ML20137S611
| ML20137S611 | |
| Person / Time | |
|---|---|
| Site: | Fort Saint Vrain  |
| Issue date: | 12/31/1996 |
| From: | PUBLIC SERVICE CO. OF COLORADO |
| To: | |
| References | |
| NUDOCS 9704150191 | |
| Download: ML20137S611 (96) | |
Text
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Fcrm 10-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549
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[* ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
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SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31,1996 OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period fmm to Commission file number 1-3280 Public Service Company of Colorado (Exact name of registrant as specified in its charter)
Colorado 84-0296600 l
(State or otherjurisdiction of (IRS Employer incorporation or organization)
Identification No.)
122517th Street, Denver, Colorado 80202 j
(Address of principkl executive offices)
(Zip Code)
Registrant's Telephone Number, including area <.sde: (303) 571-7511 Securities Registered Putsuant 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 Putthase Common Stock New York, Chicago and Pacific Cumulative Preferred Stock, par value $100 per share
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f 41/4 Series American 7.15% Series New York Cumulative Prefetud Stock ($25), par value per shate 8.40% Series New York Secur: ties Rgistetid Pursuant to Section 12(g) of the Act:
Canulative Pnfmed 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 regutrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /
No Indicate by check mark if disclosure of delinquent filers pursuant tr, item 405 of Regulation S-K is not he contained, to the best of registrant's knowledge, in definitive proxy or contamed herein, and wiB 5 t information statements incorpo,oted by reference in Part til of this Form 10-K or any amendment to this Form i
10-K. [ ]
The aggregate market value of the registrant's Common Stock, $5.00 par value (the only class of voting stock), held by non-affiliates was $2,536,745,052 based on the last sale price thereof reported on the consolidated tape for February 21,1997.
At February 21,1997,65,253,892 shares of the registrant's Common Stock, $5.00 par value (the only class of common stock), were outstanding.
Documents incorporated by Reference Portions of the registrant's 1997 Proxy Statement are incorporated by reference in Part 11, item 9 and Part III, itsens 10,11,12 and 13 of this Form 10-K.
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4 e-n n rs n 9704150191 961231 ADOCK0500g7 lII,E%ll%%%%%,EE PDR
4 Attention ENCLOSED IS THE PUBLIC SERVICE COMPANY OF COLORADO'S 1996 FORM 10-K WHICH PROVIDES AN IN-DEPTH OPERATIONAL AND FINANCIAL REVIEW OF THE COMPANY. IN LIGHT OF THE ANTICIPATED TIMING OF MERGER COMPLETION, THE 10-K IS BEING PROVIDED IN LIEU OF THE CUSTOMARY ANNUAL REPORT TO SHAREHOLDERS THIS YEAR.
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Table of Contents i
PARTI Item 1. Business..
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'Ihe Company........................
1 Cheyenne & WGI....................
2 e prime and subsidiaries....................................
2 Other Subsidiaries........................
2 Electric Operations.....
2 Peak lead.............................................
3 Purchased Power.
3 Construction Program..............
5 Electric Fuel Supply...........................
5 Coal.......................................................................
6 Natural Gas and Fuel Oil....................................
7 Natural G as Ope rations......................
8 Natural Gas Supply and Storage........
8 Regulation and Rates.
8 M e rger Rate Filin gs........................................
9 State Regulation.......................
9 CPUC........
9 Gas Rate Case...
9 Electric and Gas Adjustment Clause 6...
9 Incentive Regulation and Demand Side Management....
10 IRP - Electric.
10 WPSC...
10 Federal Energy Regulatory Commission.........................................
10 Environmental Matters....
I1 Co mpet it ion...................................
12 I n d ust ry Outlook....................................................................................... 12 State Regulatory Environment........
12 Electric................
13 Natural Gas.
13 Franchisca......
13 Employees & Union Contracts..................
13 Research and Development..
14 Consolidated Electric Operating Statistics..
1" Consolidated Gas Operating Statistics......
16 Electric Transmission Map......................
17 Item 2. Properties..........
I8 Electric Generation Property..
18 Nuclear Generation Property....
18 Electric Transmission and Distribution Property...
18 Gas Property.......
19 Other Property...
19 Property of Subsidiaries..
20 Character of Ownership.....
20 item 3. legal Proceedings....
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l Item 4. Submission of Matters to a Vote of Security Holders.......
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PARTII Item 5. Market for Registrant's Common Equity and Related Stockholder Matters......
............. 21 Item 6. Selected Financial Data..........
... 22 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 23 Ind u st ry Outl ook.................................................................................... 23 Co rpo rate Ov e rvi ew...........................................................................
23 Recen t De velo p men ts.................................................................................................. 24 Earnings.............................................................................................25 El ect ri c Ope rat i on s............................................................................................. 25 GasOperations..........................................................................................
..... 27 Non-Fuel Operating Ex penses........................................................................................ 28 Financ ial Po s i ti on..................................................................................... 29 Commitments and Contingencies..
....... 29 Common Stock Div i dend............................................................................... 29 Liq uidity and Capi tal Resources................................................................................ 29 Cash Flow s.................
29 Prospective Capital Require ments.............................................
.........30 Capital Sources....................................
3i Registration Statements..................................................
3i Company 's Inden tures.......................................................................... 31 Company's Restated Articles ofIncorporation..........
...................32 Short-Term Borrowing Arrangements..................
32 Item 8. Financial Statements and Supplementary Data..........
...............................33 Report of Audit Committee of the Board of Directors..
...........................33 Report of Management..........
................34 Report o f Independent Public Accountants........................................................................ 35 Consolidated Balance Sheets.,.................................................................... 36 Consolidated Statements of Income....................................
..........................38 Consolidated Statements of Shareholders' Equity...........
.........................39 Consolidated Statements o f Cash Flows.........................................................
...............40 Notes to Consolidated Financial Statements.........................,...
.......................41 Schedule II............
..............................................................................69 Exhibit 12(a).......................................................................................,.........70 Exhibit 12(b)............................................................................................
71 Exhi bit 99.............................
............72 Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......... 78 i
i PARTIll item 10. Directors and Executive Officers of the Registrant.....
,. 78 i
Item i1. Executive Compensation..
81 I
l item 12. Security Ownership of Certain Beneficial Owners and Management..
. 81 H
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Item 13. Certain Relationships and Related Transactions............................................................. 81 j
I PART IV 1
Item I4. Exhibits, Financial Statement Schedules and Reports on Form 8-K.....
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Experts......................................................................................................................83 Consent of Independent Public Accountants............................................................................. 84 Pow er of A ttorney.......................................................................................................... 84 l
Signatures.........................................................................................................
85 Exhibitindex...........................................................................................
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In' addition to the historical information contained herein, this report contains a number of " forward-looking i
statements", within the meaning of the Securities Exchange Act of 1934. Such statements address future events and conditions concerning capital expenditures, resolution and impact of litigation, regulatory matters, liquidity and capital resources, and accounting matters. Actual results in each case could differ materially from those projected in such statements due to a variety of factors including, without limitation, restructuring of the u.tility industry; future economic conditions; earnings retention and dividend payout policies; developments in the j
legislative, regulatory and competitive environments in which the Company operates; and other circumstances that
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could affect anticipated revenues and costs, such as compliance with laws and regulations. There and other l
factors are discussed in the Company's filings with the Securities ar.d Exchange Commission including this report.
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TERMS The abbreviations or acronyms used in the text and notes are defined below:
Term Abbreviation or Acronym
.. American Electric Power AEP.......................
.......... Allowance for Funds Used During Construction AFDC.................
... Accounting Principles Board Opinion No. 25 APB Opinion No. 25............
" Accounting for Stock issued to Employees"
... Amax Coal Company, a subsidiary of Cyprus /Amax Coal Company
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..Arapahoe Steam Electric Generating Station Amax.
Arapahoe..
...... Bureau of Land Management BLM....
...... Cameo Steam Electric Generating Station
. Clean Coal Technology 111 Cameo CCT3.
............ Comprehensive Environmental Response, Compensation and Liability Act CERCLA........
.. Cherokee Steam Electric Generating Station Cherokee.
..... Cheyenne Light, Fuel and Power Company Cheyenne..
... Corporate-owned life insurance COLI.......
.. Supreme Court of the State of Colorado Colorado Supreme Court.
.......... Comanche Steam Electric Generating Station Comanche...................
.. Public Service Company of Colorado (excluding subsidiaries)
Company or PSCo...
..... Cenificate of Public Convenience and Necessity CPCN........
.Public Utilities Commission of the State of Colorado CPUC..
... Craig Steam Electric Generating Station Craig.
., Construction Work in Progress CWIP...................
..... Colorado Water Quality Control Division CWQCD....
... District Court in and for the City and County of Denver Denver District Court.
. U.S. Department of Energy DOE......
..... Demand Side Management DSM...
....,. Demand Side Management Cost Adjustment DSMCA............
....Dekatherm Dth..
. e prime, inc.
a prime.
.. Energy Cost Adjustment EC A.....
. Environmental Impact Statement EIS.
..... National Energy Policy Act of 1992 EPAct.,.
. U.S. Environmental Protection Agency EPA..
.. Exempt Wholesale Generator EWG...................
. Financial Accounting Standards Board F AS B...........
. Federal Energy Regulatory Commission FERC......
..FERC Order Nos. 636-A and 636-B FERC Order 636..
. Fort St. Vrain Nuclear Electric Generating Station Fort St. Vrain
.. Fuel Rest'irces Development Co., a dissolved Colorado corporation Fuelco
. Gas Cost Adjustment GCA.................
..Hayden Steam Electric Generating Station Hayden
. IBM Global Services IBM.
.... Incentive Cost Adjustment ICA.....
.... Colorado Interstate Gas Company Interstate.
.. Independent Power Production Facility IPPF
.... Integrated Resource Plan IRP.....
.. Internal Revenue Service IRS...
.. Independent Spent Fuel Storage Installation
'sFSI..
. KN Energy, Inc.
KN Energy..
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, Merger........................................... the proposed business combination between the Company and SPS l
Merger Agreement............................................... Agreement and Plan of Reorganization by and among l
the Company, SPS. and NCE, as amended Natural Fuels...............
. Natural Fuels Corporation N C E................................................................................... New Century Energies, I nc.
l N O PR.............................................................................. Notice of Proposed Rule mak in g l
N O x................................................................................................... N i t rogen o xid e NRC......................................
... Nuclear Regulatory Commission OCC........................................................................... Colorado O ffice of Consumer Counsel OPEB.................................................................. Other Postretirement Employee Benefits PCB.............................
.................................... Polychlorinated biphenyl Pawnee........................................................ Pawnee Steam Electric Generating Station Pawnee 2........................................ Pawnee Steam Electric Generating Station, Unit 2 (proposed)
Poo!........................
. Inland Power Pool PR Ps.....................
...... Potentially Responsible Parties PSCCC.............
.............................. PS Colorado Credit Corporation PSRI....
....PSR Investments, Inc.
PUH CA.................................................................. Public U tility Holding Company Act of 1935 Q F......
.............. Qualifying Facility
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Q FCCA........
........................................ Qualifying Facilities capacity Cost Adjustment
.... Quality of Service Plan QSP....................
S EC............................................................................. Securities and Exchange Commission S FA S 71................................................. Statement of Financial Accounting Standards No. 71 -
" Accounting for the Effects of Certain Types of Regulation" S FAS 106........................
............... Statement of Financial Accounting Standards No.106 -
" Employers' Accounting for Postretirement Benefits Other Han Pensions" SFAS 107.........
..................................... Statement of Financial Accounting Standards No.107 -
" Disclosures about Fair Value of Financial Instruments" S F A S 109....................................
....... Statement of Financial Accounting Standards No.109 -
" Accounting for locome Taxes" S FA S 1 12...................................
........ Statement of Financial Accounting Standards No. I12 -
" Employers' Accounting for Postemp oyment Benefits
- i S FA S 121..................................
....... Statement of Financial Accounting Sta,dsrds No.121 -
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" Accounting for the impairment of Long-Lived Assets and long-Lived Assets to be Disposed of" S FA S 123........................
........... Statement of Financial Accounting Standards No.123 -
" Accounting for Stock-Based Coma
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SO2............
.............. S ul fu,
le SPS.........................................~......................
... Southwestern Public Service Company TOG...............................................................
........ Texas-Ohio Gas, Inc.
TOP................................
.. Texas-Ohio Pipeline. Inc.
Tri-State.................................................. Tri-State Generation and Transmission Association. Inc.
UK.................
..... United Kingdom Valmont....................................................
........Valmont Steam Electric Generating Station WGG....................
........WestGas Gathering, Inc.
WGI.........................
............ WestGas Interstate. Inc.
i WGT....................
.....WestGas TransColorado, Inc.
WPSC...............................................
Public Service Commission of Wyoming 3
WSCC..............
................. Western Systems Coordinating Council
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Young Storage.
... Young Gas Storage Company, Ltd.
YG SC................
... Young Gas Storage Company Yorkshire Electricity.......................
... Yorkshire Electricity Group ple l
Yorkshire Holdings..............
.. Yorkshire Holdings plc l
Yorkshire Power.......
....Yorkshire Power Group Ltd.
Zuni
.. Zuni Steam Electric Generating Station V
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PARTI i
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Etem i. Business
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The Company l
l ihe Company, incorporated through merger of predecessors under the laws of the State of Colorado in l
1924, is an operating public utility engaged, together with its subsidiaries, principally in the generation, purchase, l
transmission, distribution and sale of electricity and in the purchase, transmission, distribution, sale and transportation of natural gs -
I'he Company provides electricity or gas or both in an area having an estimated population of 3.0 million people of which approximately 2.1 million are in the Denver metropolitan area. The Company's operations are wholly within the State of Colorado.
On August 22, 1995, the Company, SPS, a New Mexico corporation, and NCE, a newly formed Delaware corporation, entered into a Merger Agreement providing for a business combination rs peer firms involving the Company and SPS in a " merger of equals" transaction. As part of the agreement, NCE would become the parent company for the Company and SPS. On January 30,1996, NCE filed its application with the l
SEC to be a registered public utility holding company. The shareholders of the Company and SPS approved the Merger Agreement on January 31,1996. The Merger is subject to customary closing conditions, including the receipt of all necessary govemmental approvals and the making of all necessary governmental filings, as discussed in Note 3. Merger and Note 9. Commitment and Contingencies - Regulatory Matters in Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. The future operations and financial position of the Company will be i
significantly affected by the Merger. See the information in item 7. M ANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDirlON AND RESULTS OF OPERATIONS and the unaudited pro forma financial information for l
NCE included in this report - Exhibit 99.
On February 24,1997, the Company and AEPjointly announced that they have reached agreement with the board of directors of Yorkshire Electricity, a UK regional electricity company, on the terms of a recommended cash tender offer for all of the outstanding and to be issued ordinary shares of Yorkshire Electricity (the " Proposed Acquisition"). The Company and AEP, through a joint venture named Yorkshire Holdings, are offering the equivalent of US $15.02 (9.27 pounds) per ordinary share, for a total purchase price of approximately US $2.4 billion (1.5 billion pounds). The boards of directors of the Company and AEP have approved the transaction. The board of directors of Yorkshire Electricity has agreed to recommend the offer to Yorkshire Electricity's shareholders. Consummation of the Proposed Acquisition is subject to customary conditions in the UK, including regulatory clearance and acceptance of the offer by holders of at least 90% of the outstanding shares of Yorkshire Electricity. Yorkshire Holdings may waive the latter condition when it has received acceptances of its offer and has otherwise acquired shares which in total represent more that. 50% of the outstanding shares of Yorkshire Electricity. The Company cannot predict at this time whether or not these conditions will be met or waived.
See "Recent Developments" in item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL j,
CONDTTION AND RESULTS OF OPERATIONS and Note 4. Acquisition and Divestiture of Investments - Proposed Acquisition of Yorkshire Electricity in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
As of December 31,1996, the Company owned all of the outstanding capital stock of Cheyenne, WGI, e prime,1480 Welton, Inc., PSRI, PSCCC, Green and Clear lakes Company and Fuelco (a dissolved corporation).
In addition, the Company owned 83.63% of the capital stock of Natural Fuels and e prime owned all of the outstanding capital stock of TOG, TOP and YGSC. These subsidiaries are included in the Company's consolidated financial statements. The Company also holds a controlling interest in several other relatively small ditch and water companies whose capital requirements are not significant and which are not consolidated in the Company's financial statements or statistical data.
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information regarding industry segments is set forth in Note 14. Segments of Business in Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Cheyenne and WGI Cheyenne is an operating utility engaged in the purchase, distribution and sale of electri d in gas primarily serving customers in Cheyenne, Wyoming. WG1 is a natural gas transmission compa ff Colorado transporting gas to Cheyenne, Wyoming via a thirteen mile connecting pipeline between Chalk B and Cheyenne, Wyoming. Gas transportation volumes were approximately 3.4 million Dth for 1996 e prime and subsidiaries e prime, wuh headquarters in Denver and an office in Tulsa, was established in 1995 an brokering and energy related produas and services which include, bar are not li On March 29,1996, e based services. e prime is also pursuing international energy investment opportunities.
prime received authorization from the FERC to act as a power marketer. Effective Septe Company and e prime acquired TOG, a gas marketing compa TOG have merged operations and together they provide value-added energy related products e prime also acquired TOP on September 1,1996, a small pipeline use customers and utilities nationwide, company which connects two major interstate pipelines. TOP is subject to FERC regula its subsidiary, e prime are also developing the necessary policies and procedures to enable it to use derivative financial instruments in its electric and gas brokering and marketing activities.
e prime owns a 50% general partnership interest in the Johnstown Cogeneration Co In addition, e prime acquired a 50%
produces electric energy that is sold to PSCo under a 30 year contract. li YGSC, a subsidiary of e prime, owns a 47.5% general partnership interest in Young Storage. Y Storage owns and operates an underground gas storage facility in northeastern Colorado to FERC regulation.
Other Subsidiaries 1480 Welton, Inc. is a real estate company which owns certain of the Company's real estate intere PSRI owns and manages permanent life insurance policies on cenain past and prescnt emp o i
from which are to provide future funding for general corporate purposes; PSCCC is a finance c finances certain of the Company's current assets: Green and Clear Lakes Company owns water Natural Fuels sells compressed facilities for water used at the Company's Georgetown Hydroelectric Station:
natural gas as a transportation fuel to retail markets, converts vehicles for natural gas usag facilities and sells miscellaneous fueling facility equipment. On July 1,1996, Fuelco, which wa involved in the exploration and production of oil and natural gas, sold its remaining properties, Effective October 31, 1996, Fuelco was Basin Coal Bed Methane properties, at approximately book value.
dissolved. (See Note 4. Acquisition and Divestiture of Investments in item 8. FINANCIAL STATEM SUPPLEMENTARY DATA).
Electric Operations The Company proposes tu use the following resources to meet its net dependable system Company's electric generating stations (see Electric Generatio alternatives, including the phased repowering of Fort St. Vrain. Additional planned resources l
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.t e Company s proposed IRP, which was filed with the CPUC in October 1996 (see " Regulation and Rates -
h State Regulation - IRP - Electric").
Peak Load During 1997, net firm system peak demand for the Company and Cheyenne is estimated to be 4,413 Mw, assuming normal weather conditions. Net dependable system capacity is projected to be, after accounting for 68 Mw of demand-side management options,5,127 Mw (generating capacity of 3,304 Mw and firm purchases of 1,823 Mw) at the time of the anticipated 1997 system peak (summer season), resulting in a reserve margin of a
approximately 16%.
The net firm system peak demand for the Company and Cheyenne for each of the last five years was as follows:
1992 1993 1994 1995 I996 Net Firm System Peak Demand * (Mw)...
3,757 3,869 3,972 4,248 4,397 Excludes station housepower, nonfirm electric fumace load and controlled interruptible loads (of which approximately 156 Mw,164 Mw,160 Mw,148 Mw and 122 Mw in the years 1992-1996, respectively, was not interrupted at the time of the system peak).
The net firm system peak demand for the Company and Cheyenne for the years 1992-1996 occurred in the summer. 'Ihe net firm system peak demand for 1996, which occurred on August 13,1996, was 4,397 Mw.
At that time, the net dependable system capacity totaled 5,103 Mw (generating capacity of 3,314 Mw, together with firm purchases of 1,789 Mw), which represented a reserve margin of approximately 16%. Net dependable system capacity is the maximum net capacity available from both Company-owned generating units and purchased power contracts to meet the net firm system peak demand.
Purrhased Power
'Ihe 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.
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The Company and Cheyenne have contracted with the following sources for the firm purchase of capacity and energy at the time of the anticipated summer 1997 net firm systert peak demand through the expiration of the contracts:
Mw Contracted For at the Time of the Anticipated Generating Summer 1997 Net Firm Contract Comriany Source System Peak Demand Emiration Basin Electric Power Cooperative, Laramie River Station Agreements 1 and 2 (a)(b)
Units 2 and 3 175 2016 PacifiCorp (c)
PacifiCorp System 140 2000 Pacificorp (d)
PacifiCorp Resource Pool 176 2011 Plane River Power Authority (a)(c)
Craig Units 1 and 2; ISO 2004 Rawhide Unit 1 Tri-State 525 (O
Agreements 1,2,3 and 4 (a)(O Laramie River Station Units 2 and 3; Craig Units 1,2 and 3 Agreement 5 (a) (O Laramie River Station Units 2 and 3; Craig Units 1,2 and 3; Nucia Units 1,2,3 and 4 Vanous Owners (a)
QFs & IPPF 627 Various dates 1.823 (a) These contracts are contingent upon the availability of the units listed as the generating source. These contracts are take and pay contracts. Based upon the terms of these agreements, if the capacity is available from these units, the Company is obligated to pay for capacity whether or not it takes any energy. However, the Company has historically satisfied the minimum energy requirements associated with these agreements and anticipates doing so in the future. Additionally, if these units are unavailable, the supplying company has no obligation to furnish capacity or energy and the capacity charge to the Company is reduced accordmgly.
