF 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 1994.
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.
4
Purchases of capacity and energy do not have a significant effect on the
earnings of the Company because the costs thereof, without mark-up, are billed
to customers through base rates, the ECA and the QFCCA. The CPUC, however,
has established a schedule for reviewing the ECA (see Note 8. Commitments and
Contingencies-Regulatory Matters in Item 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA). Such purchases neither require the Company to make an
investment nor afford the Company an opportunity to earn a return.
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, 1994, the Company and its subsidiaries estimated the
cost of their construction program, including AFDC, in 1995, 1996 and 1997 to
be $323 million, $347 million and $316 million, respectively (see Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS). Included in these estimated costs is $117 million associated
with the conversion of Fort St. Vrain to a 471 Mw gas fired combined cycle
steam plant. The total conversion project cost is approximately $231 million.
A CPCN for the conversion of Fort St. Vrain was approved by the CPUC in July
1994 (see Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA).
Fort St. Vrain
See Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA.
5
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 $
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
1990 . . . . . . . . . . . 1.145 98 2.101 2 1.165
* The average cost per ton of coal, including freight, for years
1994 through 1990 shown above was $20.57, $21.03, $21.14, $22.40
and $21.44, 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, 1994, the Company's coal requirements
for existing plants were approximately 8,502,170 tons, a substantial
portion of which was supplied pursuant to long-term supply contracts.
Coal supply inventories at December 31, 1994 were approximately 52 days
usage, based on the average peak burn rate for all the Company's
coal-fired plants.
6
The following table is a synopsis of the basic supply provisions of
the existing long-term contracts, which provide a minimum delivery of
approximately 92 million tons of low-sulfur coal over their remaining life
(see Note 8. Commitments and Contingencies-Purchase requirements in Item
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ).
Minimum Maximum Contract
delivery delivery maximum
per contract year per contract year sulfur
Coal Supplier and Delivery Year in tons in tons content
_______________________________ ________________ ________________ ________
Amax (1)
1988 through Pawnee 2 completion . . . . . . . 3,960,000 (2) 0.50%
Pawnee 2 completion through 2013 . . . . . . . 3,600,000 (3) 0.50%
Colowyo Coal Company
1992 through 2017 . . . . . . . . . . . . . . . 79,429 (4) 79,429 0.70%
Cyprus Coal Company
1988 through 1997 . . . . . . . . . . . . . . . 1,700,000 1,900,000 0.60%
Mountain Coal Company
1993 through 2000 . . . . . . . . . . . . . . . 600,000 (5) 800,000 0.67%
Powderhorn Coal Company
1992 through 1996 . . . . . . . . . . . . . . . 175,500 214,500 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, 1994, 70,661,607 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 1994 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, 1994,
971,426 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, 1994, 17,311,889 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 1994 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 8. 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
7
The Company uses both firm and interruptible natural gas and standby oil
in combustion turbines and certain boilers. Natural gas used in steam heat
production facilities and as boiler fuel in the Company's Denver area
generating stations and Comanche is purchased primarily from North American
Resources Co. pursuant to a Gas Sales Agreement that went into effect for a
12-month period beginning October 1, 1994. The agreement with North American
Resources Co. provides for firm supplies ranging from 10,000 MMbtu per day
(during the seven month summer season) to 20,000 MMbtu per day (during the
five month heating season), with varying daily purchase obligations by the
Company. Requirements above these levels are secured by purchasing
competitively priced gas from other suppliers on an as-needed basis. Natural
gas supplies for the Valmont and Ft. Lupton power plants are purchased from
various suppliers on an as-needed basis.
Natural Gas Operations
During the period 1990-1994, the PSCo Gas Companies experienced growth
in the number of commercial and residential customers ranging from 1.3% to
2.8% annually. Since 1990, commercial and residential gas volumes sold have
averaged 150.6 Bcf annually, while industrial volumes sold have declined from
3.6 Bcf in 1990 to 0.1 Bcf in 1994. The growth of commercial and residential
sales has been moderate 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 1994, transportation services of the PSCo Gas Companies generated
revenues of $23.5 million compared to $23.2 million in 1993 and $20.6 million
in 1992.
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 1994, the PSCo Gas Companies purchased 132.6 Bcf (at 14.65
pounds per square inch) from 87 suppliers, including the following major
suppliers: Interstate (44.7 Bcf); Associated Natural Gas, Inc. (8.9 Bcf); KN
Energy and affiliates (7.2 Bcf); and Western Gas Resources, Inc. (5.2 Bcf).
In 1994, the average delivered cost per Mcf for the PSCo Gas Companies was
$2.86 compared to $2.82 per Mcf in 1993 and $2.72 per Mcf in 1992.
As indicated above, Interstate was the primary supplier to the PSCo Gas
Companies in 1994. 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 will decline 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.
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 8. Commitments and
Contingencies-Purchase requirements in Item 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA for information regarding the Company's financial
commitments under these contracts.
8
Young Storage
Young Storage, a partnership among Young Gas Storage Company and CIG Gas
Storage Company, each 47.5% general partners, and The City of Colorado Springs
Department of Public Utilities ("Colorado Springs"), a limited partner, is
converting a depleted natural gas field into an underground natural gas
storage facility at a cost of approximately $45 million. The 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. Commercial operations are
expected to begin by mid-1995. 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 Colorado Springs. Young Storage will
be subject to FERC regulation.
In December 1994, the Board of Directors of the Company approved
exercising the option to acquire Young Gas Storage Company's 47.5% general
partnership interest in Young Storage pursuant to the Company's Option For
Purchase and Sale of the Young Gas Storage Company dated August 31, 1993. The
Company expects to exercise this option during the first quarter of 1995
resulting in an investment of approximately $6.5 million.
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 1.7 Bcf for 1994.
WGT
WGT holds a one-third interest ($3.4 million) in the TransColorado
Project. The TransColorado Project is a partnership of WGT and subsidiaries
of KN Energy and Questar Pipeline Company for developing a pipeline to
transport natural gas out of western Colorado and the Rocky Mountain Region
into major western and midwestern markets. The TransColorado Project has been
designed and engineered for a 300 mile pipeline capable of transporting 300
MMcf per day. The partnership is currently marketing the transportation
service to producers in western Colorado and to marketers and local
distribution companies in an effort to gain firm contracts to support the
project. FERC approval was received in October 1994. Construction of the
pipeline is scheduled to begin during 1996, depending upon the success of the
marketing efforts. The Company is currently evaluating the possible
divestiture of its interest in WGT.
WGG
WGG owned and operated natural gas gathering and processing facilities
in Southern Colorado. On August 30, 1994, the Company sold all of its
outstanding common stock of WGG (see Note 3. Divestiture of Nonutility Assets
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 re-evaluating its alternatives related
9
to the disposition of the remaining assets (see Note 3. Divestiture of
Nonutility Assets in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
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, 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. 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.
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 mechanism was revised and a new QFCCA mechanism 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. The
balance in the deferred account on June 30 of each year (including interest if
the balance is negative) is reflected in the ECA over a 12 month period
commencing October 1 of such year. Under the QFCCA, all purchased capacity
costs from new QF projects, not otherwise reflected in base rates, are
recoverable similar to the ECA. While the CPUC approved the QFCCA, recovery
of such costs may be subject to an earnings test, which has not yet been
defined by the CPUC. The OCC has proposed an annual earnings test that may
result in a reduction of QFCCA recoveries to the extent the Company's earnings
are in excess of its 11% authorized rate of return on regulated common equity
granted in the 1993 rate case. Hearings regarding this matter are scheduled
for April 1995.
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
10
basis and differences, including interest, are deferred. The balance in the
deferred account on June 30 of each year (including interest if the balance is
negative) is reflected in the GCA over a 12 month period commencing October 1
of such year.
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.
The CPUC held a prehearing conference on May 24, 1994 for the purpose of
establishing a schedule for reviewing the justness and reasonableness of GCA
and ECA mechanisms used by gas and electric utilities within its jurisdiction
resulting in the opening of an investigatory docket. Open hearings were held
in December 1994. The OCC and the CPUC staff are recommending the elimination
of these cost adjustment mechanisms. The Company is in opposition to the
elimination of these cost adjustment mechanisms and has filed initial
comments, as well as responded to the comments filed by the other parties. On
February 6-7, 1995, as part of an open hearing, the CPUC determined that
proceeding with a generic ECA rulemaking docket was not appropriate. However,
the Company is required to make an individual filing with the CPUC related to
its ECA by September 1, 1995 to assess whether the ECA should be maintained in
its present form, altered or eliminated. Additionally, the CPUC preliminarily
determined that the GCA will continue under current practices. The CPUC staff
will hold informal roundtable discussions for the purpose of clarifying the
review procedures for the GCA.
Incentive Regulation and Demand Side Management
The Company, in 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. On May 5, 1993, the CPUC
approved the programs along with a schedule to be implemented over a three-
year period. Effective July 1, 1993, the Company placed into effect 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.
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 8. Commitments and Contingencies - Regulatory Matters in Item
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
The CPUC has opened a separate docket to investigate issues relating to
the adoption and implementation of incentive regulation, which includes the
concept of decoupling the Company's earnings from sales, and additional DSM
incentives. On February 10, 1994, the parties to this docket filed a
unanimous stipulation and settlement agreement with the CPUC. Provisions of
the stipulation include, among other things, retaining the cost recovery
component of the DSMCA through December 31, 1998, modifying slightly the DSM
11
incentive mechanism for 1994 and 1995 and forming a technical working group to
study and analyze various alternative annual revenue reconciliation mechanisms
and incentive mechanisms for 1996 through 1998, which would replace existing
DSM incentives until another mechanism or regulatory approach is approved by
the CPUC. The stipulation agreement, which includes a procedural schedule to
review the results of all studies and simulations over the next year, was
approved by the CPUC on June 16, 1994. The technical working group will
present to the CPUC a detailed analysis demonstrating the effect of the
various proposed mechanisms by the end of the first quarter of 1995.
1993 Rate Case
On November 26, 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. As part of the final decision, the CPUC adopted the following
significant positions:
. the rejection of the Company's proposed use of a fully forecasted
test year in the establishment of revenue requirements in favor of
an historical test year ended September 30, 1992,
. the adoption of full income tax normalization with a 13-year
amortization of prior flow-through amounts currently
reflected as a regulatory asset on the balance sheet, and
. continued inclusion in rate base of the Pawnee 2 engineering
costs ($18 million) and the investment in Southeast Water
Rights ($28 million), but with an allowed rate of return on
such assets based on the Company's weighted cost of debt and
preferred stock.
The OCC filed in Denver District Court an appeal of the CPUC's decision.
The OCC has claimed that accounting related to a specific income tax issue
results in the overcollection of costs from ratepayers. The Company is in
opposition to the appeal. The Company believes that the resolution of this
appeal will not have a material effect on its financial position or results of
operations.
On August 1, 1994, the Company filed its Phase II testimony. The Phase
II proceedings will address cost allocation issues and specific rate changes
for the various customer classes based on the results of the Phase I hearings
and decision that became effective December 1, 1993. A final CPUC decision on
the Phase II proceedings is expected in late 1995.
IRP - Electric
On October 1, 1993, the Company filed its first IRP pursuant to the
Electric Integrated Resource Planning Rules of the CPUC. The Company's IRP
describes 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 have been identified and described which are intended to reduce the
amount of additional capacity required to be supplied by the Company in the
future. Hearings regarding the Company's and other electric utilities'
specific IRPs were held before the CPUC in April 1994 and an interim order
12
approving the Company's IRP was issued on June 10, 1994. The final order has
not yet been received; however, no changes are expected to result from the
final order. The Company's next IRP is scheduled to be filed with the CPUC on
or about July 1, 1996.
IRP - Gas
In December 1992, the CPUC established a separate docket to consider the
need for a gas IRP. The CPUC has held several pre-hearing conferences and has
determined to conduct roundtable discussions to explore the impacts of the
EPAct and the mandates in the EPAct regarding the consideration by state
regulatory agencies of the adoption of standards for gas integrated resource
planning and conservation incentives, as well as the impact on small
businesses of adopting these standards. These proceedings have been completed
and the CPUC determined there was no need to establish a gas IRP in Colorado.
WPSC
On July 31, 1992, Cheyenne filed a rate case application with the WPSC.
On December 17, 1992, the WPSC issued an order approving a Settlement
Agreement reached between Cheyenne and the Consumer Representative Staff of
the WPSC. The Settlement Agreement provided for a return on equity of 11.66%
which, in addition to new rates, became effective January 1, 1993.
In June 1993, Cheyenne filed gas and electric IRPs with the WPSC
pursuant to the 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.
Environmental Matters
See Note 8. 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.
For the years 1995, 1996 and 1997, the estimated expenditures for
environmental control facilities are $11.3 million, $18.2 million and $26.9
million, respectively. These figures include estimated expenditures to
install SO2 and NOx reduction equipment for the years 1995, 1996 and 1997 of
$4.7 million, $14.1 million and $20.3 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,
which may require the Company to participate in a 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 is expected to be
completed at both units in late 1995.
13
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. Depending upon the outcome of the study, the
participants may need to install emissions control equipment. However, the
type and extent of equipment necessary will not be determined until after the
conclusion of the study.
Installation of a fabric filter dust collector at Pawnee, which was
accelerated as a result of a Consent Decree between the Company, the DOJ, the
EPA and the State of Colorado, was completed in December 1994. The cost of
installing this equipment was approximately $41.6 million.
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 NPDES permits to discharge effluents into various streams
and waters of the State of Colorado for each of its generating stations.
These permits, which have a five-year life, are issued by the CWQCD, but are
subject to review by the EPA. The Company believes it is presently in
compliance with such discharge permits.
Renewed wastewater discharge permits have been issued for: 1) Fort St.
Vrain, effective April 1, 1993; 2) Cherokee, effective July 1, 1994; 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. A permit renewal application was submitted
for the Comanche generating station prior to the expiration of its existing
permit. 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.
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 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 or, generally, what effect future laws or regulations may have
upon the Company's operations.
Competition
Industry Outlook
During 1994, unprecedented change occurred 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 FERC the authority to require utilities to provide non-discriminatory
open access to the transmission grid for purposes of providing wholesale
14
customers with direct access. Additionally, 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.
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. Currently, the Company is
participating in several CPUC dockets that address this change, and it is in
the process of investigating various incentive/performance-based alternative
forms of regulation. However, the Company believes it will continue to be
subject to rate regulation that will allow for the recovery of all of its
deferred costs (see Note 1. Summary of Significant Accounting Policies -
Business and Regulation - Regulatory Assets and Liabilities and Note 8.
Commitments and Contingencies - Regulatory Matters in Item 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA).
Electric
The wholesale electric business faces increasing competition in the
supply of bulk power due to provisions of the EPAct and Federal and state
initiatives with respect to providing open access to utility transmission
systems. The Company does not anticipate that these provisions will have a
material impact on its operations in the near-term. For 1994, 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 8 years. In
addition, since 1992, the Company has had a FERC-approved transmission tariff,
which provides for open access, with certain limitations. During 1994, the
Company was notified by one wholesale customer of its intent to reduce future
firm and peaking power purchases in accordance with current contractual
arrangements. This customer is seeking a CPCN to construct its own generation
facilities to serve its customers' needs. The Company has proposed
alternative power supply arrangements for such customer's consideration.
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-
15
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, 1994. These franchises consist of 69 combined gas and
electric service franchises, 28 electric service franchises and 22 gas service
franchises. The Company is currently providing gas and electric service to
one previously franchised municipality while a new franchise is being
negotiated. 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
The number of employees of the Company and its subsidiaries decreased
from 6,507 at December 31, 1993 to 5,160 at December 31, 1994. The number of
employees covered by collective bargaining agreements at December 31, 1994 was
2,449. The decrease in the number of employees is primarily due to an early
retirement/severance package offered by the Company in 1994 and to an
involuntary severance program implemented as part of the Company's
restructuring activities in 1994. Effective February 13, 1995, approximately
390 positions were outsourced as part of a ten-year agreement with ISSC to
manage most of the Company's information technology systems and network
infrastructure.
Research and Development
The Company and its utility subsidiaries spent approximately $3.8
million in 1994, $4.3 million in 1993 and $4.8 million in 1992 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.
16
Consolidated Electric Operating Statistics
Year Ended December 31,
1994 1993 1992 1991 1990
Energy Generated, Received, & Sold (Thousands of Kwh):
Net Generated:
Steam, Fossil . . . . . . . . . . . . . 15,949,980 15,470,247 14,972,688 13,164,941 13,103,990
Combustion Turbine . . . . . . . . . . . 41,705 39,228 47,194 7,643 5,440
Pumped Storage . . . . . . . . . . . . . 126,721 118,593 79,609 68,988 77,309
Hydro . . . . . . . . . . . . . . . . . 176,264 198,272 175,010 147,686 141,663
Total Net Generation . . . . . . . . 16,294,670 15,826,340 15,274,501 13,389,258 13,328,402
Energy Used for Pumping . . . . . . . . 201,744 185,850 126,266 111,008 124,648
Total Net System Input . . . . . . . 16,092,926 15,640,490 15,148,235 13,278,250 13,203,754
Purchased Power and Net Interchange . . . 9,653,067 9,631,982 8,663,339 8,738,907 8,416,081
Total System Input . . . . . . . . . 25,745,993 25,272,472 23,811,574 22,017,157 21,619,835
Used by Company . . . . . . . . . . . . 66,348 60,396 64,125 71,506 69,461
Other(1) . . . . . . . . . . . . . . . . 1,670,591 2,001,832 1,932,333 1,493,291 1,401,956
Total Energy Sold . . . . . . . . . . 24,009,054 23,210,244 21,815,116 20,452,360 20,148,418
Electric Sales (Thousands of Kwh)(2):
Residential . . . . . . . . . . . . . . 6,119,914 5,969,529 5,747,048 5,699,374 5,552,879
Commercial . . . . . . . . . . . . . . . 8,931,962 10,797,272 10,350,155 10,307,829 10,175,316
Industrial . . . . . . . . . . . . . . . 5,726,837 3,289,501 3,375,638 3,334,405 3,382,450
Public Authorities . . . . . . . . . . . 187,939 186,397 187,500 184,315 185,813
Other Utilities(3) . . . . . . . . . . . 3,042,402 2,967,545 2,154,775 926,437 851,960
Total Energy Sold . . . . . . . . . . 24,009,054 23,210,244 21,815,116 20,452,360 20,148,418
Number of Customers at End of Period(2):
Residential . . . . . . . . . . . . . . 913,582 898,752 894,217 880,676 871,455
Commercial . . . . . . . . . . . . . . . 120,886 120,317 120,198 119,118 118,332
Industrial . . . . . . . . . . . . . . . 384 157 194 179 164
Public Authorities . . . . . . . . . . . 77,842 76,476 647 660 653
Other Utilities(3) . . . . . . . . . . . 18 20 34 29 29
Total Customers . . . . . . . . . . 1,112,712 1,095,722 1,015,290 1,000,662 990,633
Electric Revenues (Thousands of Dollars)(2):
Residential . . . . . . . . . . . . . . $ 453,614 $ 433,521 $ 413,655 $ 403,095 $ 389,935
Commercial . . . . . . . . . . . . . . . 519,340 602,187 572,780 568,588 553,429
Industrial . . . . . . . . . . . . . . . 252,552 142,146 148,951 147,997 146,114
Public Authorities . . . . . . . . . . . 21,950 20,828 20,221 19,256 19,185
Other Utilities (3) . . . . . . . . . . 120,238 116,937 80,290 35,480 32,323
Other Electric Revenues . . . . . . . . 32,142 21,434 24,872 6,085 4,929
Total Electric Revenues . . . . . . . $1,399,836 $1,337,053 $1,260,769 $1,180,501 $ 1,145,915
Average Annual Kwh Sales per Residential Customer 6,770 6,717 6,533 6,563 6,445
Average Annual Revenue per Residential Customer $501.82 $487.81 $470.26 $464.17 $452.59
Average Residential Revenue per Kwh . . . . .0741 .0726 .0720 .0707 .0702
Average Commercial Revenue per Kwh . . . . .0581 .0558 .0553 .0552 .0544
Average Industrial Revenue per Kwh . . . . .0441 .0432 .0441 .0444 .0432
Average Other Utilities Revenue per Kwh . . .0395 .0394 .0373 .0383 .0379
_________________________
(1) Primarily includes net distribution and transmission line losses.
(2) Comparison of energy sales, customers and electric revenues to prior periods is impacted by: 1) a change in
criteria for counting customers resulting from the implementation of a new customer information system during
17
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.
18
Consolidated Gas Operating Statistics
Year Ended December 31,
1994 1993 1992 1991 1990
Natural Gas Purchased and Sold (Thousands of Mcf)(1):
Purchased from Interstate . . . . . . . 53,337 64,494 69,309 68,398 66,739
Purchased from Others . . . . . . . . . 104,102 103,609 92,302 96,358 93,180
Total Purchased . . . . . . . . . . 157,439 168,103 161,611 164,756 159,919
Company Use . . . . . . . . . . . . . . 2,817 2,750 3,041 2,262 1,830
Other(2) . . . . . . . . . . . . . . . . 4,515 (2,111) 7,070 2,628 4,706
Total Gas Sold . . . . . . . . . . . 150,107 167,464 151,500 159,866 153,383
Gas Deliveries (Thousands of Mcf)(1):
Residential . . . . . . . . . . . . . . 92,036 98,350 87,560 91,807 86,622
Commercial . . . . . . . . . . . . . . . 57,366 62,193 57,321 61,266 58,722
Industrial . . . . . . . . . . . . . . . 118 1,097 1,772 2,468 3,604
Public Authorities . . . . . . . . . . . - 88 141 134 130
Other Utilities . . . . . . . . . . . . 587 5,736 4,706 4,191 4,305
Total Gas Sold . . . . . . . . . . . 150,107 167,464 151,500 159,866 153,383
Transported Gas . . . . . . . . . . . . 78,194 71,922 60,404 54,214 46,374
Gathered and Processed Gas . . . . . . . 29,889 42,010 33,052 18,622 11,170
Total Deliveries . . . . . . . . . . 258,190 281,396 244,956 232,702 210,927
Number of Customers at End of Period:
Residential . . . . . . . . . . . . . . 845,464 820,521 808,722 792,646 780,157
Commercial . . . . . . . . . . . . . . . 87,077 86,202 85,954 85,317 84,672
Industrial . . . . . . . . . . . . . . . 26 25 237 331 327
Public Authorities . . . . . . . . . . . - - 1 1 1
Other Utilities . . . . . . . . . . . . 8 8 8 9 9
Total . . . . . . . . . . . . . . . 932,575 906,756 894,922 878,304 865,166
Transported Gas and Other . . . . . . . 786 619 416 275 233
Total Customers . . . . . . . . . . 933,361 907,375 895,338 878,579 865,399
Gas Revenues (Thousands of Dollars):
Residential . . . . . . . . . . . . . . $ 375,406 $ 366,445 $ 329,406 $ 343,692 $ 327,403
Commercial . . . . . . . . . . . . . . . 202,873 201,693 185,851 198,160 190,409
Industrial . . . . . . . . . . . . . . . 438 2,887 5,213 7,765 11,166
Public Authorities . . . . . . . . . . . - 240 302 371 345
Other Utilities . . . . . . . . . . . . 7,319 13,966 10,099 9,198 10,003
Transported Gas . . . . . . . . . . . . 23,495 23,176 20,638 18,966 16,981
Gathered and Processed Gas . . . . . . . 8,335 10,575 8,023 5,465 2,829
Other Gas Revenues . . . . . . . . . . . 7,056 9,342 9,354 3,992 2,576
Total Gas Revenues . . . . . . . . . $ 624,922 $ 628,324 $ 568,886 $ 587,609 $ 561,712
Average Annual Mcf Sales per Residential Customer 110.59 120.85 109.5 116.8 112.0
Average Annual Revenue per Residential Customer $451.09 $450.29 $411.94 $437.40 $419.66
Average Residential Revenue per Mcf . . . . $4.079 $3.726 $3.762 $3.744 $3.780
Average Commercial Revenue per Mcf . . . . $3.536 $3.243 $3.242 $3.234 $3.243
Average Industrial Revenue per Mcf . . . . $3.716 $2.631 $2.942 $3.146 $3.098
Average Transport Gas Revenue per Mcf . . . $0.300 $0.322 $0.342 $0.350 $0.366
_________________________
(1) Volumes are reported at local pressure base.
(2) Primarily includes distribution and transmission line losses and net changes to gas in storage.
19
Electric Transmission Map
This page is a map of Colorado showing the Company's electric
transmission interconnected system.
20
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 1995 net firm
system peak demand during the summer season are as follows:
Net Dependable
Capacity
Installed (Mw)
Gross at Time of Major
Name of Station Capacity 1995 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 . . . . . . . . . . . . . . 86.89 (a) 83.20 Coal
Hayden-near Hayden . . . . . . . . . . . . . 259.47 (b) 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 . . . . . . . . . . . . . . . . . . 3,027.36 2,801.80
Combustion turbines (6 units-various locations) . 209.00 171.00 Gas
Hydro (14 units-various locations) (c) . . . . . 52.70 35.90 (d) Hydro
Cabin Creek Pumped Storage-near Georgetown . . . 324.00 (e) 162.00 Hydro
Diesel generators (7 units-various locations) . . 15.50 15.50 Oil
__________ __________
Total . . . . . . . . . . . . . . . . . . . 3,628.56 3,186.20
________________
* A measure of the unit capability planned to be available at the time of the system peak load net of seasonal
reductions in unit capability due to weather, stream flow, fuel availability and station housepower, including
requirements for air and water quality control equipment.
(a) The gross maximum capability of Craig Units No. 1 and No. 2 is 894 Mw, of which the Company has a 9.72% undivided
ownership interest.
(b) The gross maximum capability of Hayden Units No. 1 and No. 2 is 202.01 Mw and 285.96 Mw, respectively, of which
the Company has a 75.5% and 37.4% undivided ownership interest, respectively.
(c) Includes one station (two units) not owned by the Company but operated under contract.
(d) Seasonal Hydro Plant net dependable capabilities are based upon average water conditions and limitations for each
particular season. The individual plant seasonal capabilities are sometimes limited by less than design water
flow.
(e) Capability at maximum load.
21
Nuclear Property
Fort St. Vrain, near Platteville, the Company's only nuclear
generating station, ceased operations on August 29, 1989 (see Note 2.
Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
Transmission and Distribution Property
On December 31, 1994, the Company's transmission system consisted of
approximately 182 circuit miles of 345 Kv overhead lines; 1,832 circuit
miles of 230 Kv overhead lines; 15 circuit miles of 230 Kv underground
lines; 65 circuit miles of 138 Kv overhead lines; 965 circuit miles of 115
Kv overhead lines; 19 circuit miles of 115 Kv underground lines; 355
circuit miles of 69 Kv overhead lines; 170 circuit miles of 44 Kv overhead
lines; and 1 circuit mile of 44 Kv underground lines. The Company jointly
owns with another utility approximately 347 circuit miles of 345 Kv
overhead lines and 330 miles of 230 Kv overhead lines, of which the
Company's share is 182 miles and 114 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, 1994, the distribution systems consisted primarily of
approximately 12,887 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 7,389 cable miles of underground distribution system
(excluding street lighting) located principally in the Denver metropolitan
area. The Company owned 214 substations (four of which are jointly owned)
having an aggregate transformer capacity of 18,179,300 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, 1994 consisted chiefly
of approximately 14,619 miles of distribution mains ranging in size from 0.50
to 30 inches and related equipment. The Denver distribution system consisted
22
of 8,100 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, 1994 consisted of
10.5 miles of transmission, distribution and service lines in the 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 3. Divestiture of Nonutility Assets
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 office buildings in Denver 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.
23
Item 3. Legal Proceedings
See Note 2. Fort St. Vrain and Note 8. Commitments and Contingencies in
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Item 4. Submission of Matters to a Vote of Security Holders
Does not apply.
24
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
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
1993
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . $ .50 $ 30 1/4 $ 27 1/2
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . .50 33 1/4 28 1/2
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . .50 33 3/8 31
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . .50 32 7/8 28
$ 2.00
At December 31, 1994, the book value of the common stock was $20.39
per share. At February 24, 1995, there were 64,366 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 various
uncertainties, including those associated with the eventual resolution of
Fort St. Vrain decommissioning issues. 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.
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 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).
25
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 set forth as
Exhibit 1 to the Company's Form 8-A filed with the SEC on March 1, 1991,
which is incorporated herein by reference.
26
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, 1994 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,
1994 1993 1992 1991 1990
(In Thousands-except per share data & ratios)
Operating revenues:
Electric . . . . . . . . . . . . . . . . $1,399,836 $1,337,053 $1,260,769 $1,180,501 $ 1,145,915
Gas . . . . . . . . . . . . . . . . . . 624,922 628,324 568,886 587,609 561,712
Other . . . . . . . . . . . . . . . . . 32,626 33,308 32,618 26,794 26,312
Total . . . . . . . . . . . . . . . . 2,057,384 1,998,685 1,862,273 1,794,904 1,733,939
Total operating expenses . . . . . . . . . 1,786,592 1,717,752 1,612,646 1,551,326 1,495,533
Operating income . . . . . . . . . . . . . 270,792 280,933 249,627 243,578 238,406
Total interest charges . . . . . . . . . . 132,134 130,337 121,116 101,537 97,296
Net income . . . . . . . . . . . . . . . . 170,269 157,360 136,623 149,693 146,144
Dividend requirements on preferred stock: . 12,014 12,031 12,077 12,234 12,439
Earnings available for common stock: . . . 158,255 145,329 124,546 137,459 133,705
Per share data applicable to common stock (a):
Earnings . . . . . . . . . . . . . . . . $ 2.57 $ 2.43 $ 2.16 $ 2.48 $ 2.49
Dividends declared . . . . . . . . . . . $ 2.00 $ 2.00 $ 2.00 $ 2.00 $ 2.00
Shares of common stock outstanding:
Weighted average . . . . . . . . . . . . 61,547 59,695 57,558 55,471 53,626
Year-end . . . . . . . . . . . . . . . . 62,155 60,457 58,477 56,294 54,320
Rate of return earned on average common equity
(net to common) . . . . . . . . . . . . 12.9% 12.7% 11.7% 13.8% 14.3%
Ratio of earnings to
fixed charges (b) . . . . . . . . . . . 2.53 2.54 2.43 2.94 3.07
Total assets . . . . . . . . . . . . . . . $4,207,832 $4,057,600 $3,759,583 $3,462,668 $ 3,233,840
Total net plant . . . . . . . . . . . . . . 3,291,402 3,193,136 3,077,509 2,745,800 2,609,261
Total construction expenditures . . . . . . 317,138 293,515 261,666 260,704 261,221
AFDC . . . . . . . . . . . . . . . . . . 7,158 12,667 11,302 9,437 6,715
Cash generated internally as a percent of
construction expenditures (c) . . . . . 35.4% 52.2% 57.5% 69.4% 67.6%
Total common equity . . . . . . . . . . . . $1,267,482 $1,184,183 $1,101,047 $1,034,433 $ 963,663
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) 45,241 45,454 45,654 46,368 48,944
Long-term debt (including amounts due within one year) 1,180,580 1,193,668 1,199,779 993,965 938,264
Notes payable & commercial paper . . . . . 324,800 276,875 250,626 200,640 213,833
_________________________
(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.