(b) The Company has entered into two agreements with Basin Electric Power Cooperative. The first agreement is for 100 Mw of capacity through March 31, 2016. The second agreement is for 75 Mw of summer season capacity through March 31,2016 and 25 Mw of winter season capacity through March 31,2010.
(c) 'lhis contract calls for PacifiCorp to sell to Cheyenne the total electric capacity and energy requirements associated with the operation of Cheyenne's service area.
(d) The current agreement with Pacificorp expires October 31,2022. However, the agreement provides the Company the opportunity to exercise an irrevocable option to terminate the agreement on December 31, 2011, provided the Company gives notice to PacifiCorp no later than March 1,2002.
(e) The amount of capacity to be made available for each summer and winter season is agreed upon prior to such season to the extent that Platte River Power Authority has excess capacity for such season.
(O The Company has entered into Sve agreements with Tri-State. Agreements 1,2 and 5 are contracts for 100 Mw each of capacity and expire in 2001,2017 and 2011, respectively. Agreement 3 is a contract for 25 Mw of summer season capacity and 75 Mw of winter season capacity and expires in 2016. Agreement 4 expires in 2018 and the related capacity is for the following amounts: 1997 through 2000 - 200 Mw and 2001 through 2018 - 250 Mw; however, either party may elect to reduce the Agreement 4 capacity by up to 50 Mw each year, except for 2001, effective in the year 1999, if the full 50 Mw reduction is taken each year, the capacity associated with Agreement 4 from 1999 on would be as follows: 1999 - 150 Mw, 2000 through 2001 - 100 Mw, 2002 - 50 Mw with no commitments thereafter. The Company has notified Tri-State ofits intent to reduce the capacity associated with Agreement 4 to 150 Mw for 1999.
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,See Note 9. Commitments and Contingencies - Purchase Requirements in item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for information regarding the Company's financial commitments under these contracts. See Electric Transmission and Distribution Property in item 2. PROPERTIES for a discussion of the Company's interconnections with these sources.
Based on present estimates, the Company and Cheyenne will purchase approximately 37% of the total electric system energy input for 1997. In addition, based on the capacity associated with the purchase power contracts described above, approximately 36% of the total net dependable system capacity for the estimated summer 1997 net firm system peak demand for the Company and Cheyenne will be provided by purchased power, compared to approximately 35% in 1996.
In accordance with the Public Utility Regulatory Policies Act of 1978 ("PURPA"), the Company is obligated to purchase at " avoided cosit" 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 ta the fact that excess generating capacity would be created if additional contracts were executed. Although a comprehensive QF bidding procedure was adopted by the CPUC in 1988, which allowed the Company to purchase the most competitively priced QF power, all of the QF capacity purchased by the Company, including approximately 5 Mw of additional capacity scheduled to come on line in the future, is being purchased under contracts entered into prior to the adoption of such procedure. Based on the 1988 comprehensive QF bidding criteria, QFs could provide up to 20% of the Company's net firm system peak load. 'Ibe CPUC has circulated proposed new rules that would supplant the 1988 comprehensive QF bidding criteria whereby long-term future resource needs would be selected through a competitive bidding process. In 1996, approximately 15% of the Company's summer net firm system peak demand was provided by QFs.
In addition to long-term and QF and IPPF purchases, the Company also made short-term and non firm purchases throughout the year to replace generation from Company owned units which were unavailable due to maintenance and unplanned outages, to provide the Company's reserve obligation to the Pool, to obtain energy at a lower cost than that which could be produced by other resource options, including Company-owned generation and/or long-term purchase power contracts, and for various other operating requirements. Short-term and non-firm purchases accounted for approximately 3% of the Company's total energy requirement in 1996.
Based on current projections, the Company expects that purchased capacity will continue to meet a significant portion of system requirements r.t least for the remainder of the 1990s. Such purchases neither require the Company to make an investment nor afford the Company an opportunity to earn a return. Further discussion related to recovery of purchased capacity costs can be found in " Regulations and Rates - State Regulation -
Electric and Gas Adjustment Clauses".
The Company is a member of the Pool which is composed of members each of which owns and/or operates electric generation and/or transmission systems which are interconnected to one or more other member systems. The objective of the Pool is to provide capacity which is categorized as: 1) immediately accessible; 2) accessible within ten minutes; and 3) accessible within twelve hours, as required. As a result of membership in the Pool, the Company can supply and protect its electric system with less aggregate operating reserve capacity than otherwise would be necessary; emergency conditions can be met with less likelihood of curtailment or impairment of electric service; and generation and transmission facilities and interconnections can be used more efficiently and economically.
l Construction Program At December 31,1996, the Company and its subsidiaries estimated the cost of their total construction program, including AFDC, to be approximately $327 million in 1997, approximately $376 million in 1998, and 5
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approximately $300 million in 1999 (see item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDmON AND RESULTS OF OPERATIONS).
Electric Fuel Supply ne following table presents the delivered cost per million Btu of each category of fuel consumed by the system for electric generation of the Company and its utility subsidiary during the years indicated, the percentage of total fuel requirements represented by each category of fuel and the weighted average cost of all fuels during such years:
Weighted Average Coal
- Gas All Fuels **
Cost $ %
Cost $ %
Cost $
1996........
1.029 98 2.424 2
1.054 1995..
0.992 99 1.521 1
0.998 199 4....................
1.038 99 2.069 1
1.053 1993....
1.078 98 2.319 2
1.097 1992.....................
1.091 99 2.065 1
1.105 The average cost per ton of coal, including freight, for years 1992 through 1996 shown above was
$21.14, $21.03, $20.57, $19.06 and $20.17, respectively.
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- Insignificant purchases of oil are included.
Coal l
%e 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 l
and Eagle Butte Mines near Gillette, Wyoming and the Foidel Creek and Empire Energy mines in northwestern Colorado.
long-term contracts presently in existence provide for a substantial portion of future annual coal requirements. Any shortfall will be provided by purchases on the spot market. During the year ended December 31, 1996, the Company's coal requirements for existing plants were approximately 9,118,360 tons, a substantial portion of which was supplied pursuant to long-term supply contracts. Coal supply inventories at December 31, 1996 were approximately 43 days usage, based on the average peak burn rate for all the Company's coal-fired plants.
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The following table provides a summary of the basic supply provisions of the existing long-term contracts', which provide a minimum delivery of approximately 78 million tons of low-sulfur coal over their l
remaining life (see Note 9. Commitments and Contingencies - Purchase Requirements in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ).
j Minimum Maximum Contract l
delivery delivery maximum per contract year per contract year sulfur
{
Coal Supplier and Delivery Year in tons in tons content s
l Amax (1)
~
0.50%
l 1988 through Pawnee 2 completion...........................
3,960,000 (2)
Pawnee 2 completion through 2013............................
3,600,000 (3) 0.50 %
Colowyo Coal Company 1992 through 2017.............................................
79,429 (4)
"'9,429 0.70 %
Cyprus Coal Company j
1988 through 1997.......
1,700,000 1,900,000 0.60 %
Mountain Coal Company 199 3 through 2000...........................................
600,000 (5) 800,000 0.67 %
Powderhorn Coal Company 1995 through 1999........................
150,000 350,000 0.69 %
Seneca Coals, Ltd (6) 1992 throu gh 2004..............................................
439,800 (7) 1.00 %
[
Trapper Mining, Inc.
I 1992 through 2014.........................
189,108 (8) 189,108 (9)
(1) De contract term is completed upon delivery of 144,843,970 tons regardless of the year in which delivery is completed.
From January 1,1976 through December 31,1996,79,573,842 tons have been delivered.
(2) Coal requirements of Comanche and Pawnee, (3) Coal requirements of Pawnee and Pawnee 2.
(4) De contract minimum quantity varies by year during the agreement from 79,429 tons in 1996 to 124,810 tons in 2017.
f (5) De contract term is completed on December 31,2000 or upon delivery of 3,200,000 tons. As of December 31,1996, j
2,181,740 tons have been delivered.
(6) He contract term is completed upon total delivery of 31,250,000 tons to Hayden from and arter January 1,1983. As of December 31,1996,20,604,164 tons have been delivered. Delivery is expected to be completed in the year 2004.
(7) Coal requirements of Hayden.
7 (8) The contract minimum quantity varies by year during the agreement from 189,108 tons in 1996 to 440,621 tons in 2014.
(9) Not specified in the contract.
Each coal contract contains adjustment clauses which permit periodic price increases or decreases. See Note 9.
Commitments and Contingencies - Purchase Requirements in item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for information regarding the Company's financial commitments under these contracts as well as coal transportation contracts.
[
t NaturalGas and FuelOil l
t The Company uses both firm and interruptible natural gas and standby oil in combustion turbines and t
certain boilers. Natural gas supplies for the Company's power plants are procured under short-term contracts on a competitive basis to provide an adequate supply of fuel.
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Natural Gas Operations During the period 1992 1996, PSco and Cheyenne have experienced growth in the number of residential and commercial customers ranging from 1.4% to 3.4% annually. Since 1992, residential and cotamercial gas j
volumes sold have averaged 131.9 million dekatherms ("MMDth") annually. The growth of residential and commercial sales has steadily improved due primarily to stronger economic conditions in Colorado and Wyoming.
1 Growth of commercial customers has been impacted by large commercial customers selecting to purchase gas directly from suppliers. PSCo and Cheyenne transport gas through their transmission and distribution facilities for large commercial and industrial customers which purchase gas directly from suppliers. Fees for transportation services, which are paid by these customers, substantially offset the effect on net income of the revenue loss from decreased sales of gas to these customers. During 1996, transportation services generated revenues of $28.5 million compared to $23.8 million in 1995 and $23.5 million in 1994.
%e Company recognizes that the divestiture of its existing gas business or certain n< -utility ventures is a possibility under the new registered holding company structure proposed as part of the merger wnu SPS (see Note 3.
Merger in item 8. FtNANCtAL STATEMENTS AND SUPPLEMENTAPY DATA). He Company is seeking approval from the SEC to maintain these businesses and currently does not anticipate that divestitun: will be required. If divestiture is ultimately required, the SEC has historically allowed companies sufficient time to accomplish divestitures in a manner that protects shareholder value.
For a discussion of non-regulated gas marketing operations, see information in "e prime and subsidiaries" Natural Gas Supply and Storage PSco and Cheyenne have attempted to maintain low cost, reliable natural gas supplies by optimizing a balance of long-and short-term gas purchase, firm transportation and gas storage contracts. During 1996, PSCo and Cheyenne purchased 142.2 MMDth from approximately 71 suppliers, including the following major 1
suppliers: Interstate (39.9 MMDth); Western Gas Resources (12.2 MMDth); Barrett Resources (11.4 MMDth);
Amoco Energy Trading Co. (11.3 MMDth); and PanEnergy Gas Services, Inc. (6.0 MMDth). In 1996, the average delivered cost per one thousand dekatherms ("MDth") for PSCo and Cheyenne was $2.58 compared to
$2.22 per MDth in 1995 and $2.85 per MDth in 1994. Purchased gas costs are recovered from customers through the GCA (see " Regulation and Rates - State Regulation - Electric and Gas Adjustment Clauses").
Interstate was the largest gas supplier to PSCo and Cheyenne in 1996. During 1993, PSCo and Cheyenne entered into two non-regulated supply agreements, as allowed under FERC Order 636. Under the agreement with Interstate, which covered the period from October 1,1993 through September 30,1996, the annual quantities purchased declined from 46 MMDth in the first year to 34 MMDth in the second year and declined to 23 MMDth in the third year. Under the agreement with KN Gas Supply Services, Inc., which covered the period from September 1,1993 through August 31,1996, the annual quantities to be purchased were fixed at 4 MMDth. During 1996, PSCo and Cheyenne entered into new contracts with Interstate and others for firm transportation and gas storage services with terms of 5-7 years. Adequate supplies of natural gas are currently available for delivery within the Rocky Mountain region. PSCo and Cheyenne continually evaluate the natural gas market and procure supplies, as needed, te meet current and anticipated customer demand.
Regulation and Rates He 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 thejurisdiction 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. Ahhough the Company is a holding company" under the PUHCA, it has filed an annual exemption statement pursuant to Rule 2 of the SEC under that Act and is, therefore, currently exempt from all of the provisions of such Act and the Rules thereunder, except Section 9(a)(2) thereof. Such 8
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exemption is subject to termination under Rule 6 of PUHCA. On January 30,1996, as part of the Merger of the Companf with SPS, NCE filed its application with the SEC to be a registered public utility holding company, which would subject the Company and its subsidiaries to regulation under PUHCA (see "Recent Developments" in Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDTTION AND RESULTS OF OPERATIONS).
He 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. WG1 and TOP cach hold a FERC certificate which allows them to transport natural gas in interstate commerce pursuant to the provisions of the Natural Gas Act. WGI and TOP are subject to FERC jurisdiction. e prime and TOG have authorization from FERC to act as power marketers.
Merger Rate Filings See Note 3. Merger and Note 9, Commcnents and Contingencies - Regulatory Matters - Merger Rate Filings in item 8. FIN ANCIAL STATEMENTS AND SUl?LEMENTARY DATA.
State Regulation CPUC He CPUC consists of three full-time members appointed by the Governor and approved by the Colorado Senate. Only two members may be from the same political party.
In 1996, the CPUC opened en inquiry docket related to electric utility restructuring. He Company submitted a response to a CPUC sponsored restructuring questionnaire which was followed by the CPUC issuing a summary of all responses. The CPUC is currently working with the Colorado General Assembly in its investigation and implementation of public policy.
Gas Rate Case See Note 9.
Commitments and Contingencies - Rate Case in Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Electric and Gas Adjustment Clauses At December 31,1996, the Company has four adjustment clauses: the ICA (which replaced the ECA),
GCA, DSMCA and QFCCA. These adjustment clauses allow certain costs to be passed through to retail customers. He Company and Cheyenne are required to file applications with their respective state regulatory commissions for approval of adjustment mechanisms in advance of the proposed effective date. The applications must be acted upon before becoming effective.
During 1994 and 1995, the CPUC conducted several proceedings to review issues related to the ECA. He CPUC opened a docket to review whether the ECA should be maintained in its present form, altered or eliminated, and on January 8,1996, combined this docket with the Merger docket discussed in Note 9.
Commitments and Contingencies - Regulatory Matters - Merger Rate Filings in item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. The CPUC decision on the Merger modified and replaced the ECA with the ICA. De ICA, c
which became effective October 1,1996, allows for a 50%/50% sharing of certain fuel and energy cost increases and decreases among customers and shareholders.
I
%e 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 i and otherwise as needed, to coincide with changes in purchased gas costs. Purchased gas costs and l
l 9
revenues received to recover such gas costs are compared on a monthly basis and differences, including in are deferred.
He CPUC has had an on-going docket to review the status of the GCA and will determine whether it should be maintained in its present form, altered or eliminated. He CPUC conducted hearings regarding this matter on Februuy 14,1997. Additional hearings have been scheduled for March 7,1997.
He QFCCA was implemented on December 1,1993. Under the QFCCA, all purchased capacity costs The DSMCA is discussed from new QF projects, not otherwise reflected in base electric rates, are recoverable.
below in " Incentive Regulation and Demand Side Management".
Inantire Regulation and Demand Side Management
%e Company, in a collaborative process with public interest groups, consumers and industry, has developed DSM programs (programs designed to reduce peak electricity demand, shift on-peak demand to off-peak hours and provide for mcre efficient operation of the electric generation system), including incentive and cost recovery mechanisms. He CPUC approved the programs in 1993 along with a schedule to be implemented over a three-year period. Effective July 1,1993, the Company implemented a DSMCA clause which permits it to recover deferred DSM costs over seven years while non-labor incremental expenses, carrying costs associated with deferred DSM costs and certain incentives associated with the approved DSM programs are recovered on an annual basis.
Ho CPUC subsequently opened a separate docket to investigate issues involving alternative annual revenne reconciliation mechanisms and incentive mechanisms related to the Company's DSM programs. He investigation was completed in 1995 and a final order was issued. He major provisions of the final order, effective December 27,1995, included: 1) not to pmceed with any of the pro;xised mechanisms; 2) to nxluce the recovery period for certain costs of the Company's DSM prognuns from seven to five years for expenditures made on or after January 1, 1995; 3) not to estabiish DSM targets for 1997 and 1998; 4) not to adopt a penalty for failure to achieve DSM targets; and 5) to approve the Company's proposal to forego incentive payments for DSM programs.
Under a separate CPUC order issued in December 1992, the Company has implemented a low-income Energy Assistance Program, he costs of this energy conservation and weatherization program for low-income customers are recoverable through the DSMCA.
IRP - Electric ne Company filed a new IRP with the CPUC in October lo96. A final order is expected in 1997.
WPSC In June 1993, Cheyenne filed gas and electric IRPs with the WPSC pursuant to a settlement agrcement.
He WPSC has not formally acted on these filings.
ne WPSC has approved adjustment mechanisms which permit Cheyenne to recover purchased energy costs.
Federn! Energy Regulatory Commission See Note 9. Commitments and Contingencies - Regulatory Matters - Rate Cases in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for information related to the Company's FERC rate case.
Information regarding FERC Order No. 888, Order No. 889 and the NOPR on Capacity Resenation Open Access Transmission Tariffs is discussed in Note 9. Commitments and Contingencies - Regulatory Matters
- Federal Energy Regulatory Commission in Item 8. PtNANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
10
Environmental Matters Enviromnental regulations at the Federal, state and local levels, including the Clean Air Act Amendments (CAAA) of 1990 and other cnvironmental matters, are expected to have a continuing impact on the Company's operations. See Note 9. Comrnitments and Contingencies - Environmental issues in item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for a discussion of the impact on the Company of the CAAA of 1990, environmental site clean-up, and other environmental matters not discussed below. The Company continues to strive to achieve compliance with all environmental regulations currently applicable to its operations. However, it is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, generally, what effect future laws or regulations may have, upon the Company's operations.
At December 31,1996, the estimated 1997,1998 and 1999 expenditures for environmental air and water emission control facilities were $29.6 million, $43.7 million and $23.2 million, respectively. As discussed below the Company's share of estimated cost to install emission control equipment at the Hayden station for the years 1997 through 1999 is approximately $70 million.
The Company continues to research and implement various SO2 and NOx emissions reduction projects, including two CCT3 projects. He CCT3 projects are part of a larger DOE Clean Coal Program, which co-funds developing technologies aimed at more efficient and environmentally acceptable methods of burning coal.
Research and implementation continues on the two CCT3 projects, which involve Arapahoe Unit 4 and Cherokee Unit 3. Modification and testing at Cherokee Unit 3 and Arapahoe Unit 4 was conducted through 1996 and is expected to continue into 1997.
The Company is currently participating in the Northern Front Range Air Quality Study (NFRAQS), a follow-up study to the previous Metro Denver Brown Cloud Studies, which is designed to investigate the t'ormation of secondary particulates in the Denver metropolitan area. The previous study, completed in 1993, was inconclusive and did not offer any policy recommendations. He NFRAQS began field sampling in early December 19% and is expected to be completed by December 1997. Also, the EPA issued a draft particulate regulation in 1996, requesting public comments on the proposed regulation with issuance of the final regulation expected in June 1997. The Company is currently evaluating the impact of this new regulation on its operations.
He Mount Zirkel Wilderness Area ("MZWA") Reasonable Attribution Study, designed to ascertain the contribution of various emission sources to visibility impairment in the MZWA was completed in 1996. The Company is a participant in the Hayden and Craig generating stations, in the nearby Yampa Valley. The study results revealed that the Hayden and Craig Stations were minor contributors to visibility impairment in the MZWA. In May 1996, the joint owners of the Hayden station reached a settlement with a conservation organization, the Colorado Department of Public Health and Environment, and the EPA to resolve alleged air quality concerns in the Yampa Valley. The settlement, among certain other items, will result in the installation of additional emission control equipment at the Hayden station (see Note 9. Commitments and Contingencies -
Environmental issues in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
Pursuant to the requirements of the Federal Clean Water Act, as amended, and the Colorado Water Quality Control Act and regulations issued thereunder, the Company receives National Pollution Discharge Elimination System permits to discharge effluents into various streams and waters of the State of Colorado for each of its generating stations. Rese permits, which have a five-year life, are issued by the CWQCD, but are o
subject to review by the EPA. He Company believes it is presently in compliance with such discharge permits.
l Renewed wastewater discharge permits have been issued for: 1) Fort St. Vrain, effective April 1,1993; j
- 2) Cherokee, effective July 1, 1993; 3) Zuni, effective August 1, 1993; 4) Hayden, effective August 1, 1994; 5)
Valmont, effective October 1,1994; 6) Arapahoe, effective December 1, 1994; 7) Cameo, effective December 1, 1994 and 8) Comanche effective July 1,1996. A renewal wastewater discharge permit for the Leyden Gas Storage facility is expected in the first quarter of 1997. All discharge permits that are not renewed by the l
l 11
CWQCD prior to their expiration date automatically receive an administrative extension pending the isguance of a final permit.
He Company has completed the preparation of applications for Operating Permits as required by Title V of the 1990 CAAA. Permits were submitted to the state health department to meet 1996 submittal deadlines. The Company received its first Operating Permit in December 1996 for the Denver Steam Plant. The Company has applied for an early election of annual NOx emission limits for six units including Cherokee Units 3 and 4, Valmont Unit 5, Pawnec Unit 1, and Comanche Units 1 and 2. If the Company meets emission limits for these six units, as required by the early election, the Company would have until the year 2008, rather than the year 2000, to meet the lower emission limits established by Phase 11 of the CAAA.
Competition frulustry Outlook Unprecedented change is occurring in the electric utility industry nationwide, furthering the development of a coropetitive environment. In general, the economics of the electric generation business have fundamentally changed with open transmission access and the increased availability of electric supply alternatives. Such alternatives will ultimately serve to lower customer prices, particularly in areas where only higher cost energy is currently provided. Customer demands for lower prices and supplier choices, the availability of alternative supplies (IPPFs, QFs, EWGs and power marketers), and open access to the utility transmission grid have resulted in a commodity market for bulk electric supply. De EPAct directly addressed this issue by giving the FERC the authority to require utilities to provide non-discriminatory open access to the transmission grid for purposes of providing wholesale customers with direct access. In response to such authority, in early 1996, the FERC issued new rules on open access transmission services. Furthermore, an increasing number of states with above average energy prices are pursuing full competition in the electric industry, He presence of competition and the associated pressure on prices may ultimately lead to the unbundling of products and services similar to what has evolved in the natural gas industry. Today's market view of the future envisions an unbundled electric utility industry consisting of at least four major business segments: energy supply, transmission, distribution and energy services - each having a different driving force.
The SEC has also responded to increasing competition in the utility industry and chances in state and federal utility regulation. In June 1995, the SEC issued its report which focused on both iepiauw ami administrative options for the reform of public utility holding company regulation. The report presented three possible recommendations for legislative reform of PUHCA: 1) conditional repeal of PUHCA, 2) unconditional repeal of PUHCA, and 3) PUHCA remains unmodified, but grants the SEC broader exemptive authority under PUHCA. Any changes in regulation will be determined by Congress.
Further discussion can be found in Item 7. MAN AGEMENT*S DISCU$$10N AND ANALYSIS OF FINANCIAL CONDITION AND REsuLTs OF OPERATIONS.
State Regulatory Environment Colorado law permits the CPUC to authorize rates negotiatM with individual electric and gas customers which have threatened to discontinue using the services of the C.smpany, so long as the CPUC finds that such authorization: 1) in the case of electric rates, will not adversely affect the Company's remaining customers and 2) in the case of gas rates, will not affect the Company's remaining customers as adversely as would the alternative.
3 in response to the increasingly competitive operating environment for utilities, the regulatory climate is also changing. He CPUC recently issued a report on a comprehensive survey on electric industry restructuring. The Company continues to participate in regulatory proceedings which could change or impact current regulation. The Company believes it will continue to be subject to rate regulation that will allow for the recovery of all of its deferred costs (see Note 1. Summary of Significant Accounting Policies - Business and Regulation - Regulatory l
12 i
. Assets and Liabilities and Note 9. Commitments and Contingencies - Regulatory Matters in item 8. FINANCIAL STATEMENTS AND SUFPLEMENTARY DATA).
Electric ne wholesale electric business faces increasing competition in the supply of bulk power due to provisions of the EPAct and Federal.and state initiatives with respect to providing open access to utility transmission systems. Under the new FERC rules issued in early 1996, utilities are required to provide wholesale open-access transmission services consistent with what is provided for in their own operations. The Company and Cheyenne are operating with the tariffs approved by the FERC under these new rules. To date, these provisions have not had a material impact on the Company's operations. For 1996, the Company's wholesale revenues totaled approximately 8% of total electric revenues. A substantial portion of these revenues related to firm sales contracts, which are expected to continue at current levels for a minimum of to years.
Today, the retail electric business faces increasing competition from industrial and large commercial customers who have the ability to own or operate facilities to generate their own electric energy requirements. In addition, customers rmy have the option of substituting fuels, such as natural gas for heating, cooling and manufacturing purposes rather than electric energy, or of relocating their facilities to a lower cost environment.
While the Company faces these challenges, it believes its rates are competitive with currently available alternatives. The Company is taking actions to lower operating costs and is working with its customers to analyze the feasibility of various options, including energy efficiency, load management and co-generation in order to better position the Company to more effectively operate in a competitive environment.
Natural Gas Historically, gas utilities have competed with suppliers of electricity and fuel oil, as well as to a lesser extent, propane, for sales of gas to customers for heating and/or cooling purposes. In the 1980s, industrial and large commercial customers began to 'by-pass" the local gas utility through the construction of interconnections j
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 j
for several years in providing transportation services for those industrial and large commercial customers which chose to purchase gas directly from suppliers. in addition, the Company has provided flexible transportation rates for several years. He per-unit fee charged for transj,ortation 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. Herefore, increases in such activities will not have as great an impact on gas revenues as increases in deliveries from the sale of gas, but will have a positive impact on operating margin. In 1995, the Company organized e prime to engage in the non-regulated marketing of natural gas in order to expand its marketshare.
Franchises The Company and its subsidiaries held nonexclusive franchises to provide electric or gas service or both services in 120 incorporated cities and towns at December 31,1996. Rese franchises consist of 69 combined gas and electric service franchises,29 electric service franchises and 22 gas service franchises. In 1997, the Company expects to renegotiate.four of the franchise agreements which will be expiring. De Company's franchise with the City of Denver will expire in 2006. He Company and its subsidiaries supply electric or gas service or both services in about i14 unincorporated communities in which franchises are not required.
Employees and Union Contracts ne number of employees of the Company and its subsidiaries decreased from 4,776 at December 31, 1995 to 4,675 at December 31, 1996. Approximately, 2,090 employees, er 45% of the Company's total 13
i workforce, are represented by the International Brotherhood of Electrical Workers, local 111. He number of employees covered by collective bargaining agreements at December 31,1996 approximated 2,284.
i Research and Development he Company and its utility subsidiaries spent approximately $3.8 million in 1996, $3.6 million in 1995 and $3.8 million in 1994 on research and development. %e major portion of those expenditures went to utility f
associations which engage in research projects to benefit the electric and gas industries as a whole. De balance of the expenditures went for smaller internal and external projects dealing with such areas as pollution control and alternative fuels research.
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Consolidated Electric Operating Statistics Year Enda! Dwember 31.
1996 1995 1994 1993 1992 Energy Generated, Received, & Sold (Thousands of Kwh):
Net Generated:
Steam, Fossil..
17,099,890 16,053,928 15,949,980 15,470,247 14,972.688 Combustion Turbine...
121,079 5,251 4t,705 39,228 47,194 Pumped Storage.
178,205 68,400 126,721 118,593 79,609 Hydro..
197.660 208 R 176.264 198.2_72 175.010 Total Net Generation..
17,596,834 16,335,683 16,294,670 15,826,340 15,274,501 Energy Used for Pumping..
276.983 109.632 201.744 185.850 126.266 Total Net System input.,
17,319,851 16,226,051 16,092,926 15,640,490 15,148,235 Purchased Power and Net laterchange..
10.349.298 9.794.968 9.653.067 9.631.982 8.663.339 Total System Input.
27,669, t 49 26,021,019 25,745,993 25,272,472 23,811,574 Used by Company.
57,603 64,885 66,348 60,396 64,125 Other (1).
1.352.843 1.526.358 1.670.591 2.001.832 1.932 M Total Energy Sold,
26,258.703 24.429.776 24.009.054 23.210.244 21,815,116 Doctric Sales (Thousands of Kwh) (2r Residential.,
6,606,601 6.281,911 6,119,914 5,969,529 5,747,048 Commercial.
9,880,502 9,284,577 8,931,962 10,797,272 10,350,155 Industrial..
5.791,608 5,747,534 5,726,837 3,289,501 3,375,638 Public Authorities.
200,070 188.363 187,939 186,397 187,500
%holesale - Regulated.
3,361,217 2,927,391 3.042,402 2,967,545 2,154,775 Wholesale Energy Services - Non-Regulated.
418.705 Total Energy sold,
26.25R.703 24,429.776 24,009.044 23,210,244 21.815.116 Number of Customers at End of Period (2):
Residential..
959,249 936,759 913,582 898,752 894,217 Commercial,
126,426 123,277 120,886 120,317 120,198 Industnal,.
380 378 384 157 194 Public Authorities, 79,725 79,154 77,842 76,476 647
%holesale - Regulated,
26 17 18 20 34
%holesale Energy Services - Non-Regulated.,
6 Total Customers 1,165.812 1.139.585 1.112.712 1 095,722 1.015.290 Electric Revenues (Thousands of Dollars)(2):
Residential..
$ 507,233 $
477,740 $ 453,614 $ 433,521 413,655 Commercial.
571,536 552,905 519,340 602,187 572,780 industrial..
249,774 257,189 252,552 142,146 148,951 Public Authorities,.
25,798 23,029 21,950 20,828 20,221 Wholesale Regulated..
120,478 114,514 120,238 116,937 80,290 Wholesale Energy Services - Non-Regulated.,
7,806 Other Electric Revenues.
6.365 23.719 32.142 21.434 24.872 Total Electric Revenues.
$ 1.488.990
$ t.449.096
$ 1799,836 5 1.337.053
$ 1.260.769 Average Annual Kwh Sales per Residential Customer.
6,965 6,794 6,770 6,717 6,533 Average Annual Revenue per Residential Customer..
1534.79
$516.70
$501.82
$487.81
$470.26 Average Residential Revenue per Kwh..
7.68C 7.61c 7.41 C 7.26c
".20c Average Commercial Revenue per Kwh.
5.78c 5.96c 5.81c 5.58c 5.53c Average Industrial Revenue per Kwh..
4.31c 4.47c 4.41 c 4.32c 4.41 c Average Wholesale - Regulated Revenue per Kwh.
3.58C 3.91c 3.95c 3.94c 3.73c (1)
Primarily includes net distribution and transmission line losses.
(2)
Comparison of energy sales, customers and electric revenues between periods is impseted by: 1) a change in criteria for counting customers resulting from the implementation of a new customer information system during 1993, and 2) effective January 1,1994, a reclassification to include large commercial customers (> l,000 Kw demand) within the industrial category, to be consistent with recommended utility industry guidelines.
15
e Consolidskd Gas Operating Statistics Year Ended D=.__'_ r 31.
19 %
1995 _
1994 1993 1992 Natural Gas Purchased and Sold (Thousands of Dth):
39,924 38,687 45,177 55,078 59,328 107,374 101,259 88,174 88,482 79,011 Purchased from Interstate..
Purchased from others....
22.807 237 Purchased for Non-regulated Gas Marketing (1)..
170,105 140,183 133,351 143,560 138,339 Total Purchased..
520 1,330 2,386
' 2,349 2,603 10.000 5.657 3.824 (1.803) 6.052 Company Use..
Other (2).~
159.585 133.1 %
127.141 143.014 129.684 Total Gas Sold....
On Deliveries (Thousands of Dth):
86,102 82,188 77,955 83,991 74,951 Residential..
50,l00 50,463 48,689 54,125 50,705 Commercial 1,555 308 497 4,898 4.028 Wholesale,.
21.828 237 Non-regulated Osa Marketing (1)....
159,585 133,1%
127,141 143,014 129,684 Total Gas Sold.,
90,304 75,704 66,230 61,421 51,706 Transportation..
l.141 1.391 25.316 35.877 28.292 Gathering and Processing (3)..
251.0.0 210.291 218.687 240.312 200.682 3
Total Deliveries..
Number of Customers at End of Period:
Residential..
902,078 872,777 845,464 820,521 808,722 Commercial.
90,761 89,034 87,103
. 86,227 86,192 8
8 8
Wholesale...
1.255 2
Non-regulated Gas Marketing (1)..
Total.
994,094
%I,813 932,575 906,756 894,922 l.794 952 786 619 416 Transportation and Other...
905.888 962.765 933.361 907.375 895.338 Total Customers..
Gas Revenues (' thousands of Dollars):
362,481 $ 383,719 $ 375,406 $ 366,445 $
329,406 Residential..
Commercial..
173,308 200,314 203,31]
204,820 191,366 Wholnale.....
3,020 4,%)
7,319 13,966 10,099 Non-regulated Oas Markenng (1)..
64,389 399 Transportation.
28,549 23,769 23,495 23,176 20,638 Gathering and Procmaing..
364 443 8,335 10,575 8,023 Other Gas Revenues..
8.386 10.980 7.056 9.342 9.354 Total Gas Revenues..
640.497 624.585
$ 624.922 5 628.324 $
568.886 Average Annual Dth Sales per Residential Customer.....
97.14 95.65 93.67 103.21 93.73 Average Annual Revenue per Residential Customer..
$408.93
$446.58
$451.09
$450.29
$411.94 Average Revenue per DeLatherm:
Residential..
$4.210
$4.669
$4.816 '
$4.363
$4.395 Commercial
$3.459
$3.970
$4.176
$3.784
$3.774
$0.316
$0.314
$0.355
. $0.377
. $0.399 Transportation (1) includes purchenes and sales by e prime and TOO.
' (2)
Primarily includes distribution and transmission line losses and net changes to gas in storage.
(3) in August 1994, the Company sold WOG, which resuhad in the decline in gathering and processing dehveries.
w 16
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l Iteun 2. Properties Electric Generation Property 1
1 The electric generating stations of the Company and its subsidiaries expected to be available at the time of the anticipated 1997 net firm system peak demand during the summer season are as follows:
I Net Dependable Capacity Installed (Mw)
Gross at Time of Anticipated Major Name of Station Capacity 1997 Net Firm System Fuel and tocation (Mw)
Peak Demand *
}sggy,e Steam:
Arapahoe-Denver.,
262.00 246.00 Coal Cameo-near Orand Junction.
77.00 72.70 Coal Chemkee-Denver..
784.00 723.00 Coal Comanche-near Pueblo..
725.00 660.00 Coal Craig-near Craig.,
86.90 (a) 83.20 Coal Hayden-near Hayden..
259.00 (b) 237.00 Coal Pawneo-near Brush..
530.00 495.00 Coal Valmont-near Boulder (Unit 5)..
188.00 178.00 Coal Zuni-Denver..
I15 00 107 00 Osa/ Oil i
Total..
3,026.90 2,801.90 Fort St. Vrain Combustion Turbine near Platteville.
141.45 126.75 Osa Combustion turbines (6 units-various locations)..
209.00 171.00 Oas Hydm (14 units-various locations) (c)..
53.35 36.55 (d)
Hydro Cabin Creek Pumped Storage-near Georgetown..
324.00 (e) 162.00 Hydm Cherokee Diesel generators (2 unita).
5.50 5.50 Oil Total.,
3.760 20 3,301 70 1
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.
i l
(a) ne gross maximum capability of Craig Units No. I and No. 2 is 894 Mw, of which the Company has a 9.72% undivided ownership interest.
(b) ne gross maximum capability of Hayden Units No I 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.
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(c) includes one station (two units) not owned by the Company but operated under contract.
(d) Seasonal Hydro Plant net denendable capabilities are based upon average water conditions and limitations for each particular season.
De individual plant seasonal capabilities are sometimes limited by less than design water flow.
(e) Capability at maximum load, l
Nuclear Generation Property Fort St. Vrain, near P atteville, the Company's only previous nuclear generating station, ceased operations on August 29, 1989 and on March 22, 1996 the physical decommissioning of the station was completed. The initial phase of the repowered gas fired combined cycle steam electric generating station began
-l commercial operations on May 1,1996 (see Note 2. Fort St. Vrain in item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
Electric Transmission and Distribution Property On December 31,1996, the Company's transmission system consisted of approximately 112 circuit miles of 345 Kv overhead lines; 1,916 circuit miles of 230 Kv overhead lines; 15 circuit miles of 230 Kv underground 18
, lines; 65 circuit miles of 138 Ky overhead lines; 999 circuit miles of 115 Kv overhead lines; 20 circuit miles of 115 Kv underground lines; 344 circuit miles of 69 Ky overhead lines; 143 circuit miles of 44 Kv overhead lines; and I circuit mile of 44 Kv underground lines. He Companyjointly owns with another utility approximately 342 circuit miles of 345 Kv overhead lines and 360 miles of 230 KV overhead lines, of which the Company's share is 112 miles and 147 miles, respectively, which shares are included in the amounts listed above.
He Company's transmission facilities are located wholly within Colorado. He map on page 16 illustrates the Company's transmission interconnected system. %e system is interconnected with the systems of the following utilities with which the Company has major firm purchase power contractr; 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.........
Northeentral Colorado Tri-State...............
Southeast Wyoming and Northwest Colorado ne 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.
He Company is a member of the WSCC, an interstate network of transmission facilities which are owned by public entities and investor-owned utilities. WSCC is the regional reliability coordinating organization for member electric power systems in the western United States.
At December 31,1996, the distribution systems consisted primarily of appror.imately 12,939 miles of overhead line,1,068 miles of which are located on poles owned by other utilities underjoint use agreements. He Company also owned approximately 7,891 cable miles of underground distribution system (excluding street lighting) located principally in the Denver metropolitan area. He Company owned 219 substations (four of which are jointly owned) having an aggregate transformer capacity of 18,705,000 Kva, of which 4,145,827 Kva is step-up transformer capacity at generating stations.
Gas Property ne gas property of the Company at December 31,1996 consisted chiefly of approximately 15,304 miles of distribution mains ranging in size from 0.50 to 30 inches and related equipment. The Denver distribution system consisted of 8,691 miles of mains. Pressures in the low pressure system are varied to meet load requirements and individual house regulators are installed on each customer's premises to provide uniform flow of gas to appliances. He Company also owns and operates four gas storage facilities.
Other Property He Company's steam heating property at December 31, 1996 consisted of 10.5 miles of transmission, distribution and service lines in the central business district of Denver, including a steam transmission line connecting the steam heating system with Zuni. Steam is supplied from boilers installed at the Ccmpany'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. He Company also owns service and office facilities in Denver and other communities strategicall) beated throughout its service territory.
19
Property of Subsidiaries he book value of the propertier of the consolidated subsidiaries of th-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.
Unregula'ed subsidiary property is approximately 1% of the total book value of the properties of the Company and consolidated subsidiaries combined. 1480 Welton, Inc. owns two buildings that are used by the Company.
Character of Ownership ne 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.
De remaining major electric substations and compressor stations and the majority of gas regulator stations and
<n border and meter stations are wholly or partially on land leased from others or on or along public highways or on streets or public plact ' within incorporated towns and cities. He Company's Cabin C-eek 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 cr its subsidiaries hold licenses or permits issued by appropriate Federal agencies or departments. De leyden gas storage facility is located largely on leased property under leases expiring December 31, 2040. He Company and its utility subsidiaries have the power of eminent domain pursuant to Colorado law to acquire property for their electric and gas facilities, ne electric and gas transmission and distribution facilities are foi the most part located over or under streets, public highways or other public
% aces and on public lands under franchises or other rignts, and on land owned by the Company or others pursuant to casaments 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 senring the mortgage bonds of the Company and its utility subsidiaries.
Item 3. Legal Proceedings See Note 9. Commitments and Contingencies in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Ilmi 4. Submission ofAtatters to a he ofSecurity lloiders Does not apply.
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20
PART 11 Item 5. Marketfor Registrant's Common Equity s *ul Related Stockholder Matters ne Company's common stock is listed on trm New York, Chicago and Pacific Stock Exchanges. De 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 Ihe Wall Street Journal.
Dividends Price Range Year and Ouarter Declared 1Dg,h, Low 1996 First Quarter.............................
$.525
$361/2
$33 3/4 Second Quarter.....
.525 36 3/4 32 3/8
.525 36 7/8 34 3/4 Third Quarter........................
Fourth Quarter........
.525 39 1/2 35 1/4
$2.10 1995 First Quarter..........
$.51
$31 1/2 3
29 Second Quarte r.............................
.51 32 7/8 29 1/4 Dird Quarter.........................................
.51 34 1/2 30 5/8 Fourth Quarter........................
.51 35 7/8 33 3/8
$2.04 At December 31,1996, the book value of the common stock was $22.19 per share. At February 21, 1997, there were 57,532 holders of record of the Company's common stock.
He dividend level is dependent upon the Company's results of operations, financial position and other factors and is evaluated quarterly by the Board of Directors. See item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
On February 26, 1991, the Company's Board of Directors declared a dividend of one common share purchase right ("right") on each outstanding share of the Company's common stock. All future common shares issued will contain this right. Each right stipulates an initial purchase price of $55 per share and also prescribes a means whereby the resulting effect is such that, under the circumstances described below, shareholders would be entitled to purchase additional shares of common stock at 50% of the prevailing nrrket price at the time of exercise. De rights are not currently exercisable, but would become exercisable if certain events occurred related to a person or group acquiring or attempting to acquire 20% or more of the outstanding shares of common stock of the Company. On August 22, 1995, in connection with the proposed merger (see Note 3. Merger in item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA), the Company's Rig'ats Agreement was amended to provit that NCE will not be deemed an " Acquiring Person" as a result of the execution, delivery, and performance of the Merger Agreement.
In the event a takeover results in the Company being merged into an acquiror, the unexercised rights could be used to purchase shares in the acquiror at 50% of market price. Subject to certain conditions, if a person or group acquires at least 20% but no more than 50% of the Company's common stock, the Company's Board of Directors may exchange each right held by shareholders other than the acquiring person or group for one share of common stock (or its equivalent).
If a person or group successfully acquires 80% of the Company's common stock for cash, after tendering for all of the conunon stock, and satisfies certain other conditions, the rights would not operate. He rights expire on March 22,2001; however, each right may be redeemed by the Board of Directors for one cent at any time l
prior to the acquisition of 20% of the common stock by a potential acquiror. For a description of the rights and their terms see the Company's Rights Agreement, as amended, which is an exhibit to this Form 10-K.
t 21
i Itesn 6. Selected Rnancial LAata i
l J
He following selected consolidated financial data of the Company and its subsidiaries for each of the five years in the period ended December 31, 1996 should be read in conjunction with the consolidated financial statements and the tnanagement's discussion and analysis of financial condition and results of operations appearing elsewhere herein.
i l
j.
Year Ended Dec-- ' -- 31.
1996 1995 1994 1993 1992 (la Thousands-except per share data & ratios) i Operating revenues:
l Electric...
$1,488,990
$1,449,096
$1,399,836
$1,337,053
$1,260,769 Gas...
640,497 624,585 624,922 628,324 568,886 1
Other...
41.899 36.920 32.626 33.308 31 618 Total...
2,171,386 2,110,601 2,057,384 1,998,685 1,862,273 Total or ersting expenses..
1,1 ',902 1,784,784 1,786,592 1,717,752 1,612,646 l
Operating incotne..
328,484 325,817 270,792 280,933 249,627
)
Total intereet charges.,
149,880 143,906 132,134 130,337 121,116 I
Net income...
190,346 178,856 170,269 157,360 136,623 Dividend requirements on preferred stock...
I1,848 11, % 3 12,014 12,031 12,077 Earnings available for common stock.