27
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Industry Outlook
During 1994, unprecedented change occurred 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 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.
Additionally, an increasing number of states recently have begun to
evaluate or pursue regulatory reform in an effort to proactively respond
to this changing business environment.
The presence of competition and the associated pressure on prices
ultimately may 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.
Corporate Overview
While the Company continues to pursue the overall long-term strategy
of focusing on its core electric and natural gas businesses, during 1994,
several short-term strategies, primarily designed to lower operating
costs, were implemented to better position the Company to more effectively
operate in a competitive environment. Initially, an early
retirement/severance program was offered with approximately 550 employees
electing to participate. Annual salary savings are estimated to be
approximately $22 million. Total program costs, of approximately $39.7
million, are being amortized over 4.5 years, which is the remaining
average estimated service life of the program participants.
Following the early retirement/severance program, the Company
restructured internally, consistent with an anticipated unbundled business
approach, in order to more effectively address customers' needs. In
conjunction with the internal restructuring, an involuntary severance
program was implemented. Approximately 550 management and staff level
positions were eliminated, resulting in an additional estimated annual
salary savings of $21 million. Involuntary severance costs of
approximately $10.7 million were recognized, of which $8.7 million served
to reduce pre-tax earnings. Additionally, in conjunction with the
internal restructuring process, 32 customer offices were closed in support
of the overall cost-containment effort.
As part of an effort to expand the Company's markets by providing
value-added services, in January 1995, the Company and IBM formed an
alliance to develop advanced customer service and energy management
28
applications for utility and energy-using customers. In particular, a
subsidiary of IBM, ISSC, and the Company's new subsidiary, e prime, will
develop and deliver new information technology-based applications to
assist utilities and others across the country to provide more responsive
and efficient customer service. IBM has committed to use the services of
e prime, thus becoming its first customer. Also as part of the alliance,
ISSC, under a ten-year agreement, will manage most of the Company's
information technology systems and network infrastructure, resulting in
the outsourcing of approximately 390 positions, effective February 13,
1995. Such arrangement is expected to result in an estimated $190 million
savings to the Company during the ten-year period.
In spite of having to recognize an additional $43.4 million in costs
primarily associated with the decommissioning of Fort St. Vrain in 1994,
important milestones were achieved with the repowering and decommissioning
activities. In July 1994, the CPUC approved a CPCN allowing the Company
to repower the facility in a phased approach. The first phase is expected
to be completed in 1996. Additionally, on January 26, 1995, the Company
received NRC approval of its Final Survey Plan for Site Release, reducing
the future uncertainty related to the completion of the decommissioning
project. Decommissioning work is approximately 67% complete at December
31, 1994.
Also supporting the Company's strategy of focusing on its core
electric and gas businesses, in August 1994, the Company sold all of the
outstanding common stock of WGG and certain related operating assets for
$87 million, resulting in a gain of approximately $34.5 million.
In response to the increasingly competitive operating environment
for utilities, the regulatory climate also is changing. Currently, the
Company is participating in several CPUC dockets that address this change,
and it is in the process of investigating various incentive/performance-
based alternative forms of regulation. However, the Company believes it
will continue to be subject to rate regulation that will allow for the
recovery of all of its deferred costs.
Earnings
Earnings per share were $2.57, $2.43 and $2.16 during 1994, 1993 and
1992, respectively. The increase in 1994 earnings was primarily due to
the gain on the sale of WGG, as discussed above, and higher electricity
sales. Furthermore, during 1994, the Company recognized additional
defueling and decommissioning costs associated with Fort St. Vrain and a
favorable income tax accrual adjustment following a complete analysis of
the Company's income tax liabilities associated with the adoption of full
normalization. The lower earnings for 1992 reflect charges related to the
divestiture of certain of the Company's nonutility assets.
29
Electric Operations
The following table details the annual change in electric revenues
and energy costs as compared to the preceding year:
Increase (Decrease)
From Prior Years
1994 1993
(Thousands of Dollars)
Electric revenues:
Retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 48,774 $ 43,075
Wholesale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,301 36,647
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,708 (3,438)
Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62,783 76,284
Fuel used in generation . . . . . . . . . . . . . . . . . . . . . . . . . . 3,200 12,086
Purchased power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40,134 30,004
Net increase in electric margin . . . . . . . . . . . . . . . . . . . . . $ 19,449 $ 34,194
Electric operating revenues increased in 1994 and 1993, when
compared to the respective prior year, primarily due to favorable weather,
moderate customer growth and additional revenues related to the collection
of decommissioning, DSM and QF purchased power capacity costs. The
increase in 1993 also includes the full-year effect of the April 1992
addition of four new wholesale customers. Warmer weather during the
summer months was the primary factor that contributed to 3.4% and 6.4%
increases in electricity sales in 1994 and 1993, respectively. Based on
weather comparisons, it was 74% warmer than normal in 1994 and 18% warmer
than normal in 1993.
Base rates are changed only through rate proceedings with 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.
Concurrently, all of the Company's QF capacity costs, previously recovered
through the ECA, became recoverable under the QFCCA. However, the
recovery of costs under the QFCCA may be subject to an earnings test,
which has not yet been defined by the CPUC (see Note 8. Commitments and
Contingencies - Regulatory Matters in Item 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA). 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 and allow recovery of such costs on a
timely basis. As a result, the changes in revenues associated with these
mechanisms in 1994, 1993 and 1992 had little impact on net income.
Purchased power expense increased 10.1% in 1994 and 8.2% in 1993,
primarily due to increased purchases from QFs. Fuel used in generation
expense increased 1.6% in 1994 and 6.6% in 1993, primarily due to higher
generation levels. The higher generation levels in 1993 were
predominantly due to the April 1992 purchase of 331 Mw of additional
generating capacity.
30
Gas Operations
The following table details the annual change in gas revenues and gas
purchased for resale as compared to the preceding year:
Increase (Decrease)
From Prior Years
1994 1993
(Thousands of Dollars)
Total gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (3,402) $ 59,438
Less: transport, gathering, and processing revenues . . . . . . . . . . . . (1,921) 5,090
Revenues from gas sales . . . . . . . . . . . . . . . . . . . . . . . . . (1,481) 54,348
Gas purchased for resale . . . . . . . . . . . . . . . . . . . . . . . . . 13,484 41,205
Net (decrease) increase in gas sales margin . . . . . . . . . . . . . . . $ (14,965) $ 13,143
Gas operating revenues declined in 1994 and increased in 1993,
primarily due to changes in total gas deliveries resulting from weather
variations. There were approximately 16% fewer heating degree days in
1994, as compared to 1993, and approximately 10% more heating degree days
in 1993 as compared to 1992. The base rate increase, effective December
1, 1993 (as discussed above), and moderate customer growth mitigated some
of the effects of the lower gas deliveries in 1994.
Total gas deliveries decreased 8.2% in 1994 as a result of lower
retail gas sales and the disposition of Fuelco assets, offset by higher
transport deliveries. The growth in transportation services is primarily
due to serving two new QF customers. Total gas deliveries increased 14.9%
in 1993, due to colder weather and growth in the transport services as
industrial customers have procured their own gas supplies. 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.
However, they will have a positive impact on operating margin.
The Company and its regulated subsidiaries 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 1994 and 1993,
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 increase in gas purchased for resale for 1994 reflects the higher
price of gas purchased from major suppliers. The increase in gas
purchased for resale in 1993 is primarily due to higher gas sales, as well
as a slight increase in the per-unit cost of gas.
Non-Fuel Operating Expenses
The Company recognized additional expenses aggregating approximately
$43.4 million for increased costs associated with the defueling and
decommissioning of Fort St. Vrain, as well as the impairment of certain
related property and inventory. The additional expense is primarily
associated with radiation levels in the reactor core being higher than
originally anticipated and increased uncertainty related to spent fuel
31
disposal issues (see Note 2. Fort St. Vrain in Item 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA).
Other operating and maintenance expenses decreased $16.7 million for
1994 compared to 1993, primarily due to lower labor costs resulting from
the early retirement/severance program that was completed April 1, 1994,
decreased maintenance expenses at the Company's steam generating plants
and lower costs due to the ending of Fuelco operations. These decreases
have been offset, in part, by increased OPEB costs and the severance costs
associated with the Company's involuntary workforce reductions. The $34.0
million increase in other operating and maintenance expenses in 1993, when
compared to 1992, is primarily due to increased labor and benefits costs.
Other non-fuel operating expenses in 1992 included the recognition of
charges to earnings associated with the Synhytech and BCC transactions of
approximately $26.9 million and $11.4 million, respectively.
Depreciation and amortization expense decreased in 1994, when
compared to 1993, primarily due to the effects of using a CPUC-approved
longer estimated depreciable life of the Company's electric steam
production facilities. Higher 1993 depreciation expense reflects
additional assets acquired from Colorado-Ute and other property additions.
The 1994 and 1993 depreciation and amortization expense also include the
amortization of the decommissioning regulatory asset associated with Fort
St. Vrain, which became effective July 1, 1993, along with the collection
of such costs.
The decrease in income tax expense for 1994 includes a $21.3 million
adjustment to the income tax liabilities as a result of a detailed
analysis of the Company's income tax liabilities in conjunction with the
Company's implementation of the full normalization method of accounting
for income taxes which was provided for in a recent CPUC rate order. The
increase in 1993 income tax expense, when compared to 1992, reflects a 1%
increase in the Federal tax rate and higher pre-tax income offset by the
$1.9 million benefit realized from the adoption of SFAS 109.
Other income and deductions increased $24.8 million in 1994,
primarily due to the approximately $34.5 million gain on the sale of WGG.
This gain was offset, in part, by lower AFDC and the $3.0 million reversal
of the 1991 gas search award as the Colorado Supreme Court reversed the
incentive award previously granted by the CPUC.
Interest charges increased $1.8 million in 1994 as compared to 1993.
Interest on long-term debt, net of amortization costs, decreased $8.0
million in 1994 because the Company refinanced certain long-term debt
issues with lower-cost debt. However, this decrease was more than offset
by a $9.2 million increase in other interest, primarily due to increased
levels of short-term borrowings in 1994, compared to 1993. Interest
charges increased $9.2 million in 1993, compared to 1992. This was
primarily due to higher interest on long-term debt, reflecting the
issuance of $250 million in First Mortgage Bonds in April 1992, to finance
the Colorado-Ute asset acquisition, as well as the issuance of $50 million
in medium-term notes.
Commitments and Contingencies
Issues relating to Fort St. Vrain, regulatory and environmental
matters are discussed in Notes 2 and 8 in Item 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA.
On November 26, 1993, the CPUC issued its final decision in
connection with the 1993 rate case denying the Company any rate relief and
32
lowering the Company's overall revenue requirements by approximately $5.2
million. The Company is implementing strategies which include reductions
in operating expenses, at a minimum, to the historic test period level.
It is possible, however, that despite such efforts, the Company could be
required to issue increasing amounts of short-term and long-term
securities to fund cash requirements. It is also possible that the
Company's results of operations and financial position could be adversely
affected over time.
The Company's common stock dividend level is dependent upon the
Company's results of operations, financial position and other factors. It
will continue to be evaluated quarterly by the Board of Directors. The
Company is subject to various uncertainties, including those associated
with eventual resolution of Fort St. Vrain decommissioning issues.
Liquidity and Capital Resources
Cash Flows
Cash provided by operating activities decreased $34.2 million for
1994, primarily due to the non-cash impact of the tax accrual adjustment.
Cash provided by operations increased $7.1 million during 1993, when
compared to 1992, primarily due to increased earnings and higher
depreciation and amortization related to property additions, including the
acquisition of the Colorado-Ute assets. Although the Company collected
approximately $14 million and $6 million in 1994 and 1993, respectively,
for the decommissioning of Fort St. Vrain, significant expenditures
associated with this project will continue to reduce operating cash flows
through 1996.
Cash used in investing activities decreased $61.9 million for 1994,
primarily due to the 1994 sale of WGG. This decrease was offset, in part,
by increased construction expenditures. Cash used in investing activities
decreased $192.6 million for 1993, primarily due to the 1992 acquisition
of Colorado-Ute assets. In addition, in 1993 three new wholesale
customers prepaid 100%, or approximately $24.9 million, of a twenty-five
year surcharge associated with the Colorado-Ute acquisition. In comparing
1993 to 1992, however, this was offset by the 1992 receipt of
approximately $75 million in loan proceeds from insurance policies held by
one of the Company's subsidiaries.
Cash used in financing activities increased approximately $6.8
million in 1994, primarily due to increased repayments of long-term debt,
decreased proceeds from the sale of common stock and increased dividends,
offset by higher short-term borrowings. Cash provided by financing
activities decreased approximately $247.7 million during 1993, primarily
due to the 1992 issuance of $250 million in First Mortgage Bonds related
to the acquisition of the Colorado-Ute assets.
33
Prospective Capital Requirements and Sources
At December 31, 1994, the Company and its subsidiaries estimated the
cost of their construction programs, including AFDC and other capital
requirements, in 1995, 1996 and 1997 to be as follows:
1995 1996 1997
(Thousands of Dollars)
Company:
Electric
Production* . . . . . . . . . . . . . . . . . . $92,500 $111,312 $130,172
Transmission . . . . . . . . . . . . . . . . . . 13,015 33,110 15,699
Distribution . . . . . . . . . . . . . . . . . . 74,037 80,626 83,693
Gas . . . . . . . . . . . . . . . . . . . . . . . . 77,949 69,663 41,600
General** . . . . . . . . . . . . . . . . . . . . . . 58,514 44,710 40,878
Subtotal . . . . . . . . . . . . . . . . . . . 316,015 339,421 312,042
Subsidiaries . . . . . . . . . . . . . . . . . . . . 6,688 7,437 3,538
Total construction . . . . . . . . . . . . . . 322,703 346,858 315,580
Less: AFDC . . . . . . . . . . . . . . . . . . . . . 6,645 5,020 3,410
Add: Sinking funds and debt maturities . . . . . . . 43,188 86,451 78,948
Add: Fort St. Vrain Decommissioning . . . . . . . . . 33,243 13,962 0
Total capital requirements . . . . . . . . . . . $392,489 $442,251 $391,118
* Capital requirements for Electric Production include $117 million for Fort St. Vrain repowering (see Note 2.
Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
** Capital requirements for the "General" category include assets leased under a
leasing program.
The construction programs of the Company and its subsidiaries are
subject to continuing review and adjustment. In particular, actual
construction expenditures for the electric system may vary from the
estimates due to changes in 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,
actual decommissioning and defueling expenses may exceed the estimates,
due to a variety of factors discussed in Note 2. Fort St. Vrain in Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
Additionally, the Company evaluates merger, acquisition and
divestiture opportunities on an ongoing basis to support the Company's
corporate strategies.
At December 31, 1994, the Company and its subsidiaries estimated
that their 1995-1997 capital requirements would 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 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.
The Company's Automatic Dividend Reinvestment and Common Stock
Purchase Plan allows its shareholders to purchase additional shares of the
34
Company's common stock through the reinvestment of cash dividends and the
purchase of additional shares of common stock with optional cash payments.
The proceeds from the dividend reinvestment plan also will provide funds
to help meet the capital requirements of the Company.