178,498 166,893 158,255 145,329 124,546 i
Per share data applicable to common stock (a):
Earnings.
$ 2.78
$ 2.65
$ 2.57
$ 2.43
$ 2.16 Dividends declared.
$ 2.10
$ 2.04
$ 2.00
$ 2.00
$ 2.00 Shares of common stock outstanding:
Weigt.ted everage..
64,187 62,932 61,547 59,695 57,558 Year end...
64,819 63,358 62,155 60,457 58,477 Rate of return earned on average common equity (net to common)......
12.8 %
12.8 %
12.9 %
12.7 %
11.7 %
Ratio of earnings to fixed charges (b)..
2.75 2.78 2.53 2.54 2.43 I
Total assets.
$4,572,648
$4,351,789
$4,207,832
$4,057,600
$3,759,583 i
Totai nst plant..
3,598,895 3,480,712 3.291,402 3,193,136 3,077,509 Total construction expenditures..
321,162 285,516 317,138 293,515 261,666 AFDC.
4,101 7,095 7,158 12,667 11,302 Cash generated internally as a percent of construction expenditures (c).
59.5 %
87.4 %
35.4 %
$2.2%
57.5 %
Total common equity.
$1,438,288
$1,343,645
$1,267,482
$1,184,183
$1,101,047 Preferred stock:
Not subject to mandatory redemption..
140,008 140,008 140,008 140,008 140,008 Subject to mandatory redemption at par (including amounts due within one year).
42,4'9 43,865 45,241 45,454 45,654 d
Long-term debt (including amounts due within one year)..
1,414,558 1,278,389 1.180,580 1,193,668 1,199,779 l
Notes payable & commercial paper..
244,725 288,050 324,800 276,875 2 *),626 (a) Earnings per share are based on the weighted average number of shares of common stock outstanding.
(b) See Exhibit 12(a) herein.
(c) Calculated as cash provided by operations not of cash used for dividends, divided by construction expenditures not of AFDC equity-component.
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22
t
, liesn 7. Management's Discussion and Analysis of Rnancial Condition and Results of Operations Industry Outlook i
Fundamental changes continue to occur throughout the electric utility industry as it moves toward deregulation with customer choice and increased competition. Regulatory actions at both the federal and state level have opened up the wholesale, and to a lessor extent retail, markets to more competition. He FERC issued new rules in early 1996 requiring utilities to provide wholesale open-access transmission services and allowing for f
reccsesy of stranded investment costs. A few states with above-average electric energy prices are aggressively pursuing full competition in the electric industry. Some states currently have pilot plans in place to allow setail customers to select their energy supplier. Federal legislation related to deregulation of the electric utility industry was introduced in 1996 and broad support for restructuring legislation is developing. In addition, the reform or repeal of PUHCA, the law which regulates the ownership and operation of public utility holding companies, is expected to be given l
serious consideration in 1997 by Congress. Utilities are responding to increased competition. Mergers, l
l acquisitions and corporate restructurings have continued to occur nationally and globally as companies strive to position themselves for the future, achieving economies of scale and increases in productivity and efficiency.
1 Electric prices in Colorado are relatively low in cocparison to other parts of the country, lessening the need for immediate change in the state's electric industry. In 1996, the CPUC performed a comprehensive survey on electric industry restructuring. He report issued by the CPUC is not conclusive on what the next steps should l
be. Clearly, the issues are complex and controversial with significant consequences to the Company's securities holders. The Company supports the need for change and believes that Colorado must take the time to study and learn from the restructuring models developed in other states to determine which aspects of those programs may be appropriate, and to identify other specific regional issues that need to be addressed. The Company's response j
to the survey included a proposal that the CPUC undertake a comprehensive study of these complex issues, which would provide the necessary foundation of information for consideration by the state legislature, i
l Corporate Overview l
l Significant progress on the Merger of the Company with SPS was achieved in 1996 and early 1997.
l f
Shareholder approvals were received in.lanuary 1996 and required authorizations were obtained from all state l
utility regulators. Final approvals and filings are in progress with completion of the merger anticipated in the l
l spring of 1997. He Merger will permit the Company to derive benefits from the more efficient and economic l
l utilization of combined facilities and personnel. With a larger and more geographically diverse combined service l
territory, the business risks related to changes in economic, competitive or climatic conditions will be reduced. In f
addition, purchasing savings, increased economical use of generation capacity and reduced administrative costs are anticipated. Merger transition plans have been developed to begin realizing synergy savings upon consummation of the Merger, although the savings expected for 1997 will be reduced somewhat by various Merger related costs, including those related to planned workforce reductions.
i Operating priorities in 1996 continued to focus on reducing costs and developing new business opportunities. Positive earnings reflected the continued cost containment efforts initiated in 1994. De l
l performance based regulatory plan approved by the CPUC resulted in a sharing arrangement between customers i
I and shareholders on electric department earnings in excess of 11% for the years 1997-2001, a 50%/50% sharing j
of certain fuel and energy cost increases or decreases and a QSP which provides for penalties if certain i
performance measures relating to electric reliability, customer complaints and telephone response to inquiries are not met. De Company anticipates that a reward structure for performance above certain standards will be implemented in the near term.
l l
In line with the Company's strategic focus on expanding market share and value, e prime received authorization from the FERC to act as a power marketer and is now marketing wholesale electricity. In September 1996, e prime acquired TOG, a gas marketing company which serves 1,400 industrial and commercial customers in the eastern U.S.
In line with customer retention, the Company and one of its largest wholesale l
customers entered into a new purchase power agreement in which the Company provides power through the year j
l 4
3 23 i
i
2001. His wholesale customer had previously notified the Corn 3ny of its intent to reduce firm and peaking he Company continues to Nk for opportunities to expand its'entomer power purchases beginning in 1998.
base as both a natural gas and electric energy provider and to advance its strategy to focus on customer needs, while building a national presence in the marketplace.
The regulatory environment within Colorado is a primary focus for the Company and the successful raerger with SPS will likely have long-term effects on the Company's future financial performance. The Compa strongly believes that all potentially stranded costs resulting from changes in laws or regulation should be recoverable. Additionally, the Company believes that it will continue to be subject to rate regulation that will allow for the recovery of all of its deferred costs. To the extent the Company concludes in the future that such recovery is no longer probable, the Company may be required to recognize as expense, at a minimum, all defer costs currently recognized as regulatory assets on the consolidated balance sheet. (See Note 1. Summary of Significant Accounting Policies in item 8. FINANCtAL STATEMENTS AND SUPPLEMEFGARY DATA).
Recent Developments On February 24,1997, the Company and AEPjointly announced that they have reached agreement with the board of directors of Yorkshire Electricity, a UK regional electricity company, on the terms of a recommended cash tender offer for all of the outstanding and to be issued ordinary shares of Yorkshire Electricity. He Company and AEP, through a joint venture named Yorkshire Holdings, are offering the equivalent of US $15.02 (9.27 pounds) per ordinary share, for a total purchase price of approximately US $2.4 billion (1.5 billion pounds). He boards of directors of the Company and AEP have approved the transaction.
He board of directors of Yorkshire Electricity has agreed to recommend the offer to Yorkshire Electricity's shareholders. The offer will be made through Yorkshire Holdings, a wholly-owned subsidiary of Yorkshire Power, a newly formed UK corporation owned equally by the Company and AEP. The Company will make its investment through New Century International, Inc., a wholly-owned subsidiary of the Company, if the Proposed Acquisition is completed, the Company would have an indirect 50% ownership interest in Yorkshire Electricity, which would be accounted for using the equity method of accounting. Consummation of the Proposed Acquisition is subject to customary conditions in the UK, including regulatory clearance and acceptance of the offer by holders of at least 90% of the outstanding shares of Yorkshire Electricity. Yorkshire Holdings may waive the latter condition when it has received acceptances of its offer and has otherwise acquired shares which in total represent more than 50% of the outstanding shares of Yorkshire Electricity. He Company cannot predict at this time whether or not these conditions will be met or waived.
He Proposed Acquisition will be financed by Yorkshire Power through a combination of approximately 25% equity and 75% debt, including the assumption of the existing debt of Yorkshire Electricity. The funds for the Proposed Acquisition will be obtained from the Company's and AEP's investment in Yorkshire Power of approximately US $360 million (220 million pounds) each, with the remainder to be obtained by Yorkshire Power through the issuance of non-recourse debt. Yorkshire Power will, in turn, fund Yorkshire Hc4 dings for the purpose of the Proposed Acquisition. The Company intends initially to use debt to fund its entire equity investment in Yorkshire Power, including the issuance of US $250 million of its secured medium-term notes with varying maturities and drawings of US $110 million on its short-term lines of credit. It is currently anticipated that the Company's entire equity investment in Yorkshire Power will be refinanced through the issuance of common equity at the NCE level within six to eighteen months from the date of consummation of the Proposed Acquisition.
According'to Yorkshire Electricity's 1996 Annual Report and Accounts, Yorkshire Electricity's principal activities are the distribution of electricity to 2.1 million industrial, commercial, agricultural and domestic customers in its authorized area, which covers 4,180 square miles of northeast England. Yorkshire Electricity is a so active in electricity supply and generation and the supply of natural gas, including the ownership of gas assets. Other activities include the development of telecommunications services and the construction and operation of windfarms. For the fiscal year ended March 31,1996, Yorkshire Electricity reported a consolidated profit on ordinary activities before taxation and exceptional items of US $310.8 million (199.2 million pounds) on 24
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revenues of US $2.2 billion (1.4 billion pounds), had reported total assets at that date of US $2.2 billion (1.4
- iilion pr unds), and reported net assets at that date of US $818.9 million (521.1 million pounds).
l b
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The SEC, in an order issued on February 19, 1997 under section 3(b) of PUHCA, exempted Yorkshire Electricity from all provisions of PUHCA that would be applicable to it as a subsidiary of the Company. In i
connection with its application for such order, the Company also requested and obtained a no-action letter from the Division ofInvestment Management of the Office of Public Utility Regulation of the SEC stating that, as long as the Merger is completed by September 30,1997, it will not recommend any enforcement action with respect to the possible effect of ti e Proposed Acquisition on the Company's existing section 3(a)(2) exemption under PUHCA. In seeking the section 3(b) exemption for Yorkshire Electricity, the Company informed the SEC that its i
investment in Yorkshire Electricity would be less than 50% of the Company's and SPS's combined retained earnings as of September 30,1996, consistent with the requirements of Rule 53 under PUHCA. The Company also informed the SEC in its application for a section 3(b) exemption that upon completion of the Merger, NCE
(
would hold the proposed investment in Yorkshire Power through a separate subsidiary and not through the Company. At that time, Yorkshire Electricity would be qualified as a foreign utility company under section 33 of PUHCA.
See Note 4. Acquisition and Divestiture of Investments - Proposed Acquisition of Yorkshire Electricity in item 8. FINANCIAL STATEMENTS AND SUPPLEMEffrARY DATA.
Earnings l
Earnings per share were $2.78, $2.65 and $2.57 during 1996,1995 and 1994. respectively. The improved earnings in both 1996 and 1995 are primarily attributable to increased electric and gas margins resulting from higher sales and lower operating and maintenance expenses resulting from the Company's cost containment efforts. In addition, earnings in 1996 were favorably impacted by the February 9,1996 settlement agreement with the DOE resolving all spent nuclear fuel storage and disposal issues at Fort St. Vrain (See Note 2. Fort St.
Vrain in item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
I l
Electric Operations l
The following table details the annual change in electric operating revenues and energy costs as compared l
to the preceding year:
l Increase (Decrease)
From Prior Years l
1996 1995 (Thousands of Dollars)
Electric operating revenues:
R etail................
$ 43,478
$ 63,407 Wholesale................
13,770 (5,724)
Other (including unbilled revenues)...........
(17354)
(8.423)
Total revenues..
39,894 49,260 i
Fuel used in generation...
13,447 (16,123)
I Purchased power........
8.470 44.871 Net increase in electric margin..
$17.077
$10,5.12
?
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25
He following table summarizes electric sales by major customer classes:
Millions of
% Change
- Kwh Sales from prior vears 1996 1995 J.296 J.2PJ 6.607 6,282 5.2%
2.6 %
Residential Commercial and Industrial 15,672 15,032 4.3 2.5 200 189 6.2 0.2 Public Authority.......................................
Total Retail............................................
22,479 21,503 4.5 2.6 3.780 2.927 29.1 (3.8)
Wholesale............................
Total....................................................
26,259 24,430 7.5 1.8
- Percentrges are calculated using unrounded amounts.
j Electric operating revenues increased in 1996, when compared to 1995, primarily due to an overall 4.5 %
increase in retail sales resulting primarily from customer growth of 2.3%. He increase in wholesale revenues was due to higher economy sales by the Company and power marketing activities of non-regulated subsidiaries.
However, these additional sales contributed little to the increase in electric margin. Electric operating revenues increased in 1995, when compared to 1994, primarily due to higher retail sales resulting from customer growth and additional revenues related to collection of QF purchased power capacity costs. Wholesale revenues decreased in 1995, as compared to 1994, as a result of lower wholesale Kwh sales. He demand for wholesate energy during 1995 was negatively impacted by an available supply of low-cost non-firm energy in the region.
He Company and Cheyenne currently have cost adjustment mechanisms which recognize the majority of the effects of changes in fuel used in generation and purchased power costs and allow recovery of such costs on a timely basis. As a result, the changes in revenues associated with these mechanisms in 1996 and 1995, when compared to the respective preceding year, had little impact on net income. However, as discussed in Note 9.
Cortmitments and Contingencies - Regulatory Matters - Merger Rate Filings in item 8. FINANCtAL STATEMENTS l
AND StfPPLEMENTARY DATA, in its decision on the Merger, the CPUC modified and replaced the Company's ECA with an ICA, effective October 1,194, which allows for a 50%/50% sharing of certain fuel and energy l
cost increases and decreases among customers and shareholders. He change did not significantly impact the cost recoveries for 1996.
Fuel used in generation expense increased $13.4 million in 1996, when compared to 1995, primarily due t
to higher generation levels. Fuel used in generation expense decreased $16.1 million during 1995, as compared to the prior year,'primarily due to lower coal and coal transportation costs from the renegotiation of certain contracts as generation levels were about the same for both years.
Purchased power expense increased slightly in 1996 primarily due to purchases in comiection with the non-regulated power marketing sales. Purchased power expense increased 10.3% in 1995, as compared to 1994, primarily due to increased purchases fram QFs as mandated by the CPUC. Electric energy purchased from QFs is over 50% higher per Kwh than that purchased from other suppliers.
- l 26
i I
l I
l-
. ~ Gas Operations The following table details the annual change in revenues from gas sales and gas purchased for resale as
' compared to the preceding year:
Increase (Decrease)
From Prior Years i
1996 1995 i-(Thousands of Dollars) i Revenues from gas sales........................
I1.211 7,281 Gas purchased for resale.............
483 t5.117)
Net increase in gas sales margin............................................
10.728 12.478 l
De following table summarizes gas deliveries by major customer classes:
t' i
j Millions of
% Change *
[
Dth Deliveries from prior years l-1996 1995 136 1995 i.
Residential............................................
86.I 82.2 4.8 %
5.4 %
[
Commerc ial..........................................
50.I 50.5 (0.7) 3.6 '
l (38.0)
Wholesale.........,
1.6 0.3 Non. regulated gas marketin g..................................
21.8 0.2 t
Total Sales..........
159.6 133.2 19.8 4.8 l
i l
Transportation, gathering and processing....................
91.4 77.1 18.6 (15.8)
Total.........................................................
251.0 210.3 19.4 (3.8) 1 7
- Percentages are calculated using unrounded amounts.
- Percentage change is significant, but presentation of the amount is not meaningful.
Gas sales margin increased in 1996, when compared to 1995, primarily due to higher retail gas sales resulting from customer growth of 3.4% and slightly colder weather. Increased gas marketing activities by non-l regulated subsidiaries favorably impacted gss sales margin in 1996. Gas sales margin increased in 1995, as j
compared to 1994, primarily due to higher retail gas sales resulting from colder weather and moderate customer growth; there were approximately 17% more heating degree days in 1995 than in 1994.
t Gas transportation, gathering and processing revenues increased $4.7 million in 1996, as compared to i
1995, primarily due to an increase in transport deliveries resulting from the shifting of various Company j
commercial customers to firm transport customers which accelerated in October 1995 with the implementation of j
new gas rates. Transportation, gathering and processing revenues decreased $7.6 million in 1995 primarily due to j
l the sale of WGG in August 1994 (See Note 4. Acquisition and Divestiture of Investments in item 8. FINANCIAL
{
l STATEMENTS AND SUPr! EMENTARY DATA).
(
l.
The Company and Cheyenne have in place GCA mechanisms for natural gas sales, which recognize the
={
majority of the effects of changes in the cost of gas purchased for resale and adjust revenues to reflect such l
changes in cost on a timely basis. - As a result, the changes in revenues associated with these mechanisms in 1996 l
and 1995, when compared to the respective preceding year, had little impact on net income. However, the l
fluctuations in gas sales impact the amount of gas the Company must purchase and, therefore, along with increases and decreases in the per. unit cost of gas, affect total gas purchased for resale. In 1996, the increase in i
the quantity of gas purchased was offset substantially by the lower per unit average cost of gas for the year. He i
$5.2 million decrease in gas purchased for resale for 1995 is primarily due to lower per unit cost of gas offset, in i
part, by a slight increase in gas purchases.
i I
27 t
~..
Non-Fuel Operating Expenses Other operating and maintenance expenses decreased $10.1 million during 1996 as compared to 1995 primarily due to the favorable impact of the February 9,1996 settlement agreement with the DOE res I
spent nuclear fuel storage and disposal issues at Fort St. Vrain (See Note 2. Fort St. Vrain. in item 8. FINA STATEMENTS AND SUPPLEMENTARY DATA), lower labor and employee benefit costs resulting from the hirin freeze instituted in August 1995 and other general cost reductions resulting from the Company's cost containment efforts. Rese reductions were offset, in part, by higher operating costs from non-regulated operations that were, for the most part, initiated during 1996.
Other operating and maintenance expenses decreased $26.1 million in 1995, as compared to 1994, primarily due to lower labor and employee benefit costs resulting from the Company's cost containmen which included the restructuring and downsizing accomplished in 1994 (approximately a $26 million reduction) and the recognition of approximately $8.7 million of involuntary severance costs in 1994. His restructuring a
- 1) effective April 1,1994, the Company reduced its workforce by downsizing was completed in two phases:
approximately 550 employees through an early retirement / severance program, and 2) during the last 1994, the Company eliminated approximately 550 management and staff level positions in connection with an internal restmeturing and involuntary severance program. Rese decreases in 1995 were offset, in part, by the
$2.5 million write-off of software costs due to the cancellation of a materials management project, three mon additional amortization of the early retirement / severance program costs totaling $2.2 million and $2.2 million of additional repair costs associated with an early winter snow storm.
During 1994, the Company recognized additional expenses aggregating approximately $43.4 million for increased costs associated with the defueling and decommissioning of Fort St. Vrain and the impairment of cer Fort St. Vrain related property and inventory. The additional expense was primarily associated with radiation levels in the reactor core being higher than originally anticipated and increased uncertainty related to spent fuel disposal issues (See Note 2. Fort St. Vrain in item 8. FIN ANCIAL STATEMENTS AND SUPPLEMENTA Depreciation and amortization expense increased $13.3 million in 1996 and $2.3 million in 1995 primarily due to higher depreciation expense from property additions and amortization of software costs.
Taxes (other than income taxes) decreased $5.1 million in 1995 primarily due to lower payroll related taxes resulting from the 1994 downsizing.
Income taxes increased $1.0 million in 1996, as compared to 1995, primarily due to higher pre-tax income, offset, in part, by the write-off of additional investment tax credits for retired property and additional tax benefits at PSRI. He $46.9 millien increase in income taxes during 1995, as compared to 1994, is primarily due to higher pre-tax income and the effects of two items recorded in 1994 which served to lower tax expense that period. These items included: 1) an adjustment associated with the adoption of full normalization uh provided for in a CPUC rate order (approximately $21.3 million), and 2) the true-up of the tax accrual the filing of the 1993 tax return (approximately $5.1 million).
Other income and deductions decreased $15.2 million during 1996, as compared to the preceding year, primarily due to higher costs related to the Merger ($3.1 million), the recognition of $4.1 million of cer severance costs, the recognition of $2.3 million of costs associated with the settlement of environmental issues related to the operations of the Hayden station and a decrease in the allowance for equity funds used during construction. Other income and deductions decreased $34.7 million in 1995 primarily due to the net effects of the pre-tax gain of approximately $34.5 million recognized on the sale of WGG in 1994 (See Note 4. Acqui Divestiture of Investments in item 8. FtN ANCIAL STATEMENTS AND SUPPLEMENTARY costs related to the Merger (See Note 3. Merger in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA), offset, in part, by the 1994 reversal of the $3.0 million gas search award, as the Colorado Supreme Court reversed the Scentive award previously granted by the CPUC.
28
Interest charges increased $6.0 million during 1996, as compared to 1995. Higher interest on long-term debt resulted from the financing of capital expenditures. Interest charges increased $11.8 million during 1995 as compared to 1994. Other interest increased due to higher interest rates and an increased level of short-term borrowings in 1995, the recognition of interest costs related to the over-collection of expenses under the Campany's cost adjustment mechanisms and higher interest on COLI contracts, w hile the net costs associated with long-term debt decreased slightly.
Financial Position Accounts receivable increased at December 31,1996, as compared to 1995, primarily due to overall sales growth, including nwrketing activities by non-regulated subsidiaries, and the fact that a portion of the gas refund made late in 1995 was applied directly to customers' accounts, which served to lower the accounts receivable balance at December 31,1995. Accounts payable increased primarily due to the Company's higher gas costs at the end of 1996 and increased activities by non-regulated subsidiries.
He $38.5 million decrease in the defueling and decommissioning liability was due to expenditures during 1996. His decrease and the increase in noncurrent investments and receivables were also affected by the February 9,19% settlement agreement with the DOE resolving all spent nuclear fuel storage and disposal issues at Fort St. Vrain. Customers' advances for construction decreased by approximately $49.3 million due to a 1996 transfer of amounts to property, plant and equipment, which served to reduce such investments, after determining that these amounts would not be refunded to customers in the future.
Commitments and Contingencies issues relating to regulatory and environmental matters are discussed in Note 9. Commitments and Contingencies in item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Rese matters and the future resolution thereof, may impact the Company's future results of operations, financial position and cash flows.
Common Stock Dividend In the first quarter of 1996, the Company increased the quarterly dividend on its common stock from
$0.51 per share to $0.525 per share. His follows the 1995 first quarter increase in the quarterly dividend on its common stock from $0.50 per share to $0.51 per share. He Company's common stock dividend level is dependent upon the Company's results of operations, financial position, cash flow and other factors. He Board of Directors will continue to evaluate the common stock dividend level on a quarterly basis.
Liquidity and Capital Resources Cash Hows 1996 1995 1994 Net cash provided by operating activities (in m. ! lions)
$327.6
$385.7
$245.7 Net cash provided by operating activities decreased $58.1 million in 1996 primarily due to the undercollection of purchased gas and electric energy costs ($40.8 million) and lower cash receipts because of a gas refund that was applied directly to customers' accounts in late 1995. Higher earnings and lower decommissioning and defueling expenditures positively impacted operating cash flows for both 1996 and 1995. He increase in 1995 was also significantly impacted by the overcollection of purchased gas and electric costs.
At December 31, 1996, the Company's decommissioning liability, excluding defueling, was approximately $6.6 million. He remaining expenditures related to this obligation are expected to be incurred over the next year. He annual decommissioning amount being recovered from customers is approximately $13.9 million which will continue through June 2005. At December.41,1996, approximately $89.7 million remains to be collected from customers and is reflected as a regulatory asset on the consolidated balance sheet.
29
j996 1995 1994 Net cash used in investing activities (in millions)........
$(307.1)
$(284.6)
$(177.4)
Net cash used in investing activities, which substantially consisted of construction expenditures, was higher in both 1996 and 1995, compared to the respective prior years. Proceeds from the sale of WGG in 1994 and the sale of certain Fuelco properties in '994 and 1996 reduced the net cash used in investing activities (See Note 4. Acquisition and Divestiture of Investments in item 8. FINANCtAL STATEMES AND SUPPLEMEWARY DATA).
I996 1995 I994 Net cash used in financing activities (in millions).....
$(25.8)
$(92.3)
$(80.5)
Net cash used in financing activities decreased (indicating that there were more borrowings) significantly in 1996 primarily due to the issuance of additional long-term debt, including the $125 million First Collateral Trust Bonds in May 1996 and $75 million in medium-term notes in November 1996. The proceeds were used to fund the Company's construction program, for other general corporate purposes and to repay short-term indebtedness incurred for such purposes. Cash used in financing activities increased slightly in 1995 over 1994.
Proceeds from the sale of common stock under the Company's dividend reinvestment and stock purchase plan decreased in 1995. Ieng-term debt refinancing activity also decreased in 1995, as compared to 1994, as a result of higher interest rates. The use of short-term borrowing over the last several years has increased slightly, however, short-term bormwing levels were reduced in late 1995 with an issuance of $80 million of medium-term notes by PSCCC.
Prospective Capital Requirements At December 31,1996, the Company and its subsidiaries estimated cost of their construction programs and other capital requirements for the years 1997,1998 and 1999 are shown in the table below:
1997 1998 1999 Company:
(Thousands of Dollars)
Electric Production *............
$ 95,056
$ 103,211
$ 125,505 Transmission...........
39,600 48,433 22,718 Distribution..................
68,944 70,426 68,090 Gas........................................
62,991 88,240 56,172 General * *..
53.440 59.186 21.137 Total Company..................
320,031 369.4 %
293,622 Subsidiaries...............
7.015 6.243 6.075 Total construction expenditures......
327,046 375,739 299,697 less: AFDC...
5,640 5,000 6,113 Add: Sinking funds and debt maturities and refinancings.
157,851 72,901 120,957 Add: Fort St. Vrain decommissioning.
2.500 Total capital requiremen ts..........................
$ 493.037
$ 453.640
$ 426.767 1
- C4pital requirements for Electric Production include approximately $121 million.for Fort St. Vrain repowering and approximately $70 million for pollution control equipment at Hayden.
I
- Capital requirements in the ' General' category include assets leased under a leasing program. The 1997 and 1998 amounts include approximately $40 million of expenditures for automated electric and gas meter reading equipment.
The construction programs of the Company and its subsidiaries are subject to continuing review and modification. In particular, actual construction expenditures may vary from the estimates due to changes in the 30
l l
l electric system projected load growth, the desired reserve margin and the availability of purchased power, as well
- as attemative plans for mee'.ing the Company's long-term energy needs. In addition, the proposed merger with j
SPS, the Company's ongoing evaluation of merger, acquisition and divestiture opportunities to support corporate l
strategies, and future requirements to install pollution control equipment may impact actual capital requirements (See Note 3. Merger, Note 4. Acquisition and Divestiture of Investments and Note 9. Commitments and Contingencies - Environmental Issues in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
CapitalSources At December 31, 1996, the Company and P subaldiaries estimated that their 1997-1999 capital requirements will be met principally with a combination of funds from external sources and funds from operations. The Company and its subsidiaries may meet their extemal capital requirements through the issuance of first collateral trust bonds, preferred and/or common stock, by increasing the level of borrowing under PSCCC's medium-term note program or through the issuance of commercial paper or through short-term borrowing under committed and uncommitted bank borrowing arrugements discussed below. The financing needs are subject to continuing review and can change depending on market and business conditions and changes, if any, in the construction programs and other capital requirements of the Company and its subsidiaries.
Registration Statements On August 30.995, the Company filed a registration statement with the SEC for the issuance of 3 million shares of conunon stock and 3 million rights to purchase common stock appurtenant thereto to be issued under the Company's Automatic Dividend Reinvestment and Common Stock Purchase Plan (" Dividend Reinvestment Plan") for the purpose of funding its construction program and other general corporate purposes.
The Dividend Reinvestment Plan allows its shareholden to purchase additional shares of the Company's common stock through the reinvestment of cash dividends and the purchase of additional shares of common stock with optional cash payments.
la 1994, the Company filed a registration statement with the SEC for the issuance of First Collateral Trust Bonds and cumulative preferred stock for the purpose of funding its construction program, refunding certain issues of its cumulative preferred stock and other general corporate purposes. The aggregate principal amount of first collateral trust bonds, plus the aggregate par value of shares of cumulative preferred stock, will not exceed
$306 million. On May 31,1996, the Company issued $125 million aggregate principal amount of its First Collateral Trust Bonds.
On October 24,1996, the Company filed a registration statement with the SEC for the issuance of $400 million aggregate principal amount of First Collateral Trust Bonds through one or more series of medium-term notes. On November 13, 1996, the Company established a $250 million Secured Medium-Term Note Program, Series B. As of January 31,1997, $150 million of the Series B medium-term notes had been issued.
' Company's Indentures The Company's Indenture dated as of December 1,1939 (the "1939 Indenture"), which is a mortgage on the Company's electric and gas properties, permits the issuance of additional first mortgage bonds to the extent of 60% of the value of net additions to the Company's utility property, provided net earnings before depreciation, taxes on income and interest expense for a recent twelve month period are at least 2.5 times the annual interest requirements on all bonds to be outstanding. The 1939 Indenture also permits the issuance of additional bonds on the basis of retired first mortgage bonds, in some cases with no requirement to satisfy such net camings test. At December 31,1996, the amount of ret additions would permit (and the net eamings test would not prohibit) the issuance of approximately $365 million of new bonds (in addition to the $250 million principal amount of secured j
medium-term notes discussed above) at an assumed annual interest rate of 7.80%. At December 31,1996, the amount of retired bonds would permit the issuance of $718.2 million of new bonds.
31
He 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 tmstee of an equal principal amount of first mortgage bonds issued under the 1939 Indenture. If the bonds issued under the 1939 Indenture are to be issued on the basis of property additions, first collateral trust bonds may be issued under the 1993 Indenture only if net eamings 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 31,1996, coverage under the net earnings test was 5.3 times such annual interest requirements.
Company's Restated Articles ofincorporation He 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 ir at least 1.5 times the total of: 1) the annual interest requirements on all indebtedness to be outstanding for more than one year; an(' 1
- the annual dividend requirements on all preferred stock to be outstanding. At December 31,1996, gross incon.e available under this requirement would permit the Company, if allowed under provisions of the Company's Restated Articles of Incorporation, to issue approximately $2.9 billion of additional preferred stock at an assumed annual dividend rate of 6.90%. Coverage of gross income to interest charges was 6.22 at December 31,1996.
He Company's Restated Articles of Incorporation prohibit, without preferred shareholder approval, the issuance or assumption of unsecured indebtedness, other than for refunding purposes, greater than 15% of the aggregate of: 1) the total principal amount of all bonds or other securities representing secured indebtedness of the Company, then outstanding; and 2) the total of the capital and surplus of the Company, as then recorded on its books. At December 31, 1996, the Company had outstanding unsecured indebtedness, including subsidiary indebtedness with the credit support of the Company, in the amount of $231.2 million. He maximum amount permitted under this limitation was approximately $425.4 million at December 31,1996.
Short Term Borrowing Arrangements He Company and certain subsidiaries have available committed and uncommitted lines of credit to meet their short-term cash requirements. He Company, PSCCC, and certain subsidiaries have a credit facihty with several banks which provides $300 million in committed bank lines of credit and is used primarily to support the issuance of commercial paper by the Company and PSCCC, and to provide for direct borrowings thereunder.
Under the facility Cheyenne,1480 Welton, Inc., Fuelco,, e prime and PSRI are provided access to the credit facility with direct borrowings guaranteed by the Company. At Dece.nber 31,19%, $55.3 million remained unused under this faci 6y. 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. His facility expires on November 17, 2000. Also, the Company has individual arrangements for uncommitted bank lines of credit which totaled $75 million, and all remained unused at December 31,1996. Dese individual arrangements expire on December 31,1997. The Company may borrow under uncommitted preapproved lines of credit upon request; however, the banks have no firm commitment to make such loans (see Note 8. Bank Lines of Credit and Compensating Bank Balances in item 8. FINANCIAL STATG1ENTS AND SUPPLEMENTARY DATA).
PSCCC may periodically issue medium-term notes (in addition to the r,hort-term debt discussed above) to supplement the financing / purchase of the Company's customer accounts receivable and fossil fuel inventories. As of December 31,1996 PSCCC had issued and had outstanding $100 million in medium-term notes. The level of financing of PSCCC is tied directly to daily changes in the level of the Company's outstanding customer accounts receivable and monthly changes in fossil fuel inventories, and will vary minimally from year to year although seasonal fluctuations in the level of assets will cause corresponding fluctuations in the level of associated financing.
32
i l
\\
, item 8. Financh! Statements and Supplementary Data i
REPORT OF TIIE AUDIT COMMITTEE OF TIIE BOARD OF DIRECTORS l
The Board of Directors of the Company addresses its oversight responsibility for the consolidated financial statements through its Audit Committee. The Audit Committee meets regularly with the independent certified public accountants and the internal auditor to discuss results of their audit work and their evaluation of the adequacy of the internal controls and the quality of financial reporting.
l In fulfilling its responsibilities in 1996, the Audit Committee recommended to t!ae Board of Directors, subject to shareholder approval, the selection of the Company's independent certified public accountants. The Audit Committee reviewed the overall scope and specific plans of the independent certified public accountants' and
(
internal auditor's respective audit plans, and discussed the independent certified public accountants' management I
letter recommendations, approved their general audit fees, and reviewed their non-audit services to the Company.
The comndttee meetings are designed to facilitate open communications anymg Company management, internal l
auditing, independent certified public accountants, and the Audit Committee. To ensure auditor independence, both the independent certified public accountants and intemal auditor have full and free access to the Audit t
Committee.
i i
J. Michael Powers, Chairman Audit Committee February 24,1997 b
l 33 l
1 REPORT OF MANAGEMENT The accompanying financial statements of Public Service Company of Colorado and subsidiaries have bee prepared by Company personnel in conformity with generally accepted accounting principles consis IJniform System of Accounts of the Federal Energy Regulatory Commission. He integrity and objectivity of th Financial information contained data in these financial statements are the responsibility of management.
elsewhere in this Annual Report on Form 10-K is consistent with that in the financial statements.
De accompanying financial statements have been audited by Arthur Andersen Lif, independent public Management has made available to Arthur Andersen LLP all the Company's and its subsidiaries' accountants.
financial records and related data and has provided to them representations we believe cs be valid and appropriate.
He Company maintains a system of internal control over financial reporting, including the safeguarding of assets against unauthorized acquisition, use or disposition, which is designed to provide reasonable assurance to the Company's management and Board of Directors regarding the preparation of reliable published financial statements and such asset safeguarding. The system includes a documented organizational structure and division of responsibility, established policies and procedures including a code of conduct to foster a strong ethical climate, which are communicated throughout the Company, and the careful selection, training and development of our people. Internal auditors monitor the operation of the internal control system and report findings and recommendations to management and the Audit Committee of the Board of Directors, and corrective actions are taken to address control deficiencies and other opportunities for improving the system as they are identified. The board, operating through its Audit Committee, which is composed entirely of directors who are not officers or employees of the Company, provides oversight to the financial reporting process.
There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even an effective internal contro!
system can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, internal control system effectiveness may vary over time.
ne Company assessed its internal control system as of December 31,1996 in relation to criteria for effective internal control over financial reporting described in " Internal Control - Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of its assessment, the Company believes that, as of December 31, 1996, the Company's system of internal control over external financial reporting, including the safeguarding of assets against unauthorized acquisition, use or disposition, met those criteria.
W. Wayne Brown Wayne H. Brunetti Principal Accounting Officer Chief Executive Officer February 24,1997 o
34
(
l REPORT OFINDEPENDENT PUBLIC ACCOUNTANTS l
TO h.?LIC SERVICE COMPANY OF COLORADO We have audited the accompanying consolidated batsce sheets of Public Service Company of Colorado (a l
Colorado corporation) and subsidiaries as of Iwember 31,1996 and 1995, and the related consolidated l
satements of income, shareholders' equity and cash flows for each of the three years in the period ended l
December 31,1996. 'Ihese 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 f'mancial statements and schedule l
based on our audits.
l We conducted our audits in accordance with generally accepted auditing standards. Those standards require that i
we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Public Service Company of Colorado and subsidiaries as of December 31,1996 and 1995, and the i
results of their operations and their cash flows for each of the three years in the period ended December 31,1996, l
in conformity with generally accepted accountin: principles.
As more fully discussed in Note 11 to the consolidated financial statements, effective January 1,1994, the l
Company changed its method of accounting for postemployment benefits.
t l
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole.
The schedule listed in the index of financial statements is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, I
fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
We have also audited, in accordance with generally accepted auditing standards, the consolidated balance sheets as of December 31,1994,1993 and 1992 and the related consolidated statements of income, shareholders' equity l
and cash flows for each of the two years in the period ended December 31,1993, (none of which are presented herein) and have expressed an unqualified opinion on those financial statements, in our opinion, the information set forth in the selected financial data for each of the five years in the period ended December 31,1996 appearing in item 6 of this Form 10-K, other than the ratios and percentages therein, is fairly stated, in all material respects, in relation to the financial statements from which it has been derived.
ARTHUR ANDERSEN LLP Denver, Colorado February 24,1997 P
35 l
l
PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED BALANCE SIIEETS (Thousands of Dollars)
December 31,1996 and 1995 ASSETS 1996 1995 Property, plant and equipment, at cost:
$ 3,931,413
$ 3,751,321 Electric.
1,035,394 989,215 Gas.
78,225 88,446 Steam and other..
418,262 380,809 Common to all departments.
181.597 192.580 Construction in progress,
5,644,891 5,402,371 2.045.996 1.921.659 Lesa: accumulated depreciation.
3.598.895 3.480.712 Total property, plant and equipment..
46.550 21.776 Investments, at cost, and receivables.
Current assets:
9,406 14,693 Cash and temporary cash investments..
Accounts receivsble, less reserve for uncollectible accounts ($4,049 at December 218,132 124,731 31,1996; $3,630 at December 31,1995) (Schedule II)..
85,894
%,989 Accrued unbilled revenues (Note 1).
31,288 Recoverable purchased gas and electric energy costs - net (Note 1)..
48,972 56,525 Materials and supplies, at average cost..
24,739 35,654 Fuel inventory, at everage cost.
42,826 44,900 Gas in underground storage, at cost (LIFO)..
19,229 Current portion of accumulated deferred income taxes (Note 13)..
44,110 40,247 Regulatory assets recoverable within one year (Note 1).
41.790 35.619 Prepaid expenses and other..
547.157 468.587 Total current assets.
Deferred charges:
304,456 321,797 Regulatory assets (Note 1)..
10,975 10,460 Unamortired debt expense.
64.615 48.457 Other..
380.046 380.714 Total deferred charges.
$ 4.572,648
$ 4.351.789 7he accompanying notes to consolidated 6nancial statements are an integral part of these financial statements.
36
PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS -
-(Thousands of Dollars)
December 31,1996 and 1995 CAPITAL AND LIABILITIES 1996 1995
$ 1,048,447
$ 997,106 Cornmon stock (Note 5)..
389.841
- 346.539
- Retained earnings...
Total common equity...
1,438,288 1,343,645 Preferred stock (Note 5):
140.008 140,008
. Not subject to mandatory redemption..
t Subject to mandatory redemption at par...
39,913 41,289 Long-term debt (Nue 6).
1.259.528 1.195.553 2.877.737 2.720.495 Noncurrent tiabilities:
Employees' postretirement benef ts other than pensions (Note 11).
55,677 49,198 Employees' postemployment benefits (Note 11)..
25,182-23,500 Defueling and decommissioning liability (Note 2),.
23.115 Total noncurrent liabilities..
80.859 95.813 Current liabilities:
Notes payable and commercial paper (Note 7).
244,725
- 288,050 155,030 82,836
. Long-term debt due within one year..
. Preferred stock subject to mandatory redemption within one year (Note 5)..
2,576 2,576 Accounts payable..
254,256 156,109 Dividends payable..
36,973 35,284 9,508 Recovered purchased gas and electric energy costs - net (Note 1)..
21,441 17,462
, Customers' deposits..
58,990 55,393 Accrued taxes...
33,797 32.071
' Accrued intera.;
Current portion of defueling and decommissioning liability (Note 2).
8,665 24,055 Cunent portion of accumulated deferred income taxes (Note 13)..
'4,560 s
69.203
' 78.451 other..
Total current liabilities..
890.216 781.795 Deferred credits:
Customers' advances for construEtion..
50.269 99,519 Unamortized investment tax credits.
105,928 113,184 Accumulated deferred income taxes (Note 13),
539,082 508,143 28.557 32.840 Other...
Total deferred credits..
723.836 753.686 Comrnitments and contingencies (Note 9).
$ 4.572.648
$ 4.351.789 The accompanying notes to consolidated financial statements are an integral part of these financial statements.
a Y
I 37 o
PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Thousands of Dollars, Except per Shan Data)
Years ended December 31,1996,1995 and 1994 1996 1995 1994 Operating revenues:
$ 1,488,990
$ 1,449,096
$ 1,399,836 Electric..
640,497 624,585 624,922 Gas...
i 41.899 36.920 32.626 Other..
2,171,386 2,110,601 2,057,384 Operating expenses:
Fuel used in generation..
195,442 181,995 198,118 Purchased power..
490,428 481,958 437,087 Oss purchased for resale.
393,163 392,680 397,877 Other operating expenses...
336,100 346,026 369,094 Maintenance.
63,908 64,069 67,097 43,376 Defueling and decommissioning (Note 2)..
Depreciation and amortization..
154,631 141,380 139,035 Taxes (other than income taxes).
82,899 81,319 86,408 Income taxes (Note 13).
96.331, 95.357 48.500 1.812.902 1.784.784 f 786.592 Operating income..
358,484 325,817 270,792 Other income and deductions:
Allowance for equity funds used during construction.
757 3,782 3,140 Osin on sale of WestGas Osthering, Inc. (Note 4)..
34,485 Miscellaneous income and deductions - not (Notes 1 and 3)..
(19.015)
(6.837)
(6.014)
(18,258)
(3,055) 31,611 Interest charges:
J laterest on long-term debt..
92,205 85,832 89,005
[
I Amortization of debt discount and expense less premium.
3,621 3,278 3,126 Other irmerest..
57,398 58,109 44,021 i
Allowance for borrowed funds used during construction..
G.344) 0.313)
(4.018) 149.880 143.906 132.134 Net income...
190,346 178,856 170,269 Dividend requirements on preferred stock..
11.848 1 f.%3 12.014 Earnings available for common stock..
178.498 166.893 p 158.255 Sharea of common stock outstanding (thousands):
Year-end..
64.819 63.358 62.155 64.187 62.932 61.547 Weighted everage..
Earnings per weighted average share of common stock outstanding.
M g
M l
l l
I~
The accompanying notes to consolidated financial statements are an integral part of these financial statements.
4 e
4 t
38
i i
j' PUBLIC SERVICE COMPANY OF COLORADO j
l AND SUBSIDIARIES i
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Thousands of Dollars, Except Share Infomaation)
Years ended December 31,1996,1995 and 1994 i
t Counsaan Stock. $5 mar value Prwenium on Retamed Nhares Amount Cosnanos Stock Earniegn I!da!
Balance at December 31,1993..
60,457,375
$ 302,287
$ 608,561
$ 273,335
$ 1,184.183 Not income..
170,269 170,269 Dividends declered 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) lasuance of common stock l
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 Not income..
178,856 178,856 Dividends declared
}
Common stock, $2.04 per share..
(128,587)
(128.587)
Preferred stock, $100 par value..
(9,004)
(9,004)
Preferred stock, $25 par value.
(2,940)
(2,940) lasuance of common stock Employees' Savings Plan..