At December 31, 1994, the Company and its subsidiaries had temporary
cash investments of $3.5 million.
As of December 31, 1994, PSCCC had borrowed $167.5 million in
short-term debt, for use primarily in the purchase of the Company's
customer accounts receivable and fossil fuel inventories. PSCCC may
periodically convert short-term debt to medium-term notes. As of December
31, 1994, PSCCC had no medium-term notes outstanding. 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. The Company expects that the amount of financing
associated with PSCCC 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.
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, 1994, $169.5 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 million 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 million 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 has 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, 1994, the amount of net
additions, as of December 31, 1993, would permit (and the net earnings
test would not prohibit) the issuance of approximately $98 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
8.9%. At January 31, 1995, the amount of retired bonds would permit the
issuance of $889 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
35
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, 1994, coverage under the net earnings test was in excess of 5
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,
1994, 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 $1.7 billion of additional preferred
stock at an assumed annual dividend rate of 8.25%. Coverage of gross
income to interest charges was 4.5 at December 31, 1994.
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, 1994, the Company had
outstanding unsecured indebtedness, including subsidiary indebtedness with
the credit support of the Company, in the amount of $157.4 million. The
maximum amount permitted under this limitation was approximately $383.9
million at December 31, 1994.
At December 31, 1994, the Company and certain of its subsidiaries
had arrangements for bank lines of credit totaling $300 million in
committed lines, of which $41.2 million was then available. On January 3,
1994, the Company established uncommitted lines of credit totaling $25
million which were increased throughout the year to $75 million. The
amount of unused uncommitted bank lines of credit at December 31, 1994 was
$9.0 million. These uncommitted lines of credit were renewed on December
31, 1994 and expire on December 31, 1995. The Company could generally
borrow under the uncommitted pre-approved lines of credit upon request;
however, the banks have no firm commitment to make such loans.
On November 22, 1994, the Company, PSCCC and certain subsidiaries
extended a credit facility with several banks providing $300 million in
committed bank lines of credit. The credit facility, which is used
primarily to support the issuance of commercial paper by the Company and
PSCCC, alternatively provides for direct borrowing thereunder. Under the
current extension, Cheyenne, 1480 Welton, Inc., Fuelco and PSRI are
provided access to the credit facility with direct borrowings guaranteed
by the Company. 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.
The credit facility expires November 21, 1995. The Company expects to
seek renewal of the credit facility at that time (see Note 7. Bank Lines
36
of Credit and Compensating Bank Balances in Item 8. FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA).
37
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, 1994 and 1993, and the related consolidated statements of
income, shareholders' equity and cash flows for each of the three years in
the period ended December 31, 1994. 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, 1994 and 1993, and
the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1994, in conformity with generally
accepted accounting principles.
As more fully discussed in Note 2 to the consolidated financial
statements, the adequacy of the Company's recorded liability for defueling
and decommissioning its Fort St. Vrain Nuclear Generating Station
(approximately $77.0 million at December 31, 1994) is primarily dependent
on assurances that the dismantlement and decommissioning of the Fort St.
Vrain Nuclear Generating Station can be accomplished at currently
estimated costs and that the spent fuel storage and shipment issues are
successfully resolved. The outcome of the above issues cannot be
determined at this time. The accompanying consolidated financial
statements do not include any adjustments that might result from the
outcome of these uncertainties.
As more fully discussed in Notes 10 and 12 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 audit was 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 audit 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
38
statements taken as a whole.
We have also audited, in accordance with generally accepted auditing
standards, the consolidated balance sheets as of December 31, 1992, 1991
and 1990 and the related consolidated statements of income, shareholders'
equity and cash flows for each of the two years in the period ended
December 31, 1991, (none of which are presented herein) and have expressed
an opinion, which makes reference to uncertainties related to the
Company's Fort St. Vrain Nuclear Generating Station, 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,
1994 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.
Denver, Colorado ARTHUR ANDERSEN LLP
February 10, 1995
39
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
December 31, 1994 and 1993
ASSETS
1994 1993
Property, plant and equipment, at cost:
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . $3,641,711 $3,466,627
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 867,239 929,718
Steam and other . . . . . . . . . . . . . . . . . . . . . . . 86,458 75,288
Common to all departments . . . . . . . . . . . . . . . . . . 369,070 356,633
Construction in progress . . . . . . . . . . . . . . . . . . 187,577 181,802
5,152,055 5,010,068
Less: accumulated depreciation . . . . . . . . . . . . . . . 1,860,653 1,816,927
Total property, plant and equipment . . . . . . . . . . . . 3,291,402 3,193,141
Investments, at cost . . . . . . . . . . . . . . . . . . . . . . 18,202 18,487
Current assets:
Cash and temporary cash investments . . . . . . . . . . . . . 5,883 18,038
Accounts receivable, less reserve for uncollectible accounts ($3,173 at December
31, 1994; $3,276 at December 31, 1993) (Schedule II) . . . 163,465 149,637
Accrued unbilled revenues (Note 1) . . . . . . . . . . . . . 86,106 76,983
Recoverable purchased gas and electric energy costs - net (Note 1) 37,979 60,692
Materials and supplies, at average cost . . . . . . . . . . . 67,600 77,732
Fuel inventory, at average cost . . . . . . . . . . . . . . . 31,370 35,484
Gas in underground storage, at cost (LIFO) . . . . . . . . . 42,355 41,130
Current portion of accumulated deferred income taxes (Note 12) 20,709 4,201
Regulatory assets recoverable within one year (Note 1) . . . 39,985 20,891
Prepaid expenses and other . . . . . . . . . . . . . . . . . 16,312 13,580
Total current assets . . . . . . . . . . . . . . . . . . . . 511,764 498,368
Deferred charges:
Regulatory assets (Note 1) . . . . . . . . . . . . . . . . . 335,893 285,061
Unamortized debt expense . . . . . . . . . . . . . . . . . . 11,073 10,378
Pension benefits (Note 10) . . . . . . . . . . . . . . . . . 1,031 23,149
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38,467 29,016
Total deferred charges . . . . . . . . . . . . . . . . . . . 386,464 347,604
$4,207,832 $4,057,600
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
40
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
December 31, 1994 and 1993
CAPITAL AND LIABILITIES
1994 1993
Common stock (Note 4) . . . . . . . . . . . . . . . . . . . . . . $ 959,268 $ 910,848
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . 308,214 273,335
Total common equity . . . . . . . . . . . . . . . . . . . . 1,267,482 1,184,183
Preferred stock (Note 4):
Not subject to mandatory redemption . . . . . . . . . . . . . 140,008 140,008
Subject to mandatory redemption at par . . . . . . . . . . . 42,665 42,878
Long-term debt (Note 5) . . . . . . . . . . . . . . . . . . . . . 1,155,427 1,135,344
2,605,582 2,502,413
Noncurrent liabilities:
Defueling and decommissioning liability (Note 2) . . . . . . 40,605 45,220
Employees' postretirement benefits other than pensions (Note 10) 42,106 28,145
Employees' postemployment benefits (Note 10) . . . . . . . . 20,975 -
Total noncurrent liabilities . . . . . . . . . . . . . . . . 103,686 73,365
Current liabilities:
Notes payable and commercial paper (Note 6) . . . . . . . . . 324,800 276,875
Long-term debt due within one year . . . . . . . . . . . . . 25,153 58,324
Preferred stock subject to mandatory redemption within one year (Note 4) 2,576 2,576
Accounts payable . . . . . . . . . . . . . . . . . . . . . . 177,031 214,599
Dividends payable . . . . . . . . . . . . . . . . . . . . . . 34,078 33,234
Customers' deposits . . . . . . . . . . . . . . . . . . . . . 17,099 16,225
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . . . 54,148 70,796
Accrued interest . . . . . . . . . . . . . . . . . . . . . . 32,265 29,507
Current portion of defueling and decommissioning liability (Note 2) 36,365 47,887
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62,640 64,664
Total current liabilities . . . . . . . . . . . . . . . . . 766,155 814,687
Deferred credits:
Customers' advances for construction . . . . . . . . . . . . 96,442 76,204
Unamortized investment tax credits . . . . . . . . . . . . . 118,532 124,331
Accumulated deferred income taxes (Note 12) . . . . . . . . 485,668 445,530
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31,767 21,070
Total deferred credits . . . . . . . . . . . . . . . . . . . 732,409 667,135
Commitments and contingencies (Notes 2 and 8) . . . . . . . . . .
$4,207,832 $4,057,600
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
41
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars Except per Share Data)
Years ended December 31, 1994, 1993 and 1992
1994 1993 1992
Operating revenues:
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . $1,399,836 $1,337,053 $1,260,769
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 624,922 628,324 568,886
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,626 33,308 32,618
2,057,384 1,998,685 1,862,273
Operating expenses:
Fuel used in generation . . . . . . . . . . . . . . . . . . . 198,118 194,918 182,832
Purchased power . . . . . . . . . . . . . . . . . . . . . . . 437,087 396,953 366,949
Gas purchased for resale . . . . . . . . . . . . . . . . . . 397,877 384,393 343,188
Other operating expenses . . . . . . . . . . . . . . . . . . 369,094 376,686 346,368
Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . 67,097 76,229 72,540
Defueling and decommissioning (Note 2) . . . . . . . . . . . 43,376 - -
Termination of Synhytech project (Note 3) . . . . . . . . . . - - 26,893
Loss on sale of real estate investments (Note 3) . . . . . . - - 11,370
Depreciation and amortization . . . . . . . . . . . . . . . . 139,035 140,804 127,317
Taxes (other than income taxes) . . . . . . . . . . . . . . 86,408 86,775 82,040
Income taxes (Note 12) . . . . . . . . . . . . . . . . . . . 48,500 60,994 53,149
1,786,592 1,717,752 1,612,646
Operating income . . . . . . . . . . . . . . . . . . . . . . . . 270,792 280,933 249,627
Other income and deductions:
Allowance for equity funds used during construction . . . . . 3,140 8,119 7,378
Miscellaneous income and deductions - net (Note 3) . . . . . 28,471 (1,355) 734
302,403 287,697 257,739
Interest charges:
Interest on long-term debt . . . . . . . . . . . . . . . . . 89,005 98,089 92,581
Amortization of debt discount and expense less premium . . . 3,126 2,018 1,790
Other interest . . . . . . . . . . . . . . . . . . . . . . . 44,021 34,778 30,669
Allowance for borrowed funds used during construction . . . . (4,018) (4,548) (3,924)
132,134 130,337 121,116
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . 170,269 157,360 136,623
Dividend requirements on preferred stock . . . . . . . . . . . . 12,014 12,031 12,077
Earnings available for common stock . . . . . . . . . . . . . . . $ 158,255 $ 145,329 $ 124,546
Shares of common stock outstanding (thousands):
Year-end . . . . . . . . . . . . . . . . . . . . . . . . . . 62,155 60,457 58,477
Weighted average . . . . . . . . . . . . . . . . . . . . . . 61,547 59,695 57,558
Earnings per weighted average share of common stock outstanding . $2.57 $2.43 $2.16
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
42
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(Thousands of Dollars, Except Share Information)
Years ended December 31, 1994, 1993 and 1992
Common Stock, $5 par value Premium on Retained
Shares Amount Common Stock Earnings Total
Balance at January 1, 1992 . . . . . 56,293,525 $ 281,468 $ 514,250 $ 238,715 $1,034,433
Net Income . . . . . . . . . . . . . - - - 136,623 136,623
Dividends Declared
Common Stock, $2.00 per share . . . - - - (115,546) (115,546)
Preferred Stock, $100 par value . . - - - (9,127) (9,127)
Preferred Stock, $25 par value . . - - - (2,940) (2,940)
Issuance of Common Stock
Employees' Savings Plan . . . . . . 333,418 1,667 7,022 - 8,689
Dividend Reinvestment Plan . . . . 1,849,862 9,249 39,666 - 48,915
Balance at December 31, 1992 . . . . 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
Authorized shares of common stock were 160 million and 140 million at December 31, 1994 and 1993, respectively.
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
43
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
Years ended December 31, 1994, 1993 and 1992
1994 1993 1992
Operating activities:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . $ 170,269 $ 157,360 $ 136,623
Adjustments to reconcile net income to net
cash provided by operating activities (Note 1):
Depreciation and amortization . . . . . . . . . . . . . . 142,843 143,940 134,335
Defueling and decommissioning expenses . . . . . . . . . . 43,376 - -
Gain on sale of WGG . . . . . . . . . . . . . . . . . . . (34,485) - -
Termination of Synhytech project . . . . . . . . . . . . . - - 26,893
Loss on sale of real estate investments . . . . . . . . . - - 11,370
Amortization of investment tax credits . . . . . . . . . . (5,799) (4,917) (5,138)
Deferred income taxes . . . . . . . . . . . . . . . . . . 34,234 33,435 23,766
Allowance for equity funds used during construction . . . (3,140) (8,119) (7,378)
Change in accounts receivable . . . . . . . . . . . . . . (16,281) (3,813) 10,380
Change in inventories . . . . . . . . . . . . . . . . . . 10,007 (25,378) 6,024
Change in other current assets . . . . . . . . . . . . . . (1,695) (14,619) (24,670)
Change in accounts payable . . . . . . . . . . . . . . . . (35,364) 31,909 10,373
Change in other current liabilities . . . . . . . . . . . (39,730) (5,439) (16,101)
Change in deferred amounts . . . . . . . . . . . . . . . . (33,920) (17,483) 23,011
Change in noncurrent liabilities . . . . . . . . . . . . . 15,321 (14,759) (57,207)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 92 7,762 521
Net cash provided by operating activities . . . . . . . 245,728 279,879 272,802
Investing activities:
Construction expenditures . . . . . . . . . . . . . . . . . . (317,138) (293,515) (261,666)
Allowance for equity funds used during construction . . . . . 3,140 8,119 7,378
Colorado-Ute asset acquisition . . . . . . . . . . . . . . . - - (265,385)
Proceeds from sale of WGG . . . . . . . . . . . . . . . . . . 87,000 - -
Proceeds from (cost of) disposition of property, plant and equipment 49,438 43,120 (3,187)
Purchase of other investments . . . . . . . . . . . . . . . . (955) (5,660) (6,348)
Sale of other investments . . . . . . . . . . . . . . . . . . 1,148 8,678 97,357
Net cash used in investing activities . . . . . . . . . (177,367) (239,258) (431,851)
44
Financing activities:
Proceeds from sale of common stock (Note 1) . . . . . . . . . 38,086 47,894 48,914
Proceeds from sale of long-term notes and bonds (Note 1) . . 250,068 257,913 296,476
Redemption of long-term notes and bonds . . . . . . . . . . . (281,835) (274,829) (94,197)
Short-term borrowings - net . . . . . . . . . . . . . . . . . 47,925 26,249 49,986
Redemption of preferred stock . . . . . . . . . . . . . . . . (213) (200) (714)
Dividends on common stock . . . . . . . . . . . . . . . . . . (122,531) (118,732) (114,454)
Dividends on preferred stock . . . . . . . . . . . . . . . . (12,016) (12,033) (12,081)
Net cash (used in) provided by financing activities . . (80,516) (73,738) 173,930
Net (decrease) increase in cash and temporary cash investments (12,155) (33,117) 14,881
Cash and temporary cash investments at beginning of year 18,038 51,155 36,274
Cash and temporary cash investments at end of year . . . $ 5,883 $ 18,038 $ 51,155
The accompanying notes to consolidated financial statements
are an integral part of these financial statements.