310,546 1,553 8,152 9,705 Dividend Reinvestment Plan...
889,331 4,447 23,575 28,022 Omnibus incentive Plan..
3.657 19 92 I!!
Balance at December 31,1995..
63,358,128 316,791 680,315 346,539 1,343,645 Net income..
190,346 190,346 Dividends declared Common stock, $2.10 per share.
(135,111)
(135,111)
Preferred stock, $100 par value.
(8,889)
(8,889)
Preferred stock, $25 par value.
(2,940)
(2,940)
Imuence of common stock Employees' Savings Plan..
274,934 1,374 8,420 9,794 Dividend Reinvestment Plan...
809,603 4,048 24,580 28,628 Omnibus incentive Plan..
58,346 292 1,427 1,719 Acquisitions (Note 4)..
317,748 1,589 9,611 11,200 Capital Stock Expense.,
(104)
(104)
Balance at December 31,1996..
64.818.'750
$ 324.004
$ 724.353
$ 389.841
$ 1.438.288 Authorized shares of common stock were 160 million at December 31,1996,1995 and 1994.
The accompanying notes to consolidated financial statements are an integral part of these fmancial statements.
l Il-l L
i l
39 1
PUBLIC SERVICE COhlPANY OF COLORADO AND SUBSIDIARIES CONSOLID ATED STATEhlENTS OF CASil FLOWS (Thousands of Dollars)
Years ended December 31,1996,1995 and 1994 1996 1995 1944 Operating actsvities:
$ 190,346
$ 178,856 5 170,269 Not income..
Adjustments to reconcile net income to net cash provided by operating activities (Note 1):
159,400 145,370 142,843 Depreciation and amortization.
43,376 Defueling and decommissioning expenses..
(34,485)
Gain on sale of WestGas Oathering, Inc.
(7,256)
(5,348)
(5,799)
Amortization of investment tax credits.
60,899 39,170 34,234 Deferred income taxes..
(757)
(3,782)
(3,140)
Allowance for equity funds used during construction.
(88,680) 38,734 (16,281)
Change in accounts receivsble.
20,542 4,246 10,007 Change in inventories..
(31,169) 7,618 (1,695)
Change in other current assets.
88,473 (20,922)
(35,364)
Change in accounts payabic.
(36,615) 24,230 (39,730)
Change in other current liabilities.
(19.550)
(20,385)
(33,920)
Change in deferred amounts..
(9,779)
(5,367) 15,321 Change in noncurrent liabilities.
1.760 3.279 92 Other.,
327,614 385,699 245,728 Net cash provided by operating activities.
investing activities:
(321,162)
(285,516)
(317,138)
Construction expenditures.
757 3,782 3,140 Allowance for equity funds used during construction.
87,000 Proceeds from sale of WestGas Oathering, Inc,.
20,454 2,470 49,438 Proceeds from disposition of propeny, plant and equipment..
3,649 Payment for purchase of companies, net of cash acquired (Note 4)..
(11,485)
(10,249)
(955)
Purchase of other investments..
664 4.898 1.148 Sale of other investments..
(307,123)
(284,615)
(177,367)
Net cash used in investing activities..
Financing activities:
30,115 28,030 38,086 Proceeds from sale of common stock (Note 1).
217,415 101,860 250,068 Proceeds from sale oflong-term notes and bonds (Note I).
(83,356)
(44,713)
(281,835)
Redemption oflong-term notes and bonds..
(43,325)
(36,750) 47,925 Short4erm borrowings - net.
(1,376)
(1,376)
(213)
Redemption of preferred stock..
(133,394)
(127,352)
(122,531)
Dividends on common stock.
(11.857)
(11.973)
(12.016)
Dividends on preferred stock..
(25.778)
(92.274)
(80.516)
Net cash used in financing activities.
(5,287) 8,810 (12,155)
Net increase (decrease) in cash and temporary cash investments..
14.693 5.883 18.038 Cash and ternporary cash investments at beginning of year.
9.406 14,603 5,883 Cash and temporary cash investments at end of year..
The accompanying notes to consolidated financial statements are an integral part of these financial statements.
40
I PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31,1996 l.
- 1. Summary of Significant Accounting Policies Business, utility operations and regulation l-i r
He Company is an operating public utility engaged, together with its utility subsidiaries, principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transmission, f
distribution, sale and transportation of natural gas. The Company is subject to thejurisdiction of the CPUC with j
respect to its retail electric and gas operations and the FERC with respect to its wholesale electric operations and l
accounting policies and practices. Over 90% of the Company's electric and gas revenues are subject to CPUC jurisdiction. Cheyenne is subject to the jurisdiction of the WPSC. WGI and TOP are subject to the jurisdiction l
of the FERC. He gas marketing, power brokering and other operations of e prime and TOG are not regulated.
r Regulatory assets and liabilities The Company and its regulated subsidiaries prepare their financial statements in accordance with the l
provisions of SFAS 71, as amended. SFAS 71 recognizes that accounting for rate regulated enterprises should I
l reflect the relationship of costs and revenues introduced by rate regulation. A regulated utility may defer l
recognition of a cost (a regulatory asset) or recognize an obligation (a regulatory liability) if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in revenues. On January 1, 1996, the Company adopted SFAS 121 which imposes stricter criteria for the continued recognition of regulatory l
assets on the balance sheet by requiring that such assets be probable of future recovery at each balance sheet date.
l The adoption of this statement did not have a material impact on the Company's results of operations, financial l
position or cash flow. He following regulatory assets are reflected in the Company's consolidated balance sheets:
Recovery 1996 1995 Through j
(Thousands of Dollars) f Nuclear decommissioning costs (Note 2)...
$ 89,731
$ 97,801 2005 Income taxes (Note 13)...........................
98,355 110,617 2006 Employees' postretirement benefits other than pensions (Note 11).....
54,449 47,600 2013 l
Early retirement costs (Note 11)................
15,505 24,366 1998 Employees' postemployment benefits (Note 11).............
24,797 23,500 Undetermined Demand-side management costs.,...........................
41,462 30,188 2002 Unamortized debt reacquisition costs..........................
19,914 21,940 2024 Other............
4.353 6.032 1999 Total.................
348,566 362,044 i*
Classified as current................
44.110 40.247 Classified as noncurrent.....
$304.456
$321.797 f
Certain costs associated with the Company's DSM programs are deferred and recovered, along with the l
associated return, in rates over five to seven year periods through the DSMCA. Non-labor incremental expenses, carrying coats associated with deferred DSM costs and incentives associated with approved DSM programs are i
recovered on an annual basis. Costs incurred to reacquire debt prior to scheduled maturity dates are deferred and amortized over the life of the debt issued to finance the reacquisition or as approved by the applicable regulatory l
authority.
41 l
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 31,1996, are The regulatory assets of the Company and its regulated subsidiaries as of December The Company believes it will reflected in rates charged to customers over the recovery periods noted above.
in the event that a portion of the Company's operations is no longer continue to be subject to rate regulation, subject to the provisions of SFAS 71 as a result of a change in regulation or the effects of competition Company could be required to write-off related regulatory assets, determine any impairment to other asset resulting from deregulation and write-down any impaired assets to their estirnated fair value.
The CPUC On January 27, 1997, the CPUC issued its order on the Company's 1996 gas rate case.
allowed recovery of postemployment benefit costs on an accrual basis under SFAS 112 and denied amortiza the approximately $8.7 million regulatory asset recognized upon the adoption of SFAS 112 (see Note 11.
)
Employee Benefits - Postemployment Benefits). The Company is appealing the decision related to this iss addressing the impact of this decision on the future recovery of the electric jurisdictional portion of postemployment benefit costs totaling approximately $13.8 million. Le Company believes that it will be successful on appeal and that the associated regulatory asset is realizable. If the appeal is unsuccessful, these amounts will be written off.
Recovered /Recowrable purchased gas ami electric energy wsts - net The Company's and Cheyenne's tariffs contain clauses which allow recovery of certain purchased gas and electric energy costs in excess of the level of such costs included in base rates. Currently, these cost adjustment
/
tariffs are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred. The cumulative effects are recogr.ized as a current asset or liability until adjusted by refunds or collections through future billings to customers. He CPUC's order related to the Company's merger rate filing modified and replaced the Company's l
ECA with an ICA, which allows for a 50%/50% sharing of certain fuel and energy cost increases and decreases among customers and shareholders (see Note 9. Commitments and Contingencies - Regulatory Matters).
Otherproperty Property, plant and equipment includes approximately $18.4 million and $25.4 million, respectively, for costs associated with the engineering design of the future Pawnee 2 generating station and certain water rights located in southeastern Colorado, also obtained for a future generating station. The Company is earning a return on these investments based on the Company's weighted average cost of debt and preferred stock in accordance with a CPUC rate order.
Non-utility subsidiaries The Company's net investment in its non-utility subsidiaries approximated 4.5% of common equity at December 31,1996. The subsidiaries are principally involved in non-regulated energy services, the management of real estate and certain life insurance policies and the financing of certain current assets of the Company.
Afanagement estimates The preparation of financial statements, in conformity with generally accepted accounting principles, requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
J b
3 42
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Consolidation Re 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.
Staternents of cashflows For purposes of the consolidated statements of cash flows, the Company and its subsidiaries consider all temporary cash investments to be cash equivalents. nese temporary cash investments are securities having original maturities of three months or less or having longer maturities but with put dates of three months or less.
Income taxes and interest (excluding amounts capitalized) paid:
1996 1995 1994 (Thousands of Dollars)
Income taxes......
$ 66,871
$ 58,662
$ 41,763 Interest...
$ 144,533
$ 140,823
$ 126,250 Non-cash transaaion.>.
Shares of common stock (274,934 in 1996,310,546 in 1995 and 334,223 in 1994), valued at the market price on date of issuance (approximately $10 million for each year), were issued to the Employees' Savings and Stock Ownership Plan of Public Service Company of Colorado and Participating Subsidiary Companies. The estimated issuance values were recognized in other operating expenses during the respective preceding years.
Shares of common stock (6,673 in 1996,3,390 in 1995 and 7,892 in 1994), valued at the market price on the date of issuance ($0.2 million in 1996, $0.1 million in 1995 and $0.2 million in 1994), were issued to certain executives pursuant to the applicable provisions of the executive compensation plans.
During 1996, the Company exchanged 317,748 shares of its common stock valued at approximately
$11.2 million in connection with the acquisition of TOG. During 1994, the Company sold all of its outstanding common stock of WGG (see Note 4. Acquisition and Divestiture of Investments). Cash flows from operating activities reflect the changes in assets and liabilities, net of the effeas from these acquisitions and divestiture.
He stock issuances referenced above were non-cash financing activities and are not reflected in the consolidated statements of cash flows.
A $40.5 million capital lease obligation was recognized in 1995 in connection with a 30-year gas storage facility agreement. Additionally, other capital lease obligations totaling approximately $0.1 million were recognized in 1995. A $16.8 million capital lease obligation was incurred for computer equipment in 1994.
Property, depreciation and amorti:.ation 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. He cost of units of property retired, together with cost or removal, less salvage, is charged against accumulated depreciation.
43
NOTES TO CONSOUDATED FIN ANCI AL STATEMENTS (Continued)
Provisions for depreciation of property, plant and equipment for financial accounting purposes are based on straight-line composite rates applied to the various classes of depreciable property. Depreciation rates include provisions for disposal and removal costs of property, plant and equipment. Depreciation expense, expressed as a percentage of average depreciable property, approximated 2.7% for the year ended December 31,1996 and 2.6%
for the years ended December 31,1995 and 1994. For income tax purposes, the Company and its subsidiaries use accelerated depreciation and other elections provided by the tax laws. Intangible assets are amortized on a straight line basis over their estimated useful lives.
Allowanceforfunds used during construction i
1 AFDC, as defined in the system of accounts prescribed by the FERC and the CPUC, represents the net cost during the period of constmetion of borrowed funds used for construction purposes, and a reasonable rate on funds derived from other sources. AFDC does not represent current cash earnings. 'Ihe Company capitalizes AFDC as a part of the cost of utility plant. The AFDC rates or ranges of rates used during 1996 1995 and 1994 l
were 5.67%-6.78%,7.97% and 6.81 %-8.75%, respectively, j
bliscellaneous income and deductions - net l
Miscellaneous income and deductions - net includes items which are non-operating in nature or, in general, are not considered in the ratemaking process. Such items include, among other things, merger related costs, contributions, gains and losses on the sale of property and certain litigation, severance and environmental costs. Individually, these amounts did not have a material impact on the Company's results of operations.
Income taxes The Company and its subsidiaries file consolidated Federal and state income tax returns. Income taxes i
are allocated to the subsidiaries based on separate company computations of taxable income or loss. Investment tax credits have been deferred and are being amortized over the service lives of the related property. Deferred taxes are provided on temporary differences between the financial accounting and tax bases of assets and liabilities using the tax rates which are in effect at the balance sheet date (see Note 13. Income Taxes).
l Stock-frased compensation As allowed by SFAS 123, the Company uses the intrinsic value based method of accounting prescribed by APB Opinion No. 25, in accounting for its stock-based compensation plan (see Note 11. Employee Benefits -
Incentive Compensation).
Gas in underground stontge Gas in underground storage is accounted for under the last-in, first-out (UFO) cost method. The estimated replacement cost of gas in underground storage at December 31,1996 and 1995 exceeded the UFO cost by approximately $52.2 million and $5.3 million, respectively.
Cash surrender value oflife insurance polleies The following amounts related to COU contracts, issued by one major insurance company, are recorded as a component of Investments, at cost and receivables, on the consolidated balance sheets:
1996 1995 (Thousands of Dollars)
Cash surrender value of contracts..........................
$ 359,136
$ 311,097 Borrowings against contracts..
356.421 308.833 Net investment in life insurance contracts....
2,7_ll 22 4 44 i
l NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
- 2. Fort St. Vrain Overview In 1989, the Company announced its decision to end nuclear operations at Fort St. Vrain and to proceed with the defueling and decommissioning of the reactor. While the defueling of the reactor to the ISFSI was completed in June 1992, several issues related to the ultimate storage / disposal of Fort St. Vrain's spent nuclear fuel remained unresolved.
During 1994, the Company recognized additional expenses aggregating approximately $43.4 million for increased costs associated with defueling and decommissioning and the impairment of certain property and inventory. He additional expense was primarily associated with radiation levels in the reactor core being higher than originally anticipated and increased uncertainty related to spent fuel issues. In 1996, the Company and the DOE entered into a contract resolving all the defueling issues. Additionally, in early 1996, the Company announced that the physical decommissioning work at the facility was completed. NRC site release activities are continuing. He Company requested the NRC to terminate the Part 50 license and it is anticipated that the license will be terminated by mid-1997.
Fort St. Vrain is being repowered as a gas fired combined cy* *am plant consisting of two combustion turbines and two heat recovery steam generators totaling 471 Mw. He CPCN, which was received in July 1994, provides for the repowering of Fort St. Vrain in a phased approach as follows: Phase 1 A - 130 Mw, commercial operations commenced on May 1,1996, Phase IB - 102 Mw, currently under construction with a 1998 expected in service date and Phase 2 - 239 Mw in 2(X)0. He phased repowering allows the Company flexibility in timing the addition of this generation supply to meet future load growth.
Ikfueling On February 9,1996, the Company and the DOE entered into an agreement relating to the disposal of Fort St.
Vrain's spent nuclear fuel. As part of this agreement, the Company has agreed to the following: 1) the DOE assumed title to the fuel currently stored in the ISFSI, 2) the DOE will assume title to the ISFSI and will be responsible for the future defueling and decommissioning of the facility, 3) the DOE agreed to pay the Company $16 million for the settlement of claims asso-tM with the ISFSI, 4) ISFSI operating and maintenance costs, including licensing fees and other regulatory costs, will be the responsibility of the DOE, and 5) the Company provided to the DOE a full and complete release of claims against the DOE resolving all contractual disputes related to storage / disposal of Fort St. Vrain spent nuclear fuel. On December 17, 1996, the DOE submitted a request to the NRC to transfer the title of the ISFSI.
His request is being reviewed by the NRC and the Company anticipates approval in mid-1997.
As a result of the DOE settlement, coupled with a complete review of expected remaining decommissioning 1
costs and establishment of the anticipated refund to customers, pre-tax camings for 1996 were positively impacted by approximately $16 million. In accordance with the 1991 CPUC approval to recover certain deconunissioning costs,50%
of any cash amounts received from the DOE as part of a settlement, net of costs incurred by the Company, including legal fees, is to be refunded or credited to customers. While the amount to be refunded to customers has not yet been finally detennined, the Company established an $8 million liability for such refunds.
Ikcommissionbrg Following the 1991 CPUC approval, effective July 1,1993 the Company began collecting from customers decommissioning costs expected to total approximately $124.4 million (plus a 9% carrying cost). Such amount, which is being collected over a twelve year period, represented the inflation-adjusted estimated remaining cost of decommissioning activities not previously recognized as expense at the time of CPUC approval. At December 31,1996, approximately $89.7 million of such amount remains to be collected from customers and, therefore, is reflected as a regulatory asset on the consolidated balance sheet. He amount recovered from customers each year is approximately
$13.9 million.
45
NOTES TO CONSOLIDATED FIN ANCIAL STATEMENTS (Continued) f the Company and the decommissioning contractors announced that the physical On March 22, 1996, decommissioning activities at the facility have been completed. Additionally, the fmal site survey was complet October 1996 with only the NRC site release remammg to be obtained. At December 31,1996, a remammg $8 defueling and decommissioning liability was reflected on the consolidated balance sheet. The Compan remalmng decommissioning liability is adequate to complete all fmal decommissioning activities.
Under NRC regulations, the Company is required to make filings with, and obtain the approval of, the NR reganiing certain aspects of the Company's decommissioning proposals, including funding. On Janu NRC accepted the Company's funding aspects of the decommissioning plan, which for several years in an unsecured irrevocable letter of credit. In December 1996, the Company placed $8.5 million in a trust to s remaming funding requuements. %ese funds are restricted for decommissioning expenditures and any will remain in this tmst until the ?!RC releases the Company from further obligation, which is anticipated to occ mid-1997.
NudearInsurunce During commercial operation and defueling, the Company participated in a federally mandated program provide funding in the event public liability claims arose from a nuclear incident which exceeded Under the requirements of the Price-Anderson Act, the Company remains subject to potential insurance capacity.
assessments of up to $79 million per incident, in amounts not to exceed $10 million per incident per year. he C 17,1994 and, therefore, remains subject to was granted an NRC waiver from participation in this program on February assessments levied in response to incidents prior to such date. He Company continues to maintain prima nuclear liability insurance of $100 million for the Fort St. Vrain site and the adjoining ISFSI.
On June 7,1995, the NRC granted the Company an exemption from the requirement to purchase nuclear property damage and decontammation coverage following an envimnmental assessment and find impact. he Company maintains coverage of $10 million to provide property damage and decontam the event of an accident involving the ISFSI.
- 3. Merger On August 22,1995, the Company, SPS, a New Mexico corporation, and NCE, a newly formed Delaw corporation, entered into a Merger Agreement providing for a business combination as peer firms Company and SPS in a " merger of equals" transaction. Based on outstanding common stock of the C December 31,1996, the Merger would result in the common shareholders of the Company owning 63 % of the c equity of NCE and the common shareholders of SPS owning 37% of the common equity of NCE. I NCE filed its application with the SEC to be a registered public utility holding company and the parent co Company and SPS.
he Merger he shareholders of the Company and SPS appmved the Merger Agreement on January 31,1996.
is subject to customary closing conditions, including the receipt of all necessary govemmental approv of all necessary govenunental filings, including approvals and findings of state utility regulators in Colorado New Mexico, Wyoming and Kansas as well as the approval of the FERC, the NRC, the SEC, the Federal T Commission and the U.S. Department of Justice in addition to the expiration or termination of the applicable wa The required periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 ("HSR"), as amended.
authorizations from the CPUC, the Public Utility Commission of Texas, the WPSC, the New Mexico Public U Commission, the Kansas Corporation Commission, the NRC and the U.S. Department of Justice have been o De waiting period under the HSR Act has expired. Related to FERC approval, a non-unanimous settlement a has been reached and hearings were held in late September 1996. On Jan'ary 23,1997, the sole party oppos settlement filed a notice with the FERC withdrawing all of its pleadings. %e Company has requested that the give the matter expedited consideration. A fmal FERC order is expected in March 1997. Le Compan SEC will make its ruling on the Merger within 30-60 days following the FERC decision. While timing of the ef 46
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) date of the Merger is primarily dependent on the regulatory process, it is currently expected that the Merger will be completed in the second quarter of 1997.
A transition management team, consisting of executives from each company, is working toward the common i
goal of creating one company with integrated operations to achieve a more efficient and economic utilization of facilities and resources. It is management's intention that NCE begin realizing certain savings upon the consummation of the Merger and, accordingly, costs associated with the Merger and the transition planning and implementation are expected to negatively impact eamings during 1997. He Company recognized costs associated with the Merger of approximately
$7.2 milhon in 1996 and $4.1 million in 1995. He Merger is expected to qualify as a tax-free reorganization and as a pooling of interests for accounting pumoses he Company recognizes that the divestiture of its existing gas business or certain non-utility ventures is a possibility under the new registered holding company structure proposed as part of the merger with SPS. He Company is seeking approval from the SEC to maintain these businesses and currently does not anticipate that divestiture will be required. If divestiture is ultimately required, the SEC has historically allowed companies sufficient time to accomplish divestitures in a manner that prutects shareholder value.
- 4. Acquisition and Divestiture of Investments Proposed Acquisition of Yorkshire Electricity On February 24,1997, the Company and AEPjointly announced that they have reached agreement with the board of directors of Yorkshire Electricity, a UK regional electricity company, on the terms of a recommended cash tender offer for all of the outstanding and to be issued ordinary shares of Yorkshire Electricity. He Company and AEP. through a joint venture named Yorkshire Holdings, are offering the equivalent of US $15.02 (9.27 pounds) per ordinary share, for a total purchase price of approximately US $2.4 billion (1.5 billion pounds). He boards of directors of the Company and AEP have approved the transaction.
He board of directors of Yorkshire Electricity has agreed to recommend the offer to Yorkshire Electricity's shareholders. He offer will be made through Yorkshire Holdings, a wholly-owned subsidiary of Yorkshire Power, a newly formed UK corpo-ation owned equally by the Company and AEP.
Consummation of the Proposed Acquisition is subject to customary conditions in the UK, including regulatory clearance and acceptance of the offer by holders of at least 90% of the outstanding shares of Yorkshire Electricity. Yorkshire Holdings may waive the latter condition when it has received acceptances of its offer and has otherwise acquired shares which in total represent more than 50% of the outstanding shares of Yorkshire Electricity. The Company cannot predict at this time whether or not these conditions will be met or waived.
If the Proposed Acquisition is completed, the Company would have an indirect 50% ownership interest in Yorkshire Electricity, which would be accounted for using the equity method of accounting.
Acquisition of Texas-Ohio Gas, Inc. and Texas-Ohio Pipeline, Inc.
Effective September 1,1996, the Company and e prime, a wholly-owned subsidiary, acquired all of the outstanding stock of TOG and TOP in exchange for a combination of common stock of the Company and cash.
Such acquisitions were accounted for using the purchase method and the acquired assets and liabilities have been valued at their estimated fair market values as of the date of acquisition. Rese companies are primarily engaged l
in gas brokering and marketing activities and are subsidiaries of e prime.
1 l
l 47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Divestiture of Fuel Resources Development Co.
Since 1993, the Company has been pursuing the divestiture of all properties owned by Fuelco, a wholly-owned subsidiary which was primarily involved in the exploration and production of oil and natural gas. The Company recognized the estimated effects of the divestiture in the fourth quarter of 1993 and sold the remaining properties in 1994 and 1996 at approximately net book value.
WestGas TransColorado, Inc.
1 In September 1995, WGT sold its one-third interest in the TransColorado Gas Transmission Company j
for $3.8 million, which approximated net book value.
j i
Acquisition of Young Gas Storage Company On June 25,1995, the Company acquired all of the outstanding stock of YGSC for $6.3 million. The acquisition was accounted for using the purchase method. On February 1,1996, the Company contributed the common stock of YGSC to e prime. YGSC owns a 47.5% general partnership interest in Young Storage, which owns and operates an underground facility in northeastern Colorado.
Sale of WestGas Gathering, Inc.
In August 1994, the Company sold all of its outstanding common stock of WGG, its wholly-owned i
subsidiary, and certain related operating assets of the Company which were used by WGG for approximately $87 million, subject to certain final closing adjustments. The Company recognized a pre-tax gain of approximately
$34.5 million ($19.5 million after-tax or approximatdy 31 cents per share). In the first quarter of 1995, the Company recognized $2.1 million of this gain as an amount to be refunded to customers in accordance with a March 30,1995 settlement with the OCC. The refund was completJ in late 1995.
- 5. Capital Stock Common Stock During 1991, the Company's Board of Directors declared a dividend of one common share purchase right
("right") on each outstanding share of the Company's common stock. All common shares issued will contain this right. Each right stipulates an initial purchase price of $55 per share and also prescribes a means whereby the resulting effect is such that, under the circumstances described below, shareholders would be entitled to purchase additional shares of common stock at 50% of the prevailing market price at the time of exercise. These rights are not currently exercisable, but would become exercisable if certain events occurred related to a pe-son or group acquiring or attempting to acquire 20% or more of the outstanding shares of common stock of the Company. On August 22,1995, in connection with the proposed merger (see Note 3), the Company's Rights Agreement was amended to provide that NCE will not be considered an " Acquiring Person" as a result of the execution, delivery, and performance of the Merger Agreement.
In the event 'a takeover results in the Company being merged into an acquiror, the unexercised rights enuld be used to purchase shares in the acquiror at 50% of market price. Subject te certain conditions, if a person or group acquires at least 20% but no more than 50% of the Company's common stock, the Company's Board of Directors may exchange each right held by shareholders other than the acquiring person or group for one share of common stock (or its equivalent).
If a person or group successfully acquires 80% of the Company's conunon stock for cash, after tendering for all of the common stock, and satisfies certain other conditions, the rights would r.ot operate. The rights expire 48
n.
_.. ~.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) on March 22,2001; however, each right may be redeemed by the Board of Directors for one cent at any time prior to the acquisition of 20% of the common stock by a potential acquiror.
l
)
hrferralStock 1996 1995
_ hre Asmount hres Amount (Thousands (thousneds of Dullars) of thdtars)
Cumuistive preferm wk, $100 par value:
Authorized.
g g
1 lesued and outstanding:
Not subject to mandatory redemption:
100.000 10,000 100,000 10,000 l
4.20% series...
4 41/4% series (includes $7,500 premium)...
175.000 17,508 175.000 17.508 i
41/2% series.....
65,000 6,500 65,000 '
6,500 s
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 t
7.15 % series.
7.50 000 25.000 250.000 25.000 f
I Total..
1.050.000 105.008 1.050.000 105.008 l
Subject to mandetory redemption:
7.50% series..
216,000 21,600 216,000 21,600 8.40% series.
208.892 20.889 222.652 2M 424,892 42,489 438,652 41,865 Less: Preferred stock subject to mandatory redemption within one year.
d5.760)
C.576) d5.760) d.576)
Total..
399,I32 5
39,913 412,892 41,289 Cuandative preferred stock, $25 par value:
Authorized..
4.000.000 g
Issued and outstanding:
8 Not subject to mandatory redemption:
l 8.40% series...
1.400.000 35.000 1.400.000 35.000 i
The preferred stock may be redeemed at the option of the Company upon at least 30, but not more than f
60, days' notice in accoraance with the following schedule of prices, plus an amount equal to the accrued dividends to the date fixed for redemption:
I Cumulative prefe-red stock, not subject to mandatory redennption:
i
$100 par value, all series: $101 per share.
$25 par value,8.40% series: $25.25 per share.
j r
Cisnulative preferred stock, subject to mandatory redemption:
l c
t 7.50% series: $101.75 per share on or prior to August 31,1997, reducing each year thereafter by $0.25 per share until August 31,2003, after which the redemption price is $100 per share; 8.40% series: $102 per share
[
on or prior to July 31,1997, and reducing each year thereafter by $0.25 per share until July 31, 2004, after which
'e the redemption price is $100 per share.
. l In 1997 and in each year thereafter, the Company must offer to repurchase 12,000 shares of the 7.50%
I 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 i
i to the date set for repurchase. Consequently, this preferred stock to be redeemed is classified as preferred stock 49 i
?
i
.,m._
_. m
NOTES TO CONSOLIDATED FIN ANCI AL STATEM ENTS (Continued) consolidated balance sheet, In 1996 subject to mandatory redemption within one year in the December 31,1996 and 1995, the Company repurchased 13,760 shares of the 8,40% cumulative preferred series subject to mand f
redemption. In 1994, the Company repurchased 2,133 shares of the 8.40% cumulative preferred serie No other changes in preferred stock occurred in the three years ended December 31, l
l mandatory redemption, f
- 1996,
- 6. Long Term Debt 1996 _
1995 (Thousands of Dettars)
Public Service Company of Colorsdo:
First CollateralTrust Bonds:
$ 102,667 5 102,667 6% series, due January 1,2001.
134,500 134,500 6 3/8% series, due November I,2005..
125,000 71/8% series, due June 1,2006.
I10,000 110,000 71/4% series, du, January 1,2024.
First Mortgage Bonds; 60,000 95,000 57/8% 63/4% series, due May 1,1996 - July 1,1998..
100,000 100,000 81/8% series, due March 1,2004..
225,000 225,000 83/4%-97/8% series, due July 1,2020 March 1,2022, 22,500 23,000 Pollution Control Series A,5 7/8%, due March I,2004..
27,250 27,250 Pollution Control Series F,7 3/8%, due November I,2009.
79,500 79,500 Pollution Control Series 0,5 5/8% - 5 7/8%, due April I,2008 - April 1,2014.,
50,000 50,000 Pollution Control Series II,51/2%, due June 1,2012.
Secured Medium-Term Notes, Series A:
183,500 151,500 6.05% - 9.25%, due Jan 15, 1996 - November 25, 2003..
13 24 Unamortized premium..
(5,032)
(4,568) 31,2025..
53.567 Unamortized discount..
40.070 Capital lease obligations,6.68-14.65%, due in installments through May 1,263,968 1,147,440 Cheyenne Light, Fuel and Power Company:
First Mortynge Bonds:
4,000 4,000 7 7/8 % series, due April I,2003.
8,000 8,000 7,50% series, due January 1,2024, 7,000 7,000 Industrial Development Revenue Bonds,7.25%, due September 1,2021.
PS Colorado Credit Corporation, Inc.:
Unsecured Medium-Term Notes, Series A:
100,000 80,000 5.75 % - 6.03 %,due November 24,1997 - December I,1998..
1480 Welton, Inc.:
31,506 31,814 13.25% secured promissory note, due in installments through October 1,2016..
84 135 Natural Fuels Corporation:
Capitallease obligations, 4 71 11.11%, due in installments through November 5,2000..1,414,558 1,278,389 155.030 R2.836 Less: maturities due within one year..
$1.259.52%
$1,195,553 Substantially all properties of the Company and its subsidiaries, other than expressly excepted property, are subject to the liens securing the Company's First Mortgage Bonds or the mortgage bonds and n subsidiaries, Additionally, there is a second tien on the electric property securing the Company's First Collat The Company's First Collateral Trust Bonds are additionally secured by an equal amount of First Trust Bonds.
Mortgage Bonds which bear no interest.
50
l l
l NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The aggregate annual maturities and sinking fund requirements during the five years subsequent to December 31,1996 are (in thoussods of dollars):
Year Maturities Sinking Fund Requirements Total 1997
$ 155,030
$ 810
$ 155,840 1998 76,499 560 77,059 1999 44,196 560 44,756 2000 31,656 560 32,216 2001 8,302 560 8,862 The Company and Cheyenne expect to satisfy substantially all of their sinking fund obligations through the application of property additions.
- 7. Notes Payable and Commercial Paper Information regarding notes payable and commercial paper for the years ended December 31,1996 and 1995 is as follows:
1996 1995 (Thousands of Dollars)
Notes payable to banks (weighted average interest rates of 5.98% at December 31,1996 and 6.12% at December 31,1995)...
$ 18,375
$ 45,800 Commercial paper (weighted average interest rates of 6.10% at December 31,1996 and 6.21 % at December 31,1995)...
226.350 242.250
$ 244 7E
$_288p50 1
Maximum amount outstanding at any month-end during the period....
$ 306.675
$_329J75 Weighted average amount (based on the daily outstanding balance) outstanding for the period (weighted average interest rates of 5.63 % for the year ended December 31,1996 and 6.18% for the year ended December 31,1995)..
$ 250,324
$.292J26
- 8. Bank Lines of Credit and Compensating Bank Balances Arrangements by the Company and its subsidiaries for committed lines of credit are maintained entirely by fee payments in lieu of compensating balances. Arrangements for uncommitted lines of credit have no fee or compensating balance requirements.
The Company, PSCCC, and certain subsidiaries have entered into a credit facility with several banks providing $300 million in committed bank lines of credit. The credit facility, which is used primarily to support the issuance of commercial paper by the Company and PSCCC, alternatively provides for direct borrowings thereunder. Cheyenne,1480 Welton, Inc., Fuelco, e prime and PSRI are provided access to the credit facility with direct borrowings guaranteed by the Company. The facility expires November 17, 2000.
Individaal arrangements for uncommitted bank lines of credit totaled $75 million at December 31,1996, of which all remained unused. The Company may borrow under uncommitted preapproved lines of credit upon request; however, the banks have no firm commitment to make such loans.
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i 51
NOTES TO CONSOI.JI)ATED FIN ANCI AL STATEMENTS (Continued)
- 9. Commitments and Contingencies Regulatory hiatters hierger Rate Filings in connection with the Merger with SPS, in November 1995 the Company filed comprehensive proposals with j the CPUC, the WPSC and the FERC to obtain approval of the Merger and the associated comprehensive proposals fro such regulatory agencies.
On Novenicer 29,1996, and as modified on January 15, 1997, the CPUC issual a written decision appmving the Merger as well the major provisions of a stipulation and agmement entered into among the Company, the CPUC)
Staff, the OCC, and substantially all other parties. De decision establishes a five year performance based regulatory 1
plan and acknowledges that the Merger is in the public intemst. He major provisions of the decision include:
a $6 million electric rate reduction, which was institutal October 1,1996, to be followed by an additiona! $12 e
million electric rate reduction effective with the implementation of new gas rates on Febmary 1,1997 resulting from the 1996 general gas rate case, an annual electric department camings test with the sharing of camings in excess of an i1 % return on equity for e
the calendar years 1997-2001 :,s follows:
Electric Department Sharine of Excess Eamines
/
Retum on Eauity Customens Shareholders 11-12 %
65 %
35 %
12-14 %
50 %
50 %
14-15 %
35 %
65 %
l over 15%
100 %
0%;
the termination of the QFCCA camings test which was to become effective on October 1,1996; e
a freeze in base electric rates for the period thmugh December 31, 2001 with the flexibility to make certam e
other rate changes, including those necessary to r?.sw for the mcovery of DSM, QF and decommissioning costs; a replacement of the Company's ECA with an ICA to allow for a 50%/503 sharing of certain fuel and energy e
cost increases or decreases among customers and shareholders; and the implementation of a QSP which provides for penalties totaling up to $5 million in year one and increasing a
to $11 million in year five, if the Ccmpany does not achieve certain performance measures relating to electric reliability, customer complaints an/ elephone response to inquiries. A new docket is expected to be opened to address the implementation of a r. ward stmeture for performance above certain standards.
De rate nductions, the camings sharing, the QSP and the adoption of an ICA will remain in effect even if the Merger is not consurrunated. He freeze in base electric rates does no' prohibit the Company from filing a general rate case or deny any party the oppo-tunity to initiate a complaint or show cause pmceeding.
Approval of the Merger was received from the WPSC on August 16,1996. Hearings in the FERC proceedings were held in September and a non-unanimous settlement agreement was reached. On January 23, 1997, the sole party opposing the settlement filed a notice with the FERC withdrawing all of its pleadings. Le Company has requested that the FERC give the matter expedited consideration. A final FERC order is expected in March 1997.
52
i NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) i Rate C es On June 5,1996, the Company filed a retail rate case with the CPUC requesting an annual increase in its jurisdictional gas department revenues of approximately $34 million. Intervenor testimony was filed in the third quarter of 1996 with the primary issue being authorized rate of retum on common equity, in January 1997, the CPUC approved an overall increase of $17.6 million with an 11.25% return on equity, effective Febmary 1,1997. On February 20, 1997, the Company filed for rehearing, reargument and reconsideration on the treatment of certain issues (see Note 1).
He Company filed a rate case with the FERC on December 29,1995, requesting a slight overall rate increase (less than 1 %) from its wholesale electric customers. His filing, among other things, requested approval for recovery of OPEB costs under SFAS 106, postemployment benefit costs under SFAS 112 and new depreciation rates based on the Company's most recent depreciation study. Settlement agreements have been reached with all parties and filed with the FERC which recognized recovery of the benefit costs discussed above and results in an overall slight decrease in rates.
A final order is expected to be issued in early 1997.
Elearic and Gas Cost Adjustment Mechanisms During 1994 and 1995, the CPUC conducted several pmceedings to review issues related to the ECA. He CPUC opened a docket to review wi ether the ECA should be maintained in its present form, altered or eliminated, and on Januay 8,1996, combined this docket with the merger docket discussed above. De CPUC decision on the Merger modified and replaced the ECA with an ICA. he ICA, which became effective October 1,1996, allows for a 50%/50% sharing of certain fuel and energy cost increases and decreases among customers and sha eholders.
He CPUC has had an on-going docket to review and prescribe a standardized GCA prucess to determine the pmdence of gas commodity and pipeline delivery service costs incurred by gas utilities. Other issues to be addressed in this docket include whether the GCA should be maintained in its present form, altered or eliminated. He CPUC conducted hearings regarding this matter on February 14, 1997. Additional hearings have been scheduled for March 7, 1997.
De CPUC approved the recovery of certain energy efficiency credits fmm retail jurisdiction customers through the DSMCA in June 1994. He OCC filed an appeal of the CPUC's decision in the Denver District Court. He Denver District Court approved the collection of these credits in June 1995, subject to refund. On April 9,1996, the Denver District Court issued an order affirming the CPUC's decision, however, the OCC appealed this issue to the Colorado Supreme Court. On August 20,1996, the OCC filed a motion for voluntasy dismissal with prejudice with the Colorado Supreme Court which was accepted and effectively resolved this matter.
Federal Energy Regulatory Commission On April 24,1996, the FERC issued Order No. 888, Order No. 889 ad a NOPR. Order No. 888 requires jurisdictional utilities owning, contmiling, or operating transmissiori facilities to file non-discriminatory open-access tariffs that satisfy the comparability standard-i.e., that offer transmission services consistent with what is provided for in their own operations. He FERC required that all such utilities file the single pro forma tariff (combined network and i.
point-to-point tariff) by July 9,1996. The Company has filed the required pro forma tariff. Order No. 888 also provides for the recovery of legitimate, prudent, and verifiable stranded investment costs incurred when existing wholesale requirements customers and retail customers leave utilities' generation systems through FERC jurisdictional open-access tariffs and obtain their electric power from other energy suppliers. He FERC will permit utilities to seek extra contractual recovery of stranded costs associated with wholesale requirements contracts executed prior to July 11, 1994. De FERC is to be the primary forum for utilities seeking to recover stranded costs arising where retail customers become wholesale transmission customers of a utility. In addition, the FERC will allow utilities to seek to recover stranded cw resulting from retail wheeling, but only in circumstances where a stas regulator does not have the authority t, adress 7 tail stranded costs at the time when retail wheeling is required.
i 53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Order No. 889 requires utilities to implement standards of conduct and an Open Access Same-time Information System (" OASIS") to ensure that owners of transmission facilities, including the Company and its affiliates, do not have an unfair competitive advantage in using transmission facilities to market their power. In summary, it requires that utilities completely separate their wholesale power marketing and transmission operations functions. He NOPR on Capacity Reservation Open Access Transmission Tariffs specifies filing requirements to be followed by public utilities in making transmission tariff filings based on capacity reservations for all transmission users. If adopted, the capacity reservation open access tariff would replace the pro forma tariff implemented in Order No. 888.
As required by Order No. 888, the Company filed a compliance transtnission tariff on behalf of itself and Cheyenne on July 9,1996. Le Company made various additional filings with the FERC throughout 1996 to meet the requirements of Order Nos. 888 and 889. On January 29,1997, the FERC issued an order accepting the non-rate terms and conditions contained in the Company's Order No. 888 transmission tariff. He rates set out in that tariff are the same as those proposed by the Company and Cheyenne in an Offer of Settlement submitted in an earlier proceeding and now pending before the FERC for review.
On March 29,1996, the FERC accepted the request of e prime, a non-argulated subsidiary, for authorization to act as a power marketer, subject to certain conditions. On April 15, 1996, e prime made a required compliance filing, but also submitted a request for rehearing on one of the conditions imposed by the FERC. He FERC accepted the compliance filing, but the request for rehearing is still pending.
EnvironmerdalIssues Environmental Site Geanup As described below, the Company has been or is currently involved with the clean-up of contammation fmm certain hazardous substances. In all situations, the Company is pursuing or intends to pursue insurance clairas and believes it will recover some portion of these costs through such claims. Additionally, where applicable, the Company intends to puniue recovery from other PRPs. To the extent such costs are not recovered, the Company curn:ntly believes it is probable that such costs will be recovered through the rate regulatory process. To the extent any costs are not recovered through the options listed above, the Company would be required to recognize an expense for such unrecoverable amounts.
Under the CERCLA, the EPA has identified, and a Phase Il environmental swiwt has revealed, low level, widespread contamination from hazardous substances at the Barter Metals Company (" Barter") properties located in central Denver. For an estimated 30 years, the Company sold scrap metal and electrical equipment to Baner for reprocessing. He Company has completed the cleanup of this site at a cost of approximately $9 million and has received responses from the Colorado Department of Public Health and Environment ("CDPHE") indicating that no further action is required erlated to these properties. On January 3,1996, in a lawsuit by the Company against its insurance pmviders, the Denver District Court entered final judgment in favor of the Company in the amount of $5.6 million for certain cleanup costs at Barter. Several appeals and cross appeals have been filed by one of the insurance providers and the Company in the Colorado Court of Appeals. He insurance provider has posted supersedeas bonds in the amount of
$9.7 million ($7.7 million attributable to the Barterjudgment). Previously, the Company had received certain
- surance m
settlement proceeds from other insurance pmviders for Barter and other contambt~I sites and a portion of those funds remains to be allocated to this site by the trial court. In addition, the Company expects to recoup additional expenditures beyond insurance proemis through the sale of the Barter pmperty and fmm other PRPs. In August 1996, the Company filed a lawsuit against four PRPs seeking recovery of certain Barter related costs.
PCB presence was identified in the basement of an historic office building located in downtown Denver. He Company was negotiating the future cleanup with the cunent owners; however, on October 5,1993, the owners filed a civil action against the Company in the Denver District Court. He action alleged that the Company was responsible for the PCB releases and additionally claimed other damages in unspecified amounts. On August 8.1994, the Denver District Court entered a judgment approving a $5.3 million offer of settlement between the Company and the building 54
NOTES TO CONSOUDATED FINANCIAL STATEMENTS (Continued) owners resolving all claims. In December 1995, complaints were filed by the Company against all applicable insurance carriers in the Denver District Coun. A trial date regarding the insurance carriers has been established for August 1997.