45
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1994
1. Summary of Significant Accounting Policies
Business and regulation
The Company is an operating public utility engaged, together with
its subsidiaries, principally in the generation, purchase, transmission,
distribution and sale of electricity and in the purchase, transmission,
distribution, sale and transportation of natural gas. The Company is
subject to the jurisdiction of the 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. 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. To the extent
the Company concludes 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 associated regulatory asset or
liability will be reversed with a charge or credit to income.
46
The following regulatory assets are reflected in the Company's
consolidated balance sheets:
Recovery
1994 1993 Through
(Thousands of Dollars)
Nuclear decommissioning costs (Note 2) . . . . . . . . . $ 107,374 $ 118,419 2005
Income taxes (Note 12) . . . . . . . . . . . . . . . . . 125,832 132,647 2006
Employees' postretirement benefits
other than pensions (Note 10) . . . . . . . . . . . . . 37,573 25,855 2013
Early retirement costs (Note 10) . . . . . . . . . . . . 33,124 - 1998
Employees' postemployment benefits (Note 10) . . . . . . 20,975 - Undetermined
Demand-side management costs . . . . . . . . . . . . . . 20,831 10,424 2001
Unamortized debt reacquisition costs . . . . . . . . . . 22,360 18,607 2024
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 7,809 - 1999
Total . . . . . . . . . . . . . . . . . . . . . . . . . 375,878 305,952
Classified as current . . . . . . . . . . . . . . . . . . 39,985 20,891
Classified as noncurrent . . . . . . . . . . . . . . . . $ 335,893 $ 285,061
Certain costs associated with the Company's DSM programs are
deferred and recovered in rates over a seven-year period 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.
Recoverable purchased gas and electric energy costs - net
The Company and Cheyenne tariffs contain clauses which allow
recovery of certain purchased gas and electric energy costs in excess of
the level of such costs included in base rates. These cost adjustment
tariffs are revised periodically, as prescribed by the appropriate
regulatory agencies, for any difference between the total amount collected
under the clauses and the recoverable costs incurred. A substantial
portion of this deferred amount represents the costs incurred to provide
gas and electric energy which customers have used but for which they have
not yet been billed. The cumulative effects are recognized as a current
asset or liability until adjusted by refunds or collections through future
billings to customers.
Other
Property, plant and equipment includes approximately $18.4 million
and $25.4 million, respectively, for costs associated with the engineering
design of the future Pawnee 2 generating station and certain water rights
located in southeastern Colorado, also obtained for a future generating
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
station. Effective with the December 1, 1993 CPUC rate order, the Company
is earning a return on these investments based on the Company's weighted
average cost of debt and preferred stock.
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:
1994 1993 1992
(Thousands of Dollars)
Income taxes . . . . . . . . . . . . . . . . . . . . . . . $ 41,763 $ 49,196 $ 38,624
Interest . . . . . . . . . . . . . . . . . . . . . . . . . $ 126,250 $ 129,844 $ 112,695
Non-cash transactions:
Shares of common stock (334,223 in 1994, 329,220 in 1993 and 333,418
in 1992), valued at the market price on date of issuance (approximately
$10.1 million in 1994, $9.4 million in 1993 and $8.7 million in 1992),
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. During 1994, 7,892 shares of
common stock, valued at the market price on date of issuance
(approximately $0.2 million), were issued to certain executives. These
stock issuances were not cash transactions and are not reflected in the
consolidated statement of cash flows.
A $16.8 million capital lease obligation was incurred in 1994 for
computer equipment.
48
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Changes in certain balance sheet accounts, resulting from the sale
of WGG in 1994 and the Colorado-Ute acquisition in 1992, have been
recognized as non-cash activity.
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 year ended December 31, 1994 and 3.0%
for the years ended December 31, 1993 and 1992. The average rate for 1994
reflects the effects of using a CPUC-approved longer estimated depreciable
life for the Company's electric steam production facilities. 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 1994, 1993 and 1992
were 6.81%-8.75%, 10.21% and 8.95%-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 12).
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
49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
underground storage at December 31, 1994, exceeded the LIFO cost by
approximately $12.5 million.
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:
1994 1993
(Thousands of Dollars)
Cash surrender value of contracts . . . . . . . . . . . . . . . . . . . . . $ 267,445 $ 228,195
Borrowings against contracts . . . . . . . . . . . . . . . . . . . . . . . 265,568 226,429
Net investment in life insurance contracts . . . . . . . . . . . . . . $ 1,877 $ 1,766
2. Fort St. Vrain
Overview
During 1994, the Company recognized additional expenses aggregating
approximately $43.4 million ($26.7 million after-tax or 43 cents per
share) associated with various Fort St. Vrain issues as described below,
including the defueling and decommissioning of the facility.
During 1986, the Company entered into a Stipulation and Settlement
Agreement with the CPUC, the OCC and the other parties involved in
litigation and administrative proceedings related to Fort St. Vrain's
history of limited operations. As a result, the Company's investment in
Fort St. Vrain was removed from rate base and certain charges were
recognized including the write-down of a substantial portion of such
investment and the recognition of the then estimated future unrecoverable
defueling and decommissioning expenses.
In 1989, the Company announced its decision to end nuclear
operations at Fort St. Vrain. The decision was based on the financial
impact of an anticipated lengthy outage necessary to repair the plant's
steam generator system coupled with the plant's history of reduced levels
of generation. The Company has completed defueling from the reactor to
the ISFSI as discussed below in the section entitled "Defueling" and is
currently decommissioning the facility as described below in the section
entitled "Decommissioning."
The Company has been pursuing the repowering of Fort St. Vrain and,
on July 1, 1994, the CPUC issued a decision granting the Company's
application for a CPCN for Phase 1 and Phase 2. The decision approved,
with certain modifications, a Stipulation and Settlement Agreement (the
50
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Settlement) among the Company, the OCC and various other parties regarding
the CPCN.
Repowering
Fort St. Vrain will be repowered as a gas fired combined cycle steam
plant consisting of two combustion turbines and two heat recovery steam
generators totalling 471 Mw. The CPCN provides for the repowering of Fort
St. Vrain in a phased approach as follows: Phase 1A - 130 Mw in 1996,
Phase 1B - 102 Mw in 1998 and Phase 2 - 239 Mw in 1999. The phased
repowering allows the Company flexibility in timing the addition of this
generation supply to meet future load growth.
The Settlement provides for approximately $67.4 million of the then
remaining $72.5 million investment in the existing Fort St. Vrain assets
(comprised of approximately $60.1 million in plant assets and a $12.4
million regulatory asset associated with deferred income taxes) to be
returned to rate base in future electric rate cases following the
completion of each phase or phases of the repowering. The Settlement
allows for the following assignment of existing assets: Phase 1A - $28.9
million, Phase 1B - $27.6 million and Phase 2 - $10.9 million. The
approximately $5 million balance of the Company's remaining investment in
Fort St. Vrain assets will not be returned to rate base pursuant to the
Settlement. During 1994, the Company completed an evaluation of
alternative uses of these assets and concluded that approximately $4.5
million of such assets will not be recovered; therefore, a $4.5 million
impairment reserve has been established. Because of the receipt of the
CPCN related to the repowering of Fort St. Vrain, the Company believes the
recovery of the remaining investment in the facility is probable.
Additionally, a detailed assessment of inventory requirements
necessary for the completion of decommissioning and repowering was
completed during 1994. Such analysis identified that approximately $4.5
million of inventory costs will not be recovered and, therefore, a $4.5
million impairment reserve has also been established.
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, represents the inflation-
adjusted estimated remaining cost of the early
dismantlement/decommissioning activities not previously recognized as
expense. At December 31, 1994, approximately $107.4 million of such
amount remains to be collected from customers and, therefore, is reflected
as a regulatory asset on the consolidated balance sheet. The annual
51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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. Since defueling has been
completed from the reactor to the ISFSI and the NRC decommissioning order
has been received, the Company and the contractors have proceeded with
decommissioning activities. At December 31, 1994, approximately 67% of
the decommissioning process has been performed with final completion of
such activities anticipated in the second quarter of 1996.
The decommissioning contract stipulates a fixed price, based on a
defined work scope; however, such price has been and could be further
modified due to changes in work scope or applicable regulations. In
addition to the four substantive changes in work scope previously agreed
to by the Company since the initiation of decommissioning activities, the
decommissioning contractors notified the Company of several additional
potential scope changes which were primarily related to the identification
of higher radiation levels in the reactor core than originally anticipated
and regulatory changes related to site release as discussed below.
On October 25, 1994, the Company and the decommissioning contractors
reached an agreement resolving all issues and claims related to identified
and certain possible future changes in scope of work covered by the
contract, with certain exceptions. In order to complete all
decommissioning activities related to such scope changes, the Company
recognized an additional $15 million in decommissioning expense during
1994.
The significant exceptions to the agreement, which were also areas
for potential changes in the defined work scope under the decommissioning
contract, include changes in law, radioactive material created by
activation in the lower portion of the reactor, as well as changes in the
methodology requirements and guidance established by the NRC for final
site release. On January 26, 1995, the Company received NRC approval of
its Final Survey Plan for Site Release reducing the future uncertainty
related to this issue. In the event additional costs are identified,
which relate to an issue excepted from the agreement, the decommissioning
contractors will perform all required activities on a cost basis.
While this agreement with the decommissioning contractors does not
eliminate all future decommissioning risk, the Company believes it will
serve to substantially reduce such risk. However, the Company can provide
no assurance that recognition of additional costs will not be required if
events or circumstances unknown to the Company today are identified in the
future.
52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Defueling
Currently, six segments of Fort St. Vrain's spent nuclear fuel
(segments 4-9) are stored in the ISFSI located at the plant site. While
the Company has entered into two separate agreements with the DOE for (a)
the temporary storage and processing of segments 1-8 at a DOE facility
located in the State of Idaho (such contract includes an option to
store/reprocess additional spent fuel segments at the DOE's discretion)
and (b) the disposal of segment 9 at a Federal repository, resolution of
all spent fuel reprocessing/disposal issues has been substantially delayed
pending resolution of several lawsuits filed during 1991 by and among the
Company, the DOE, the State of Idaho and the Shoshone - Bannock Indian
Tribes. While the plant was operating and as part of routine refueling
procedures, three spent fuel segments were transported to the Idaho
facility. It is currently estimated that the Federal repository will not
be available until 2010. The Company, however, intends to pursue with the
DOE the storage/reprocessing of segment 9 at the Idaho facility in
conjunction with the first eight segments.
Most recently, the DOE has required that an EIS be completed
relative to, among other things, the receipt and storage of spent fuel at
the Idaho facility. The DOE had issued a draft EIS and the Company has
submitted comments. Modifications to the Idaho facility will be required
to accommodate the new spent fuel shipping casks. These modifications
would be completed subsequent to the issuance of the EIS. The time
required for these modifications from the DOE has been estimated to be
between 15-18 months. In addition, the DOE has stated that a facility
readiness review will be required. Such review is standard DOE procedure
required to validate the readiness of equipment following a shut-down
period. Such review will also be conducted subsequent to the completion
of the EIS.
As a result of increased uncertainties related to the ultimate
disposal of Fort St. Vrain's spent nuclear fuel, the Company recognized
during 1994 an additional $15 million defueling reserve, determined on a
present value basis. This amount represents the estimated cost of
operating and maintaining the ISFSI until 2020 (if required), the earliest
date the Company believes a Federal repository will be available to accept
the Company's spent nuclear fuel. These estimated expenditures have been
escalated for inflation using an average rate of 3.5% and discounted to
present value at a rate of 8%.
The estimated total cost of defueling and decommissioning Fort St.
Vrain is approximately $361.8 million. At December 31, 1994,
approximately $284.8 million has been spent for such activities with the
remaining $77 million defueling and decommissioning liability reflected on
the consolidated balance sheet ($25 million - defueling; $52 million -
decommissioning). Because of the possibility of further changes in the
decommissioning work scope, changes in applicable regulations and/or the
uncertainties related to the final disposal of spent fuel, there can be no
53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
assurance that the actual cost of defueling and decommissioning will not
exceed the estimated liability. The Company could be required to revise
the estimated cost of defueling and decommissioning as a result of any
such matters.
Funding
Under NRC regulations, the Company is required to make filings with,
and obtain the approval of, the NRC regarding certain aspects of the
Company's decommissioning proposals, including funding. On January 27,
1992, the NRC accepted the Company's funding aspects of the
decommissioning plan. The Company has also obtained an unsecured
irrevocable letter of credit totaling $125 million that meets the NRC's
stipulated funding guidelines including those proposed on August 21, 1991
that address decommissioning funding requirements for nuclear power
reactors that have been prematurely shut down. In accordance with the NRC
funding guidelines, the Company is allowed to reduce the balance of the
letter of credit based upon milestone payments made under the fixed-price
decommissioning contract. As a result of such payments, at December 31,
1994, the letter of credit had been reduced to $66 million.
The Company had previously set aside approximately $30 million in
trust accounts for decommissioning the reactor. Since decommissioning
activities have commenced, the Company completed withdrawing funds from
the trust accounts during the second quarter of 1993. As previously
discussed, on July 1, 1993, the Company began collection of the remaining
decommissioning costs from customers.
In addition, the Company has established a separate decommissioning
trust for the ISFSI which had funds of approximately $1.6 million at
December 31, 1994. It is anticipated that this amount, together with the
expected earnings on the funds, will be sufficient to decommission the
ISFSI.
Costs for maintaining the ISFSI and removing fuel from the ISFSI,
which the Company is not required to prefund, will be paid from a
combination of operating funds of the Company and its subsidiaries and/or
external financing.
Uranium Enrichment Facility Decommissioning Assessment
As part of the EPAct, the DOE Uranium Enrichment Enterprise
Decontamination and Decommissioning Fund was established to provide for
the decommissioning of DOE fuel enrichment facilities. The EPAct provides
for a 15 year assessment of all domestic utilities that own nuclear
generation facilities. The Company believed it would be excluded from the
provisions of the EPAct as Fort St. Vrain was constructed under the Atomic
Energy Demonstration Reactor Program. During 1994, the DOE advised the
Company that it has not been exempted from the provisions of the EPAct.
As a result, the Company recognized an approximate $4 million expense
54
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
associated with this assessment, determined on a present value basis
(escalated for inflation at 4% and discounted at 8%). The Company,
however, intends to further investigate the applicability of the EPAct as
well as the recovery of such costs through the regulatory process.
However, the Company is uncertain as to the ultimate resolution of this
issue.
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 $7.8 billion,
which includes a 5% surcharge. Financial protection for this exposure is
provided by private insurance in an amount available from private insurers
(currently $200 million). The Price Anderson Act also 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 domestic nuclear
power plant, indexed every five years for inflation, provided that not
more than $10 million would be payable per incident in any one year. In
consideration of the shutdown and defueled status of Fort St. Vrain, the
Company requested an exemption from its indemnification obligations under
the Price Anderson Act. On February 17, 1994, the NRC granted this
request, exempting the Company from participation in this indemnity
program and limiting the amount of private 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, however, 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. The Company currently maintains $281 million
in property damage and decontamination insurance. The additional
insurance coverage above the required $169 million is necessary to provide
coverage for the estimated depreciated replacement value of the plant
assets that will be used in the repowering of Fort St. Vrain.
3. Divestiture of Nonutility Assets
As part of the Company's continuing strategy to focus its efforts on
the core electric and gas businesses, the Company has divested certain
nonutility investments.
WestGas Gathering, Inc.
During the third quarter of 1994, the Company sold all of its
55
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
outstanding common stock of WGG, its wholly-owned subsidiary, and certain
related operating assets of the Company which are used by WGG for
approximately $87 million. The Company recognized a pre-tax gain of
approximately $34.5 million ($19.5 million after-tax or approximately 31
cents per share). In addition, pursuant to a Stipulation and Agreement
dated November 17, 1992, approved by the CPUC by Order dated December 7,
1992, the regulatory treatment of a limited portion of this gain may be
subject to a proceeding before the CPUC. The Company believes the
resolution of this matter will not have a material impact on the Company's
results of operations or financial position.
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 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. All property sales have been completed, except the San Juan
Coal Bed Methane properties. The Company is re-evaluating its
alternatives related to the disposition of these properties. The net book
value of the San Juan properties is approximately $21.7 million.
In December 1992, the Company terminated its involvement in Fuelco's
Synhytech fuel conversion technology project. As a result, Fuelco
recognized an expense of approximately $26.9 million ($16.8 million after-
tax) associated with writing-off its entire investment in the Synhytech
plant and recognizing certain additional costs which were incurred in
connection with the termination of this project.
Bannock Center Corporation
In December 1992, BCC sold substantially all of its real estate
properties located near downtown Denver for $6 million, resulting in a
loss of approximately $11.4 million ($8.4 million after-tax).
4. Capital Stock
Common Stock
On December 7, 1992, the Company filed a registration statement with
the SEC relating to the registration of 1,000,000 shares of common stock,
$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 10.
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 future common shares issued will contain this
right. Each right stipulates an initial purchase price of $55 per share
56
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
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 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.
57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Preferred Stock
1994 1993
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 . . . . . . . . . . . . . . 236,412 23,641 238,545 23,854
452,412 45,241 454,545 45,454
Less: Preferred stock subject to mandatory
redemption within one year . . . . . . . (25,760) (2,576) (25,760) (2,576)
Total . . . . . . . . . . . . . . . . . 426,652 $ 42,665 428,785 $ 42,878
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.
58
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Cumulative preferred stock, subject to mandatory redemption:
7.50% series: $102.25 per share on or prior to August 31, 1995,
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: $102.50
per share on or prior to July 31, 1995, and reducing each year thereafter
by $0.25 per share until July 31, 2004, after which the redemption price
is $100 per share.
In 1995 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, 1994 consolidated balance sheet. In 1994, 1993,
and 1992, the Company repurchased 2,133 shares, 2,000 shares and 7,135
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, 1994.
59
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
5. Long-Term Debt
1994 1993
(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 $ 134,500
7 1/4% series, due January 1, 2024 . . . . . . . . . . . . . . . . . . 110,000 -
First Mortgage Bonds:
4 1/2% - 6 3/4% series, due June 1, 1994 - July 1, 1998 . . . . . . . 95,000 130,000
7 1/4% - 8 1/4% series, due February 1, 2001 - November 1, 2007 . . . 100,000 289,500
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 . . . . . . . . 23,500 24,000
Pollution Control Series F, 7 3/8%, due November 1, 2009 . . . . . . . 27,250 27,250
Pollution Control Series G, 5 5/8% - 7 3/8%, 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 12, 1995 - October 30, 2002 . . . . . . 149,500 141,500
Unsecured promissory notes:
7 3/4% - 10.35%, due December 1, 1997 - December 1, 1999 . . . . . . . - 21,333
11.60% - 12.875%, due May 1, 2015 - May 1, 2025 . . . . . . . . . . . 15,000 15,000
Unamortized premium . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 157
Unamortized discount . . . . . . . . . . . . . . . . . . . . . . . . . . (5,105) (3,686)
Capital lease obligations, 6.68%-14.65%, due in installments through
August 31, 1999 17,093 1,112
1,123,948 1,135,166
Cheyenne Light, Fuel and Power Company:
First Mortgage Bonds:
7 7/8% series, due April 1, 2003 . . . . . . . . . . . . . . . . . . . 4,000 4,000
7.5% series, due January 1, 2024 . . . . . . . . . . . . . . . . . . . 8,000 -
Industrial Development Revenue Bonds, 7.25%, due September 1, 2021 . . 7,000 7,000
10.70% unsecured notes, due September 1, 1995 . . . . . . . . . . . . . . - 8,000
1480 Welton, Inc.:
12.50% secured promissory note, due in installments through March 1, 1998 5,480 6,766
13.25% secured promissory note, due in installments through October 1, 2016 32,083 32,320
Fuel Resources Development Co.:
Capital lease obligations, 7.09% due in installments through March 1, 1995 13 303
Natural Fuels Corporation:
12.25% secured note, retired May 23, 1994 . . . . . . . . . . . . . . - 2
Capital lease obligations, 8 1/8% due in installments through August 31, 1997 56 111
1,180,580 1,193,668
Less: maturities due within one year . . . . . . . . . . . . . . . . . . . . 25,153 58,324
$ 1,155,427 $ 1,135,344
60
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 Company's 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, 1994 are (in thousands of
dollars):
Year Maturities Sinking Fund Requirements Total
1995 $ 25,153 $ 1,510 $ 26,663
1996 83,047 1,160 84,207
1997 75,176 810 75,986
1998 34,048 560 34,608
1999 28,184 560 28,744
The Company and Cheyenne expect to satisfy substantially all of
their sinking fund obligations through the application of property
additions.
6. Notes Payable and Commercial Paper
Information regarding notes payable and commercial paper for the
years ended December 31, 1994 and 1993 is as follows:
1994 1993
(Thousands of Dollars)
Notes payable to banks (weighted average interest rates of 6.34% at
December 31, 1994 and 3.69% at December 31, 1993) . . . . . . . . . . . . $ 107,850 $ 46,100
Commercial paper (weighted average interest rates of 6.22% at
December 31, 1994 and 3.58% at December 31, 1993) . . . . . . . . . . . . 216,950 230,775
$ 324,800 $ 276,875
Maximum amount outstanding at any month-end during the period . . . . . . . . $ 333,865 $ 276,875
Weighted average amount (based on the daily outstanding balance) outstanding for
the period (weighted average interest rates of 4.58% for the year ended
December 31, 1994 and 3.33% for the year ended December 31, 1993) . . . . $ 273,015 $ 237,526
61
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
7. 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 22, 1994, the Company, PSCCC and certain subsidiaries
extended a credit facility with several banks providing $300 million in
committed bank lines of credit. The credit facility, which is used
primarily to support the issuance of commercial paper by the Company and
PSCCC, alternatively provides for direct borrowings thereunder. Under the
current extension, Cheyenne, 1480 Welton, Inc., Fuelco and PSRI are
provided access to the credit facility with direct borrowings guaranteed
by the Company. The facility expires November 21, 1995.
Individual arrangements for uncommitted bank lines of credit totaled
$75 million at December 31, 1994. The unused uncommitted bank lines of
credit at December 31, 1994 was $9 million. The Company may borrow under
uncommitted preapproved lines of credit upon request; however, the banks
have no firm commitment to make such loans.
8. Commitments and Contingencies
Regulatory Matters
Electric and Gas Cost Adjustment Mechanisms
The Company's ECA mechanism was revised and a new QFCCA mechanism
was implemented on December 1, 1993, along with the base rate changes
resulting from the 1993 rate case. Under the revised ECA, fuel used for
generation and purchased energy costs from utilities, 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. While the
CPUC approved the QFCCA, recovery of such costs may be subject to an
earnings test, which has not yet been defined by the CPUC. The OCC has
proposed an annual earnings test that may result in a reduction of QFCCA
recoveries to the extent the Company's earnings are in excess of its 11%
authorized rate of return on regulated common equity. Hearings regarding
this matter are scheduled for April 1995.
The CPUC held a prehearing conference on May 24, 1994 for the
purpose of establishing a schedule for reviewing the justness and
reasonableness of GCA and ECA mechanisms used by gas and electric
utilities within its jurisdiction resulting in the opening of an
62
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
investigatory docket. Open hearings were held in December 1994. The OCC
and the CPUC staff are recommending the elimination of these cost
adjustment mechanisms. The Company is in opposition to the elimination of
these cost adjustment mechanisms and has filed initial comments, as well
as responded to the comments filed by the other parties. On February 6-7,
1995, as part of an open hearing, the CPUC determined that proceeding with
a generic ECA rulemaking docket was not appropriate. However, the Company
is required to make an individual filing with the CPUC related to its ECA
by September 1, 1995 to review whether the ECA should be maintained in its
present form, altered or eliminated. Additionally, the CPUC preliminarily
determined that the GCA will continue under current practices. The CPUC
staff will hold informal roundtable discussions for the purpose of
clarifying the review procedures for the GCA.
On June 8, 1994, the CPUC approved the recovery of certain "energy
efficiency credits" from retail jurisdiction customers through the DSMCA
with collection estimated to begin July 1, 1995. At December 31, 1994,
the Company has recognized approximately $6.7 million of unbilled revenue
related to these credits. On December 1, 1994, the OCC filed an appeal in
Denver District Court of the CPUC's decision approving the collection of
these credits. If the OCC is successful in its appeal, the Company could
be required to reverse these unbilled revenues.
Incentive Regulation and Demand Side Management
The CPUC has opened a separate docket to investigate issues relating
to the adoption and implementation of incentive regulation, which includes
the concept of decoupling the Company's earnings from sales, and
additional DSM incentives. On February 10, 1994, the parties to this
docket filed a unanimous stipulation and settlement agreement with the
CPUC. Provisions of the stipulation include, among other things,
retaining the cost recovery component of the DSMCA through December 31,
1998, modifying slightly the DSM incentive mechanism for 1994 and 1995 and
forming a technical working group to study and analyze various alternative
annual revenue reconciliation mechanisms and incentive mechanisms for 1996
through 1998, which would replace existing DSM incentives until another
mechanism or regulatory approach is approved by the CPUC. The stipulation
agreement, which includes a procedural schedule to review the results of
all studies and simulations over the next year, was approved by the CPUC
on June 16, 1994. The technical working group will present to the CPUC a
detailed analysis demonstrating the effect of the various proposed
mechanisms by the end of the first quarter of 1995.
1993 Rate Case
On November 26, 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
63
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
effective December 1, 1993. The OCC has filed in Denver District Court an
appeal of the CPUC's decision. The OCC has claimed that the accounting
related to a specific income tax issue results in the overcollection of
costs from ratepayers. The Company is in opposition to the appeal. The
Company believes that the resolution of this appeal will not have a
material effect on its financial position or results of operations.
On August 1, 1994, the Company filed its Phase II testimony. The
Phase II proceedings will address cost allocation issues and specific rate
changes for the various customer classes based on the results of the Phase
I hearings and decision that became effective December 1, 1993. A final
CPUC decision on the Phase II proceedings is expected in late 1995.
Environmental Issues
Environmental Site Cleanup
Under 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, which
is one of several PRPs, is involved in the cleanup of this site which
began in November 1992 and is expected to be completed during the second
quarter of 1995. The total project cost is currently estimated to be
approximately $8.5 million. The Company believes it is probable that a
significant portion of these cleanup costs will be recovered through
claims made against the Company's insurance companies as monetary
settlements with certain insurers have been achieved. Lawsuits against
certain remaining insurance companies have been filed in the Denver
District Court and a trial is scheduled to begin in late February 1995.
To the extent such costs are not recovered by insurance or from other
PRPs, the Company believes it is probable that such costs will be
recovered through the rate regulatory process.
PCB presence has been identified in the basement of an historic
office building located in downtown Denver. The Company was negotiating
the future cleanup with the current owners; however, on October 5, 1993,
the owners filed a civil action against the Company in the Denver District
Court. The action alleged that the Company was responsible for the PCB
releases and additionally claimed other damages in unspecified amounts.
On August 8, 1994, the Denver District Court entered a judgment approving
a $5.3 million settlement agreement between the Company and the building
owners resolving all claims between the Company and the building owners.
The Company believes it is probable that it will recover some portion of
these costs through insurance claims. To the extent such costs are not
recovered by insurance, the Company believes it is probable that such
costs will be recovered through the rate regulatory process.
The Company is pursuing reoccupation of its former Headquarters
64
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Office Building, which contained asbestos. The asbestos abatement/removal
at the site was recently completed at a cost of approximately $8.3
million. The Company plans to further remodel and reoccupy the facility
during 1995 and 1996 and expects to recover all such costs through the
rate regulatory process.
The Elitch Gardens Amusement Park site near downtown Denver has
revealed low level, widespread contamination. The Company had used the
site in the past as a manufactured gas plant site and is one of three
PRPs. An agreement has been signed by Trillium Corporation, a PRP, Elitch
Gardens Co. and the Company, releasing the Company from responsibility
for the first $2 million of expenses related to contamination. Any
contamination expenses incurred during construction or thereafter which
exceed $2 million will be the responsibility of the Company; however, the
Company could then pursue recovery of the incurred costs from Burlington
Northern Railroad, the third PRP, and/or through insurance claims.
Contamination expenses to date have not exceeded $2 million.
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 or results of
operations. The Company fully intends to pursue the recovery of all
significant costs incurred for such projects through insurance claims
and/or the rate regulatory process. To the extent any costs are not
recovered through the options listed above, the Company would be required
to recognize an expense for such unrecoverable amounts.
Other Environmental Matters
Under the Clean Air Act Amendments of 1990, coal burning power
plants are required to reduce SO 2 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 at an estimated total future cost of approximately $21
million. The Company is studying its options to reduce SO 2 emissions and
currently does not anticipate that these regulations will significantly
impact its operations.
On August 18, 1993, a conservation organization filed a complaint in
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, on certain
occasions, the station exceeded opacity limitations during the past
several years. The complaint seeks, among other things, civil monetary
65
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
penalties. At this time the Company is not able to estimate the amount,
if any, of its potential liability or whether additional particulate
control equipment will be required. Discovery has been completed and a
trial date has been set for August 1995.
The Company believes that, consistent with historical regulatory
treatment, any costs to comply with pollution control regulations would be
recovered from its customers. However, no assurance can be given that
this practice will continue in the future.
Purchase requirements
Coal purchases and transportation
At December 31, 1994, 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 92 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 $820 million at December 31, 1994.
The Company has entered into long-term contracts for the
transportation of coal by railroad in Company-owned or leased railcars to
existing power plants. These agreements, expiring in 2000, provide for a
minimum remaining transport quantity of 27 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 $93 million at
December 31, 1994.
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 which expire
on various dates through 1998. 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 for the next three years. The Company will not incur any gas supply
realignment costs otherwise applicable under FERC Order 636. At December
31, 1994, the Company and Cheyenne have minimum obligations under such
contracts of $222 million in 1995 declining thereafter for a total
estimated commitment of $431 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,
to replace generation from Company-owned units under maintenance and
outages, and to meet the Company's operating reserve obligation to the
Pool.
66
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 the QFCCA. Additionally, the Company and
Cheyenne have long-term purchased power contracts with various regional
utilities expiring through 2022. 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 $427 million, $366 million and $332 million in 1994, 1993
and 1992, respectively.
At December 31, 1994, 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)
1995 . . . . . . . . . . . . . . . . . . . . . $ 142,070 $ 176,936 $ 319,006
1996 . . . . . . . . . . . . . . . . . . . . . 143,499 183,089 326,588
1997 . . . . . . . . . . . . . . . . . . . . . 143,583 184,691 328,274
1998 . . . . . . . . . . . . . . . . . . . . . 143,299 183,383 326,682
1999 . . . . . . . . . . . . . . . . . . . . . 143,275 175,160 318,435
2000 and thereafter . . . . . . . . . . . . . . 1,292,476 2,239,290 3,531,766
Total . . . . . . . . . . . . . . . . . . . . $ 2,008,202 $ 3,142,549 $ 5,150,751
Historically, all minimum coal, coal transportation, natural gas and
purchased power requirements have been met.
Other purchases
Commitments made for the purchase of materials, plant and equipment
additions, DSM expenditures and other various items aggregated
approximately $405 million at December 31, 1994.
Employee Litigation
Several employee lawsuits have been filed against the Company
involving alleged sexual/age discrimination. In addition, 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.
A jury recently awarded two of 21 plaintiffs approximately $500,000, which
67
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
the Company has accrued. The Company is considering an appeal of this
decision. The remaining 19 claims were dismissed. The Company is
actively contesting all outstanding lawsuits and believes the ultimate
outcome will not have a material impact on the Company's results of
operations or financial position.
Leasing program
The Company and its subsidiaries maintain operating leases for
equipment and facilities used in the normal course of business. The
majority of these operating leases are under a leasing program that has
initial noncancelable terms of one year, while the remaining operating
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 1994,
1993 and 1992 was $29.7 million, $28.1 million, and $25.1 million,
respectively. At December 31, 1994, estimated future minimum rental
payments applicable to noncancelable operating leases were as follows:
(Thousands of Dollars)
1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 17,572
1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16,521
1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,250
1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,038
1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,133
2000 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23,029
Total minimum rental payments . . . . . . . . . . . . . . . . . . . . . $ 95,543
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.
68
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
9. Jointly-Owned Electric Utility Plants
The Company's investment in jointly-owned plants and its ownership
percentages as of December 31, 1994 are:
Plant Construction
in Accumulated Work in
Service Depreciation Progress Ownership %
(Thousands of Dollars)
Hayden Unit 1 . . . . . . . . . . . . . $ 37,183 $ 29,238 $ 1,151 75.50
Hayden Unit 2 . . . . . . . . . . . . . 57,616 29,489 229 37.40
Hayden Common Facilities . . . . . . . 1,679 1,258 924 53.10
Craig Units 1 & 2 . . . . . . . . . . . 56,874 21,091 312 9.72
Craig Common Facilities Units 1 & 2 . . 7,533 2,779 785 9.72
Craig Common Facilities Units 1,2 & 3 . 8,218 2,956 410 6.47
Transmission Facilities, Including
Substations . . . . . . . . . . . . . 72,037 19,575 - 42.0-73.0
$ 241,140 $ 106,386 $ 3,811
These assets include approximately 331 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.
10. Employee Benefits
Pensions
The Company and its subsidiaries (excluding Natural Fuels) maintain
a noncontributory defined benefit pension plan covering substantially all
employees.
The net pension expense in 1994, 1993 and 1992 was comprised of:
1994 1993 1992
(Thousands of Dollars)
Service cost . . . . . . . . . . . . . . . . . . . . . . . . $ 16,169 $ 15,868 $ 14,788
Interest cost on projected benefit
obligation . . . . . . . . . . . . . . . . . . . . . . . . 45,518 38,106 35,695
Actual return on plan assets . . . . . . . . . . . . . . . . 5,844 (52,369) (34,317)
Amortization of net transition asset . . . . . . . . . . . . (3,674) (3,674) (3,674)
Other items . . . . . . . . . . . . . . . . . . . . . . . . . (56,996) 8,219 (6,317)
Net pension expense . . . . . . . . . . . . . . . . . . . $ 6,861 $ 6,150 $ 6,175
69
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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:
Jan-Mar Apr-Dec
1994 1994 1993 1992
Discount rate 7.5% 8.0% 8.2% 8.2%
Expected long-term increase in compensation
level 5.0% 5.0% 5.5% 5.5%
Expected weighted average long-term rate of
return on assets 10.5% 10.5% 11% 11%
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, 1994 and 1993, 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 its subsidiaries'
funding policy is to contribute annually, at a minimum, the amount necessary
to satisfy the IRS funding standards.
1994 1993
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $410,117 $392,623
Nonvested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30,136 39,343
440,253 431,966
Effect of projected future salary increases . . . . . . . . . . . . . . . . 87,079 128,294
Projected benefit obligation for service rendered to date . . . . . . . . . 527,332 560,260
Plan assets at fair value . . . . . . . . . . . . . . . . . . . . . . . . . (491,735) (523,548)
Projected benefit obligation in excess of plan assets . . . . . . . . . . . (35,597) (36,712)
Unrecognized net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . 33,650 58,252
Prior service cost not yet recognized in net periodic pension cost . . . . 32,368 34,673
Unrecognized net transition asset at January 1, 1986,
being recognized over 17 years . . . . . . . . . . . . . . . . . . . . (29,390) (33,064)
Prepaid pension asset . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,031 $ 23,149
70
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Significant assumptions used in determining the benefit obligations
were:
1994 1993
Discount rate 8.75% 7.5%
Expected long-term increase in compensation level 5.0% 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 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 have been 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 served to reduce pre-tax earnings.
71
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Postretirement benefits other than pensions
The Company and its subsidiaries 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 its
subsidiaries. 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 its subsidiaries
adopted SFAS 106 which requires the accrual, during the years that an
employee renders service to the Company, of the expected cost of providing
postretirement benefits other than pensions to the employee and the
employee's beneficiaries and covered dependents.
The Company is transitioning to full accrual accounting for OPEB
costs between January 1, 1993 and December 31, 1997, consistent with the
accounting requirements for rate regulated enterprises. All OPEB costs
deferred during the transition period will be amortized on a straight line
basis over the subsequent 15 years. Effective December 1, 1993, the
Company began recovering such costs based on the level of expense
determined in accordance with the CPUC approach 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 as required under 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.
The Company plans to file a FERC rate case in 1995 which will
include a request for approval to recover all wholesale jurisdiction SFAS
106 costs. Effective January 1, 1993, Cheyenne began recovering SFAS 106
costs as approved by the WPSC. The Company and Cheyenne intend to fund
this plan based on the amounts reflected in cost-of-service, consistent
with the rate orders.
72
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The net periodic postretirement benefit cost in 1994 and 1993 under SFAS 106 was comprised of:
1994 1993
(Thousands of Dollars)
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,101 $ 4,943
Interest cost on projected benefit obligation . . . . . . . . . . . . . . . 24,111 20,828
Return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . (938) (164)
Amortization of net transition obligation at January 1, 1993,
assuming a 20 year amortization period . . . . . . . . . . . . . . . . . 12,710 12,710
Net postretirement benefit cost required by SFAS 106 . . . . . . . . . . . 41,984 38,317
OPEB expense recognized in accordance with current regulation . . . . . . . (30,266) (12,462)
Increase in regulatory asset (Note 1) . . . . . . . . . . . . . . . . . . . 11,718 25,855
Regulatory asset at beginning of year . . . . . . . . . . . . . . . . . . . 25,855 -
Regulatory asset at end of year . . . . . . . . . . . . . . . . . . . . . . $ 37,573 $ 25,855
Significant assumptions used in determining net periodic
postretirement benefit cost were:
Jan-Mar Apr-Dec
1994 1994 1993
Discount rate 7.5% 8.0% 8.2%
Expected long-term increase in
compensation level 5.0% 5.0% 5.5%
Expected return on plan assets 10.5% 10.5% 10.5%
The OPEB expense on a pay-as-you-go basis was $9.1 million for 1992.
73
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
A comparison of the actuarially computed benefit obligations and
plan assets at December 31, 1994 and 1993 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.
1994 1993
(Thousands of Dollars)
Accumulated postretirement benefit obligation:
Retirees and eligible beneficiaries . . . . . . . . . . . . . . . . . . $ 95,382 $ 86,718
Other fully eligible plan participants . . . . . . . . . . . . . . . . 71,683 95,103
Other active plan participants . . . . . . . . . . . . . . . . . . . . 86,505 98,342
Total 253,570 280,163
Plan assets at fair value . . . . . . . . . . . . . . . . . . . . . . . . . (18,114) (476)
Accumulated benefit obligation in excess of plan assets . . . . . . . . . . 235,456 279,687
Unrecognized net gain (loss) . . . . . . . . . . . . . . . . . . . . . . . 35,423 (10,059)
Unrecognized transition obligation . . . . . . . . . . . . . . . . . . . . (228,773) (241,483)
Accrued postretirement benefit obligation . . . . . . . . . . . . . . . . $ 42,106 $ 28,145
Significant assumptions used in determining the accumulated
postretirement benefit obligation were:
1994 1993
Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.75% 7.5%
Ultimate health care cost trend rate . . . . . . . . . . . . . . . . . . . 6.0% 5.3%
Expected long-term increase in
compensation level . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.0% 5.0%
The assumed health care cost trend rate for 1994 is 11.5%,
decreasing to 6.0% in 0.5% annual increments. A 1% increase in the
assumed health care cost trend will increase the estimated total
accumulated benefit obligation by $35.8 million, and the service and
interest cost components of net periodic postretirement benefit costs by
$4.6 million.
Postemployment benefits
The Company and its subsidiaries 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). The Company has recorded a $21 million regulatory asset (see
74
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 1) and a corresponding liability on the consolidated balance sheet,
assuming an 8% discount rate. The Company believes it is probable that it
will receive regulatory approvals to recover these costs in future rates.
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 stock options and/or restricted shares. 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. Cash and
restricted stock awards were made under the Omnibus Incentive Plan for
calendar years 1994 and 1993. Additionally, options were granted to
eligible employees for these same years.
The Employee Incentive Plan provides for cash awards to all
employees based on the achievement of corporate goals. Performance goals
were met in 1994 and 1993.
The expenses accrued under both incentive plans totaled
approximately $6.0 million in 1994 and $5.2 million in 1993.
11. 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, 1994 and
1993. 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.
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of dollars)
Investments, at cost . . . . . . . . . . . . $ 7,308 $ 7,283 $ 7,693 $ 7,749
Preferred stock subject to mandatory redemption 45,241 45,518 45,454 46,650
Long-term debt . . . . . . . . . . . . . . . 1,168,480 1,119,391 1,195,669 1,255,768
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 and are classified as held-to-maturity. The
unrealized holding gains and losses for these debt and equity securities
are not significant.
75
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 instrument
In accordance with NRC decommissioning funding requirements for
nuclear power reactors, the Company has obtained a $66 million irrevocable
letter of credit which bears a market interest rate. The NRC is the
beneficiary of this letter of credit. At December 31, 1994 and 1993, 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.
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.
12. Income Tax Expense
The provisions for income tax for the years ended December 31, 1994,
1993 and 1992 consist of the following:
1994 1993 1992
(Thousands of Dollars)
Current income taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . $ 22,081 $ 34,684 $ 34,265
State . . . . . . . . . . . . . . . . . . . . . . . . . . (2,016) (2,208) 1,513
Total current income taxes . . . . . . . . . . . . . . 20,065 32,476 35,778
Deferred income taxes . . . . . . . . . . . . . . . . . . . . 34,234 33,435 22,509
Investment tax credits - net . . . . . . . . . . . . . . . . (5,799) (4,917) (5,138)
Total provision for income taxes . . . . . . . . . . . . . . $ 48,500 $ 60,994 $ 53,149
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
76
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
normalization method of accounting for income taxes as provided for in a
recent rate order from the CPUC.
A reconciliation of the statutory U.S. income tax rates to the
effective tax rates is as follows:
1994 1993 1992
(Thousand of Dollars)
Tax computed at U.S. statutory rate on
pre-tax accounting income . . . . . . $76,569 35.0% $76,424 35.0% $64,522 34.0%
Increase (decrease) in tax from:
Allowance for funds used
during construction . . . . . . . . . (2,449) (1.1) (4,369) (2.0) (3,827) (2.0)
Amortization of investment tax credits (5,792) (2.6) (4,889) (2.2) (5,128) (2.7)
Cash surrender value of life
insurance policies . . . . . . . . . (7,643) (3.5) (6,386) (2.9) (4,620) (2.4)
Capitalized software, net of amortization - - (4,820) (2.2) (7,115) (3.7)
Capitalized overheads . . . . . . . . . - - 7,170 3.3 7,112 3.7
Lease amortization . . . . . . . . . . - - 3,692 1.7 3,407 1.8
Amortization of prior flow-through amounts 10,509 4.8 934 0.4 - -
Adoption of SFAS 109 . . . . . . . . . - - (1,911) (0.9) - -
Tax accrual adjustment . . . . . . . . (21,262) (9.7) - - - -
Other-net . . . . . . . . . . . . . . . (1,432) (0.7) (4,851) (2.2) (1,202) (0.7)
Total income taxes . . . . . . . . . . $48,500 22.2% $60,994 28.0% $53,149 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, has not been 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). During 1993, the Federal statutory income tax
rate was raised from 34% to 35%, retroactive to January 1, 1993. The
impact of this tax rate change on the Company was to increase the net
deferred income tax liability by $16.8 million, of which $16.7 million
increased the regulatory asset related to income taxes.
77
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 1994 and 1993 are
as follows:
1994 1993
(Thousands of Dollars)
Deferred income tax liabilities:
Accelerated depreciation and amortization . . . . . . . . . $332,222 $313,275
Plant basis differences (prior flow-through) . . . . . . . 188,194 168,131
Allowance for equity funds used during construction . . . . 49,824 51,500
Pensions . . . . . . . . . . . . . . . . . . . . . . . . . 35,975 31,689
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,792 28,398
Total . . . . . . . . . . . . . . . . . . . . . . . . . . 648,007 592,993
Deferred income tax assets:
Investment tax credits . . . . . . . . . . . . . . . . . . 73,270 76,841
Contributions in aid of construction . . . . . . . . . . . 47,832 33,063
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 61,946 41,760
Total . . . . . . . . . . . . . . . . . . . . . . . . . . 183,048 151,664
Net deferred income tax liability . . . . . . . . . . . . . . $464,959 $441,329
As of December 31, 1994 the Company has cumulative AMT carryforwards
of approximately $12.7 million. A valuation allowance has not been
recorded as the Company expects that all deferred income tax assets will
be realized in the future.
78
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
13. Segments of Business
Segment information for the year ended December 31, 1994 is as
follows:
Electric(1) Gas Other Total
(Thousands of Dollars)
Operating revenues . . . . . . . . . . . . . . . $ 1,399,836 $ 624,922 $ 32,626 $ 2,057,384
Operating expenses, excluding depreciation
and income taxes . . . . . . . . . . . . . . . 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, December 31, 1994:
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(2) . . . . . . . . . $ -- $ 42,355 $ -- 42,355
Other corporate assets . . . . . . . . . . . . 775,105
$ 4,207,832
Segment information for the year ended December 31, 1993 is as follows:
Electric Gas Other Total
(Thousands of Dollars)
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
79
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Identifiable assets, December 31, 1993:
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(2) . . . . . . . . . $ -- $ 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.
(2) Additional gas storage was purchased as part of the Company's implementation strategy associated with FERC Order 636.
* Before income taxes.
** Includes allocation of common utility property.
80
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Segment information for the year ended December 31, 1992 is as
follows:
Electric Gas(3) Other(4) Total
(Thousands of Dollars)
Operating revenues . . . . . . . . . . . . . . . $ 1,260,769 $ 568,886 $ 32,618 $ 1,862,273
Operating expenses, excluding depreciation
and income taxes . . . . . . . . . . . . . . . 886,215 529,225 16,740 1,432,180
Depreciation and amortization . . . . . . . . . . 97,274 27,621 2,422 127,317
Total operating expenses* . . . . . . . . . . . 983,489 556,846 19,162 1,559,497
Operating income* . . . . . . . . . . . . . . . . $ 277,280 $ 12,040 $ 13,456 $ 302,776
Plant construction expenditures** . . . . . . . . $ 185,170 $ 73,685 $ 2,811 $ 261,666
Identifiable assets, December 31, 1992:
Property, plant and equipment** . . . . . . . . $ 2,331,116 $ 653,898 $ 92,495 $ 3,077,509
Materials and supplies . . . . . . . . . . . . $ 67,618 $ 13,302 $ 82 81,002
Fuel inventory . . . . . . . . . . . . . . . . $ 33,384 $ -- $ 189 33,573
Gas in underground storage . . . . . . . . . . $ -- $ 14,393 $ -- 14,393
Other corporate assets . . . . . . . . . . . . 553,106
$ 3,759,583
(3) Includes additional expense of approximately $26.9 million associated with the termination of the Synhytech project.
(4) Includes additional expense of approximately $11.4 million associated with the loss on sale of BCC real estate
properties.
* Before income taxes.
** Includes allocation of common utility property.
81
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Concluded)
14. Quarterly Financial Data (Unaudited)
The following summarized quarterly information for 1994 and
1993 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.
1994
Three months ended
March 31 June 30 September 30 December 31
(In Thousands-except per share data)
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
1993
Three months ended
March 31 June 30 September 30 December 31
(In Thousands-except per share data)
Operating revenues . . . . . . . . . . . . . . . $ 607,389 $ 448,001 $ 422,353 $ 520,942
Operating income . . . . . . . . . . . . . . . . $ 88,014 $ 49,681 $ 56,575 $ 86,663
Net income . . . . . . . . . . . . . . . . . . . $ 58,687 $ 20,435 $ 25,527 $ 52,711
Earnings available for common stock . . . . . . . $ 55,678 $ 17,426 $ 22,519 $ 49,706
Weighted average common shares outstanding . . . 58,997 59,535 59,925 60,324
Earnings per weighted average common share . . . $0.94 $0.29 $0.38 $0.82
82
SCHEDULE II
PUBLIC SERVICE COMPANY OF COLORADO
AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Years Ended December 31, 1994, 1993 and 1992
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:
1994 . . . . . . . . . . . . . . . . $ 3,276 $ 8,533 $ 132 $ 8,768 $ 3,173
1993 . . . . . . . . . . . . . . . . $ 3,388 $ 6,878 $ 13 $ 7,003 $ 3,276
1992 . . . . . . . . . . . . . . . . $ 4,741 $ 5,483 $ 1,511 $ 8,347 $ 3,388
---------------------------------------
(1) Bad debts recovered, transfers from customers' deposit, etc.
(2) Bad debt written off.
83
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,
1994 1993 1992 1991 1990
(Thousands of Dollars, except ratios)
Fixed charges:
Interest on long-term debt . . . . . . . . . $ 89,005 $ 98,089 $ 92,581 $81,666 $75,075
Interest on borrowings against COLI contracts 29,786 25,333 18,312 8,144 7,771
Other interest . . . . . . . . . . . . . . . 14,235 9,445 12,357 14,574 16,178
Amortization of debt discount and expense
less premium . . . . . . . . . . . . . . . . 3,126 2,018 1,790 1,827 1,543
Interest component of rental expense . . . . 6,888 6,824 7,904 6,892 5,806
Total . . . . . . . . . . . . . . . . . . $143,040 $141,709 $132,944 $113,103 $106,373
Earnings (before fixed charges and taxes on income):
Net income . . . . . . . . . . . . . . . . . $170,269 $157,360 $136,623 $149,693 $146,144
Fixed charges as above . . . . . . . . . . . 143,040 141,709 132,944 113,103 106,373
Provisions for Federal and state taxes on income,
net of investment tax credit amortization . 48,500 60,994 53,149 69,288 73,978
Total . . . . . . . . . . . . . . . . . . $361,809 $360,063 $322,716 $332,084 $326,495
Ratio of earnings to fixed charges . . . . . . . 2.53 2.54 2.43 2.94 3.07
84
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,
1994 1993 1992 1991 1990
(Thousands of Dollars, except ratios)
Fixed charges and preferred stock dividends:
Interest on long-term debt . . . . . . . . . $ 89,005 $ 98,089 $ 92,581 $ 81,666 $ 75,075
Interest on borrowings against COLI contracts 29,786 25,333 18,312 8,144 7,771
Other interest . . . . . . . . . . . . . . . 14,235 9,445 12,357 14,574 16,178
Amortization of debt discount and expense less premium 3,126 2,018 1,790 1,827 1,543
Interest component of rental expense . . . . 6,888 6,824 7,904 6,892 5,806
Preferred stock dividend requirement . . . . 12,014 12,031 12,077 12,234 12,439
Additional preferred stock dividend requirement 3,422 4,662 4,699 5,662 6,297
Total . . . . . . . . . . . . . . . . . . $158,476 $158,402 $149,720 $130,999 $125,109
Earnings (before fixed charges and taxes on income):
Net income . . . . . . . . . . . . . . . . . $170,269 $157,360 $136,623 $149,693 $146,144
Interest on long-term debt . . . . . . . . . 89,005 98,089 92,581 81,666 75,075
Interest on borrowings against COLI contracts 29,786 25,333 18,312 8,144 7,771
Other interest . . . . . . . . . . . . . . . 14,235 9,445 12,357 14,574 16,178
Amortization of debt discount and expense less premium 3,126 2,018 1,790 1,827 1,543
Interest component of rental expense . . . . 6,888 6,824 7,904 6,892 5,806
Provisions for Federal and state taxes on income,
net of investment tax credit amortization . 48,500 60,994 53,149 69,288 73,978
Total . . . . . . . . . . . . . . . . . . $361,809 $360,063 $322,716 $332,084 $326,495
Ratio of earnings to fixed charges
and preferred stock dividends . . . . . . . . . 2.28 2.27 2.16 2.54 2.61
85
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 1995 Proxy Statement,
which information is incorporated herein by reference.
Executive Officers (at December 31, 1994 except as noted):
Executive Officers Initial Effective Date
D. D. Hock, Age 59
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
President, Fuel Resources Development Co. . . . . . . . . . . . . . . . . . . . May 12, 1993
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 and President, Green and Clear Lakes Company . . . . . . . December 6, 1988
Chairman of the Board, WestGas Interstate, Inc. . . . . . . . . . . . . . . . . April 22, 1993
President, WestGas Interstate, Inc. . . . . . . . . . . . . . . . . . . . . . . June 4, 1993
Chairman of the Board, WestGas TransColorado, Inc. . . . . . . . . . . . . . . . April 22, 1993
President, WestGas TransColorado, Inc. . . . . . . . . . . . . . . . . . . . . . June 4, 1993
Chairman of the Board, Natural Fuels Corporation . . . . . . . . . . . . . . . . June 11, 1993
President, Natural Fuels Corporation . . . . . . . . . . . . . . . . . . . . . . November 5, 1993
Chairman of the Board, e prime . . . . . . . . . . . . . . . . . . . . . . . . . January 30, 1995
Company Service: September, 1962
Wayne H. Brunetti, Age 52
President and Chief Operating Officer . . . . . . . . . . . . . . . . . . . . . June 28, 1994
President, e prime . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . January 30, 1995
Company Service: June, 1994
Richard C. Kelly, Age 48
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
86
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
Treasurer, WestGas TransColorado, Inc . . . . . . . . . . . . . . . . . . . . . July 15, 1994
Chairman and Chief Executive Officer, Service Telecommunications Co. . . . . . . February 8, 1991
Vice President and Treasurer, e prime. . . . . . . . . . . . . . . . . . . . . . January 30, 1995
Company Service: May, 1968
Patricia T. Smith, Age 47
Senior Vice President and General Counsel . . . . . . . . . . . . . . . . . . . December 5, 1994
Company Service: December, 1994
W. Wayne Brown, Age 44
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 and Treasurer, Service Telecommunications Co. . . . . . . . . . . . . February 8, 1991
Secretary, Fuel Resources Development Co. . . . . . . . . . . . . . . . . . . . January 27, 1994
Secretary, WestGas Interstate, Inc. . . . . . . . . . . . . . . . . . . . . . . May 2, 1994
Secretary, WestGas TransColorado, Inc. . . . . . . . . . . . . . . . . . . . . . May 2, 1994
Secretary, e prime. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . January 30, 1995
Company Service: June, 1972
A. Clegg Crawford, Age 62
Vice President, Engineering and Operations Support . . . . . . . . . . . . . . . June 28, 1994
Company Service: May, 1989
Ross C. King, Age 53
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 54
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 45
Vice President, Production and System Operations . . . . . . . . . . . . . . . . June 28, 1994
Company Service: July, 1978
Philip D. Shaffer, Age 49
Vice President, Wholesale Energy Services . . . . . . . . . . . . . . . . . . . June 28, 1994
Company Service: February, 1966
Marilyn E. Taylor, Age 52
87
Vice President, Human Resources . . . . . . . . . . . . . . . . . . . . . . . . June 28, 1994
Company Service: December, 1987
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, 1990:
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 Communication
and Treasurer;
Mr. Shaffer has been President, Cheyenne Light, Fuel and Power Company and
Vice President, Division Customer Operations;
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 1995
Proxy Statement, which information is incorporated herein by reference.
88
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 1995 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 1995 Proxy
Statement, which information is incorporated herein by reference.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) Financial Statements, Financial Statement Schedules, and Exhibits.
Page
1. Financial Statements:
Report of Independent Public Accountants . . . . . . . . . . . . . . 32
Consolidated Balance Sheets, December 31, 1994 and 1993 . . . . . . 33
Consolidated Statements of Income for each of the three
years in the period ended December 31, 1994 . . . . . . . . . 35
Consolidated Statements of Shareholders' Equity for each
of the three years in the period ended December 31, 1994 . . . 36
Consolidated Statements of Cash Flows for each of the three
years in the period ended December 31, 1994 . . . . . . . . . 37
Notes to Consolidated Financial Statements . . . . . . . . . . . . . 38
2. Financial Statement Schedules:
II Valuation and Qualifying Accounts and Reserves
(Consolidated) for each of the three years in the period
ended December 31, 1994 . . . . . . . . . . . . . . . . . . . 66
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.
89
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 . . . . . . . . . . . . . 77
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 October 25, 1994, was filed on October
27, 1994. The items reported were Item 5. Other Events - Fort St. Vrain
and Income Taxes and Item 7. Financial Statements and Exhibits, which
presented information regarding third quarter earnings.
90
EXPERTS
The consolidated balance sheets of the Company and its subsidiaries
as of December 31, 1994 and 1993, the related consolidated statements of
income, shareholders' equity and cash flows for each of the three years in
the period ended December 31, 1994, 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,
1994, 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. Reference is made to
said report which includes an explanatory paragraph that describes
uncertainties discussed in Note 2 to the consolidated financial statements
relating to the Company's Fort St. Vrain Nuclear Generating Station. 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 reports.
91
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.
33-42442) pertaining to the Automatic Dividend Reinvestment and Common
Stock Purchase Plan; the Company's Registration Statement (Form S-3, File
No. 33-37431), as amended on December 4, 1990, pertaining to the shelf
registration of the Company's First Mortgage Bonds; the Company's
Registration Statement (Form S-8, File No. 33-55432) pertaining to the
Omnibus Incentive Plan; the Company's Registration Statement (Form S-3,
File No. 33-51167) pertaining to the shelf registration of the Company's
First Collateral Trust Bonds and the Company's Registration Statement
(Form S-3, File No. 33-54877) pertaining to the shelf registration of the
Company's First Collateral Trust Bonds and Cumulative Preferred Stock and
to all references to our Firm included in this Form 10-K.
ARTHUR ANDERSEN LLP
Denver, Colorado
February 27, 1995
EXHIBIT 24
POWER OF ATTORNEY
Each director and/or officer of Public Service Company of Colorado
whose signature appears herein hereby appoints D. D. Hock 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.
92
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 28th day of February, 1995.
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/D. D. Hock
__________________________________ Principal Executive
D. D. Hock Officer and Director
Chairman of the Board
and Chief Executive Officer
/s/R. C. Kelly
__________________________________ Principal Financial Officer February 28, 1995
R. C. Kelly
Senior Vice President,
Finance, Treasurer and
Chief Financial Officer
/s/W. Wayne Brown
__________________________________ Principal Accounting Officer
W. Wayne Brown
Controller and Corporate Secretary
93
Signature Title Date
_________________________________________________________________________________________
/s/Wayne H. Brunetti
__________________________________
Wayne H. Brunetti
/s/Collis P. Chandler Jr.
__________________________________
Collis P. Chandler, Jr.
/s/Doris M. Drury
__________________________________
Doris M. Drury
/s/Thomas T. Farley
__________________________________
Thomas T. Farley
/s/Gayle L. Greer
__________________________________
Gayle L. Greer
__________________________________
A. Barry Hirschfeld
/s/George B. McKinley
__________________________________
George B. McKinley Director February 28, 1995
__________________________________
Will F. Nicholson, Jr.
/s/J. Michael Powers
__________________________________
J. Michael Powers
/s/Thomas E. Rodriguez
__________________________________
Thomas E. Rodriguez
__________________________________
Rodney E. Slifer
94
/s/W. Thomas Stephens
__________________________________
W. Thomas Stephens
/s/Robert G. Tointon
__________________________________
Robert G. Tointon
95
EXHIBIT INDEX
3(a)* Restated Articles of Incorporation of the Registrant dated July 9,
1990 (10-K, 1990 - Exhibit 3(a)).
3(b)* By-laws dated November 30, 1992 (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)
96
May 1, 1966 8-K, May 1966 2 November 1, 1993 S-3, (33-51167) 4(a)(3)
July 1, 1967 8-K, July 1967 2 January 1, 1994 10-K, 1993 4(a)(3)
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)* Indenture 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)
4(c)* 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).
10(a)(1)* Contract dated July 1, 1965 between the Registrant, United
States Atomic Energy Commission and General Dynamics
Corporation (Form S-7, File No. 2-24772 - Exhibit 4(g)).
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(b)* Agreement for Disposal of Spent Nuclear Fuel and/or High-Level
Radioactive Waste dated June 24, 1983 between the Registrant
and the United States Department of Energy (10-K, 1983 -
Exhibit 10(b)(2)).
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)).
97
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)(2)*+ Supplemental Executive Retirement Plan for Key Management
Employees, as amended and restated March 26, 1991 (10-K,
1991 - Exhibit 10(e)(2)).
10(e)(3)*+ Omnibus Incentive Plan (1992 Proxy Statement - Exhibit A).
10(e)(5)*+ Executive Savings Plan (10-K, 1991 - Exhibit 10(e)(5)).
10(e)(6)*+ Form of Key Executive Severance Agreement (10-K, 1991 -
Exhibit 10(e)(6)).
10(f)(1)*+ Form of Director's Agreement (10-K, 1987 - Exhibit 10(f)(1)).
10(f)(2)*+ Form of Officer's Agreement (10-K, 1987 - Exhibit 10(f)(2)).
10(g)(1)*+ Employment Agreement dated April 8, 1994 between the Company
and Mr. Delwin D. Hock
(10-Q, March 31, 1994 - Exhibit 10).
10(g)(2)*+ Employment Agreement dated July 18, 1994 between the Company
and Mr. Wayne H. Brunetti (10-Q, September 30, 1994 - Exhibit
10).
10(g)(3)+ Employment Agreement dated December 5, 1994 between the
Company and Ms. Patricia T. Smith.
12(a) Computation of Ratio of Consolidated Earnings to Consolidated
Fixed Charges is set forth at page 67 herein.
12(b) Computation of Ratio of Consolidated Earnings to Consolidated
Combined Fixed Charges and Preferred Stock Dividends is set
forth at page 68 herein.
21 Subsidiaries
23 The Consent of Arthur Andersen LLP is set forth at page 74
herein.
24 Power of Attorney is set forth at page 74 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.
98