De Ramp industries disposal facility, located in Denver, Colorado has been designated by the EPA as a Superfund hazardous substance site pursuant to CERCLA. On November 29,1995, the Company received fmm the 1
EPA a Notice of Potential Uability and Request for Information related to such site and the Company has responded to this request. %e EPA is conducting an investigation of the contamination at this site and is in the process of identifying the natme and quantities of hazardous wastes delivered to, pmcessed and currently stored at the site by PRPs. As of the end of 1996, the EPA has not yet developed a site specific plan for the cleanup or remediation, therefore at this time, the l
Company cannot estimate the amount, if any, ofits potential liability related to this matter. It is anticipated that the EPA will notify the Company with the results ofits investigation sometime during 1997.
In addition to these sites, the Company has identified several sites where cleanup of hazardous substances may be required. While potential liability and settlement costs are still under investigation and negotiation, the Company believes that the resolution of these matters will not have a material effect on its financial position, results of operations or cash flows. The Company fully intends to pursue the recovery of all significant costs incurred for weh projects through insurance claims and/or the rate regulatory process.
Emironmental Matters Related to Air Quality and Pollution Contml P
Under the Clean Air Act Amendments of 1990, coal buming power plants are required to reduce f 02 and NOx emissions to specified levels thmugh a phased approach. The Company's facilities must comply with the Phase Il requirements which will be effective in the year 2000. %e Company expects to meet the Phase !! emission standards placed on SO2 thmugh the use of low sulfur coal and the operation of pollution control equipment on certain generation facilities. He Company will be required to modify certain boilers by the year 2000 to reduce the NOx emissions in order to comply with Phase 11 requirements. He estimated Phase 11 costs for future plant modifications to meet NOx requirements is appmtimately $13 million. He Company is studying its options to reduce NOx and SO2 emissions and, currently does not anticipate that these regulations will significantly impact its operations.
Hayden Staun L7ectric Genemring Station On May 21,1996, the Company and the otherjoint owners of the Hayden station reached an agreement, as diseum.cd below, with a conservation organization, the CDPHE and the EPA which pmvides for a complete and final release of all civil claims for violations alleged in complaints filed by the conservation organization, the CDPHE and the EPA against the joint owners. He complaints filed, pursuant to pmvisions of the Federal Clean Air Act, by a conservation organization and the EPA alleged, among other things, that the station exceeded the 20% opacity limitations during various periods extending from 1988 to mid-1995. In August,1996 the U.S. District Court for the District of Colorado entered the settlement agreement which effectively resolved this litigation. %e Company is the operator and owns an average undivided interest of approximately 53% of the station's two generating units.
In connection with the above settlement, thejoint owners of the Hayden station made the following payments in 1996: 1) a $2 million payment to the U.S. Treasury, 2) a contribution of $2 million to a " Land Trust Fund" to be used for the purchase of land and/or conservation casements in the Yampa Valley and 3) a contribution of $250,000 to be used for the conversion of vehicles and/or wood buming appliances to natural gas in the Yampa Valley. He Company's portion of these costs is approximately $2.3 million, which has been expensed in the accompanying financial statements.
Re joint owners have committed to the installation of emission control equipment on both generating units to reduce future particulate (opacity), SO2 and NOx emissions over the next three years. Hejoint owners estimate that the cost of installing emission control equipment capable of reducing the emissions to the levels required under the agreement, consisting of fabric filter dust collectors, time spray dryers and low NOx bumers on both units, is approximately $130 l
million, with the Company's portion totaling approximately $70 million. Also, the settlement includes stipulated future penalties for failure to comply with the terms of the agreement, including specific provisions related to meeting l
l 55
NOTES TO CONSOLIDATED FIN ANCIAL STATEMENTS (Continued) construction deadlines -M with the installation of additional emission control equipment and complying with particulate, 502 and NOx emissions limitations.
Craig Steam Dearic Gmerating Station i
On October 9,1996, a conservation organization filed a complaint in the U.S. District Court punruant to provisions of the Federal Clean Air Act (the "Act") against the joint owners of the Craig Steam Electric Generating j
Station. Tri-State is the operator of the Craig station and the Company owns an undivided interest (acquired in April I
1992) in each of two units at the station totaling approximately 9.7%. He plaintiff alleged that: 1) the station exceeded the 20% opacity limitations in excess of 14,000 six minute intervals during the period extending from the first quarter of 1991 through the second quarter of 1996, and 2) the owners failed to operate the station in a manner consistent with good air pollution contml practices, ne complaint seeks, among other things, civil monetary penalties and injunctive relief.
He Act provides for penalties of up to $25,000 per day per violation, but the level of penalties imposed in any particular l
instance is discretienary. He Company does not believe that its potential liability or the future impact of this litigation on plant operations will have a material impact on the Company's results of operations, financial position or cash flows.
Valmont Stmm Hearic Generating Station l
On July 1,1996, the Company received a Notice of Violation ("NOV") from the CDPHE which alleges 1
inadequate reporting of NOx and SO2 information and excess NOx emissions at the Valmont Steam Electric Generating I
Station for the period January 1,1995 through August 22,1995. He Company has responded to the NOV and believes that the amount of penalties, if any, that may result from such alleged violations would not have a material impact on the Company's results of operations, financial position or cash flows.
(
Purchase Requirements j
Coalpurchases and transportation At December 31,1996, the Company had in place long-term contracts for the purchase of coal through 2017. He minimum remaining quantities to be purchased under these contracts total 78 million tons. He coal purchase prices are subject to periodic adjustment for inflation and market conditions. Total estimated obligations, based on current prices, were approximately $678 million at December 31,1996.
The Company has entered into long-term contracts for the transportation of coal by railroad in Company-owned or leased railcars to existing power plants. Rese agreements, expiring in 2000, provide for a minimum remaining transport quantity of 15 million tons. Contract prices for coal transportation are negotiated
]
based on market conditions and are adjusted periodically for inflation and operating factors. Total estimated obligations, based on current prices, were approximately $31 million at December 31,1996.
Natural gas purchases and transportation The Company and Cheyenne have entered into long-term contracts for the purchase, firm transportation and storage of natural gas. These contracts, excluding the thirty year contract with Young Storage which has been accounted for as a capital lease, expire on various dates through 2002. During 1996, the Company renegotiated contracts with its primary gas pipeline supplier and committed to continue purchasing firm transportation and gas storage services through 2002. At December 31,1996, the Company and Cheyenne have minimum obligations under such contracts of approximately $123 million in 1997 declirting thereafter for a total estimated commitment of approximately $516 million.
l l
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56
-___-_____-_____a
t NOTES TO CONSOLIDATED FINANCI AL STATEMENTS (Continued)
Purchased power l
The Company and Cheyenne have entered into agreements with utilities and QFs for purchased power to meet system load and energy requirements, replace generation from Company-owned units under maintenance and i
during outages, and meet the Company's operating reserve obligation to the Pool.
De Company has various pay-for-performance contracts with QFs having expiration dates through the year 2022. In general, these contracts provide for capacity pryments, subject to the QFs meeting certain contract obligations, and energy payments based on actual power take1 under the contracts. He capacity and energy costs are recovered through base rates, the ECA/ICA and the QFCCA. Additionally, the Company and Cheyenne have long-term purchased power contracts with various regional utilities expiring through 2018. In general, these contracts provide for capacity and energy paymcats which approximate the cost of the sellers. Total capacity and energy payments associated with such contracts were $453 million, $445 million, and $427 million in 1996, 1995 and 1994, respectively.
At December 31,1996, the estimated future payments for capacity that the Company and Cheyenne are obligated to purchase, subject to availability, are as follows:
Regional OFs Utilities Total (Thousands of Dollars) 1997.........
$ 143,236
$ 180,896
$ 324,132 199 8......................
143,502 184,701 328,203 1999.....
143,827 175,662 319,489 2000....
41,910 164,994 306,904 2001..................................
14438 143,894 284,332 2002 and thereafter...
1 000.001 1.270.872 1 270.873 Total...
$1.712.914 12.121.019
$3.833.933 Historically, all minimum coal, coal transportation, natural gas and purchased power requirements have been met.
Other purchases Commitments made for the purchase of materials, plant and equiprnent additions. DSM expenditures and other various items aggregated approximately $478 million at December 31,1996.
Employee Utigation Several employee lawsuits have been filed against the Company involving alleced discrimination and breach of certain fiduciary duties to employees. He Company is actively contesting all such lawas and believes that the ultimate oatcome will not have a material impact on the Company's resuhs of operations, fira ut position or cash flow.
On August 13, 1996, eighty<ight former Information Technology and Systems ("IT&S") employees filed a lawsuit against the Company. He complaint, which was subsequently amended to add two other former IT&S employees, alleges that the Company unfairly amended its severance plan in connection with a restructuring in late 1994 to exclude the IT&S function / positions that were outsourced to IBM, effective Febmary 1,1995. He Company believes that the amended severance plan is lawful and enforceable and believes that the ultimate outcome of the lawsuit will not i
have a material impact on the Company's results of operations, financial position or cash flows.
I l
On July 19, 1996, a class action complaint was filed by fourteen plaintiffs allegedly on behalf of all non-managerial, non-clerical women in the Company's regional facilities. he complaint asserts that the Company has 57
~-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) engaged in company. wide pattern and practice of sexual discrimination, including sexual harassment and reta previous class complaint filed by some of these plaintiffs along with other named plaintiffs, was withdrawn af; Company filed its respcase. h is too early to predict the outcome of the class action complaint. He Company in actively contest the class action and believes the ultimate outcome of the individual plaintiffs' cases will not have a material impact on the Company's results of operations, financial position or cash flows.
Certain employees terminated as part of the Company's 1991/1992 organizational analysis asserted breach contract and promissory estoppel with respect tojob security and breach of the covenant of good faith and fair dealing.
Of the 21 actions filed, the trial court directed verdica in favor of the Company in 19 cases. A jury entered verdicts adverse to the Company in two cases which were subsequently appealed by the Company. On February 6,1997, the Colorado Court of Appeals issued a decision on all issues in favor of the Company. He employees can appeal the decision of the Colorado Court of Appeals to the Colorado Supreme Court. %e Company believes that the uhimate outcome of the lawsuit will not have a material impact on the Company's results of operations, f'mancial position or cash flow.
Union Contnrcts in late December 1995, the Company's contracts with the International Brotherhood of Electrical Workers, local 111 ("lBEW local 111") expired. Previously, an arbitrator had irjected the Company's attempt to terminate the i
contracts on the expiration dates. herefore, negotiatioa of limited issues was reopened. He parties were unable to reach agreement on the contract issues reopened through the negotiation process and, as a result, the Company and IBEW Local 111 entered into binding arbitration on Man h 20,1996, as required under the contracts. On June 4,1996, the arbitrator mled that the Operations, Production and Maintenance ("OP&M") collective bargaining agreement with the Union would continue until May 31, 1997 and that the employees covered by the agreement would receive a wage increase of 3.5% retroactive to December 1995. Such amount had been previously accrued. Subsequent to the arbitrator's decision on the OP&M agreement, the Company and IBEW local 11I came to an agreement on the Meter Reader Order Reader and Field Credit Representative contract with a contract term and a wage increase consistent with the OP&M agreement. At December 31, 1996, approximately 2.090 employees, or 45% of the Company's total workforce, are represented by IBEW local 111.
On June 21,1996, the National Labor Relations Board ordered the Company to irinstate approximately 150 union employees laid off or moved to other positions in the 1994 restructuring. ne Company was ordered to make whole, with interest, any net loss of earnings or other benefits since the layoff. Wirty-two employees were reinstated and, while the final costs associated with the order have not been determined, the Company accrued $2.0 million during 1996 related to this obligation.
In addition, IBEW local 111 filed several grievances during 1996 selating to the employment of certain norr union personnel to perform services for the Company. A decision has been entered on three of the multiple grievances, with two of those decisions requiring that the Company pay union wage rates on new construction jobs performed by outside vendors. He Company has filed suit seeking to reverse one of these decisions and challenging the sebcontracting provision of the labor agreement, all of the outstanding subcontracting grievances and both of the existing adverse decisions as violations of federal law. He Company and the union have entered into negotiations to resolve this dispute over contracting. A decision is expected in March 1997.
Leasing Mgrum The Company and its subsidiaries lease various equipment and facilities used in the normal course of business, some of which are accounted for as capital leases. Expiration of the capital leases range from 1998 to 2025. The net book value of property under capital leases was $49.2 million and $53.7 million at December 31, 1996, and 1995, respectively. Assets acquired under capital leases are recorded as property at the lower of fair-market value or the present value of future lease payments, and are amortized over their actual contract term in 58 l
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) accordance with practices allowed by the CPUC. The related obligation is classified as long-term debt. Executory costs are excluded from the minimum lease payments.
The majority of the operating leases are under a leasing program that has initial noncancellable terms of one year, while the remaining leases have various terms. These leases may be renewed or replaced. No material restrictions exist in these leasing agreements concerning dividends, additional debt, or further leasing. Rental expense for 1996,1995 and 1994 was $25.0 million, $23.5 million and $29.7 million, respectively.
Estimated future minimum lease payments at December 31,1996 are as follows:
Capital Operating Leases Leases (Thousands of Dollars) 1997.......
$ 9,585
$ 20,790 199 8..........
9,392 20,947 1999.....
7,903 18,019 2000....
5,097 16,129 2001........
5,035
-11,880 All years thereafter............
8l.177 20.489 Total future minimum lease payments..
I18,189
$ 108254 less amounts representing interest..
69.035 Present value of net minimum lease payments...
$ 49.154 The Company has in place a leasing program which includes a provision whereby the Company indemnifies the lessor for all liabilities which might arise from the acquisition, use, or disposition of the leased property.
- 10. Jointly-Owned Electric Utility Plants The Company's investment in jointly-owned plants and its ownen, hip percentages as of December 31, 1996 is:
Plant Construction in Accumulatwl Work in Service Depreciation Progrm Ownentdn %
(Thomands of Dollars)
Hayden Unit 1.
38.213 29,860 1,52t, 75.50 Hayden Urit 2 58,211 32.873 300 37.40 Hayden Coinmon Facilities.
2,117 392 3,287 53.10 Craig Units i & 2..
57,057 23,352 647 9.72 Craig Common Fac.!ities Units 1 & 2.
7.714 3.033 958 9.72 Craig Commnn Facilities Units 1.2 & 3..
8,371 3,310 407 6.47 Transmission Facilities, including Sut. stations.
79.166 22.105 95 42.0-73.0 250.849 5
114.025 5
7.220 These assets include approximately 320 Mw of net dependable generating capacity. The Company is responsible for its proportionate share of operating expenses (reflected in the consolidated statements of income) and construction expenditures.
t l
l l
59 l
l l
NOTES TO CONSollDATED FINANCIAL STATEMENTS (Continuer j
- 11. Employee Benefits i
i Pensions
- De Company and Cheyenne maintain a noncontributory defined benefit pension plan covering substantially all employees.
The net pension expense in 1996,1995 and 1994 wr.s comprised of:
1996 1995 1994 (nousands of Dollars) l Service cost.,
$ 14,317
$ 11,659
$ 16,169 l
heerest cost on project 4 benefit obligation..
46,497 46,570 45.518
)
. Actual return on plan assets...
(74,646)
(123,531) 5,844 j
Amortization of not transition asset.
(3,674)
(3,674)
(3,674)
Other items......
24.362 75.521 (56.9961 i
l Net pension expent,e.
6.856 6.545 6.861 j
i De pension plan was amended in 1994 (as discussed below) requiring the use of two sets of assumptions i
in the calculation of the 1994 net periodic pension cost. Significant assumptions used in determining net periodic pension cost were; Apr. Dec Jan. Mar 1996__
1995 1994 1994 7.25 %
8.75 %
8.0 %
7.5 %
j Discount rete..
Expecwl long-term increase in compensation level..
4.0 %
5.0 %
5.0 %
5.0 %
j Expected weighted average long-term rate of return on assets..,
9.75 %
9.75 %
10.5 %
10.5 %
f f
Variances between actual e" perience and assumptions for costs and returns on assets are anortized over A
i the average remaining service lives of employees in the plan.
-l i
A comparison of the actuarially computed benefit obligations and plan assets at December 31,1996 and 1995, is presented in the following table. - Plan assets are stated at fair value and are comprised primarily of corporate debt and equity securities, a real estate fund and government securities held either directly or in commingled funds. De Company and Cheyenne's funding policy is to contribute annually, at a minimum, the I
amount necessary to satisfy the IRS funding standards.
I i
1996 1995 f
(housands of Dollars) i i
Actuarial present value of benefit obligations:
l Vested
$ 514,762
$ 523.539 l
Nonvested..
28.689
' 31.678 543,451 555,217 Effect of projected future salary increases..
85.216 91.810 i
Projected benefit obligation for service rendered to date....
628,667 647,027 Plan assets at fair vain..
(634 967)
(588.314)
Projected benefit obligation in excess of plan assets....
6,300 (58,713)
Unrecognized not loss.
1,110 62,092 I
Prior service cost not yet recognized in not periodic pension cost.
27,758 30,063 Unrecognized net transition asset at January 1,1986, l
being recognized over 17 years......
C2.042)
C5.716)
..e.,
I -
Prepaid pension asset..
$ 13.126 7.726 I
I i
l 1
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
L Significant assumptions used in determining the benefit obligations at the end of each respective year were:
IM6 IMS Disumnt rate.
7.75 %
7.25 %
Expected long-tenn increase in compensation level..
4.25 %
4.0 %
On January 25, 1994, the Board of Directors approved an amendment to the Plan which offered an incentive for early retirement for employees age 55 or older with 20 years of service as well as a Severance Enhancement Program ("SEP") option for these same eligible employees for the period February 4,1994 to April 1,1994. The Plan amendment generally provided for the following retirement enhancements: a) unreduced early retirement benefits, b) three 3 ears of additional credited service, and c) a supplement of either a one-time payment l
equal to $400 for each full year of service to be paid from general corporate funds or a $250 social security supplement each month up to age 62 to be paid by the Plan.
The SEP provided for: a) a one-time severance ranging from $20,000 - $90,000, depending on an employee's organization level, b) a continuous years of service bonus (up to 30 years), and c) a cash benefit of
$ 10,000.
Approximately 550 employees elected to participate in the early retirement / severance enhancement program, of which approximately 370 employees elected the early retirement benefit. The total cost of the program was approximately $39.7 million. These costs were deferred and, effective April 1,1994, are being amortized to expense over approximately 4.5 years in.ccordance with rate regulatory treatment. This amortization period represents the participants' average remaining years of service to their expected retirement date.
l Insotuntary severance program l
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 ofinvoluntary severance costs were accrued, of which $8.7 million reduced pre-tax earnings.
Postretirement benefits other than pensions The Company and Cheyenne provide certain health care and life insurance benefits for retired employees.
A significant portion of the employees become eligible for these benefits if they reach either early or normal retirement age while woriting for the Company or Cheyenne. Historically, the Company has recorded the cost of i
these benefits on a pay-as-you-go basis, consistent with the regulatory treatment. Effective January 1,1993, the Company and Cheyenne adopted SFAS 106 costs based on the level of expense determined in accordance with the CP1 nd WPSC. SFAS 106 requires the accrual, during the years that an employee renders service to the Cor..p uy, of the expected cost of providing postretirement benefits other than pensions to the employee and the employee's beneficiaries and covered dependents.
p 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 emts as provided in the Fort St. Vrain Supplemental Settlement Agreement. On January 13, 1995, the CPUC arroved the 1994 revision to the l
Supplemental Settlement Agreement, which accelerated the recovery of OPEB costs to comply with SFAS 106 and approved other changes to certain ratemaking principles. The change in recovery was retroactive to January 1, 1994, and accordingly, resulted in an increased OPEB expense for that year and subsequent years.
61 l
NOTES TO CONSOLIDATED FIN ANCI AL STATEMENTS (Continued)
The Company filed a FERC rate case in December 1995 which included a request for approval to rec Effective January 1,1993, Cheyenne began all electric wholesale jurisdiction SFAS 106 costs (see Note 9.).The Company and Cheyenne fund SFA recovering SFAS 106 costs as approved by the WPSC.
external trusts based on the amounts reflected in cost-of-service, consistent with the respective rate orders The net periodic postretirement benefit cost in 1996,1995 and 1994 under SFAS 106 was co 1996 1995 1994 __
Ghousands of Dollars) 6,928 6,027 5
6,101 Service coat.
22,982 24,761 24,111 Interest cost on projected benefit obligation.
(4,500)
(2,5711)
(938)
Return on plan assets..
Amonization of net transition obligation at January 1,1993 12.710 12.710 12.710 assuming a 20 year amortization period.
38,120 40,920 41,984 Net postretirement benefit c~t required by SFAS 100.
(31.271) 0 0.893) 00.266)
OPEB expense recogn zed in accordance with current reg, lation..
6,849 10,027 iI,718 incrosse in regulatory asset (Note 1)..
47.600 37.573 25.855 Regulatory asset at beginning of year..
$ 54,449
$ 47.600
$ 37.573 Regulatory asset at end of year.
Significant assumptions used in determining net periodie postretirement benefit cost were:
Apr. Dec Jan - Mar 1996 1995 1994 1994 7.25 %
8.75 %
8.0 %
7.5 %
Discount rate.
4.0 %
5.0%
5.0 %
5.0 %
Expected long-term increase in compensation level..
9.75 %
9.75%
10.5 %
10.5 %
Expected weighted average long-term rate of return on asseta..
A comparison of the actuarially computed benefit obligations and plan assets at December Plan assets are stateC at fair value and are comprised primarily of 1995 is presented in the following table.
corporate debt and equity securities, a real estate fund, government securities and other sho held either directly or in commingled funds.
1996 1995 Ghousands of Dollarsl Accumulated postretirement benefit obligation:
$ 110,692
$ 122,395 Retireen and eligible beneficiaries.
81,676 93,161 Other fully eligible plan participanta..
90.559 102 2 Other active plan participants.
282,927 318,295 Total.
(63.744)
(41.129)
Plan assets at fair value.
219,183 277,166 Accumulated benefit obligation in excess of plan asseta.
39,847 (11,905)
Unrecognized net gain (loss).
(203.353)
(216.063)
Unrecognized transition obligation..
$ 55,677
$ 49.198 Accrued postretirement benefit obligation Significant assumptions used in determining the accumulated postretirement benefit obli of each respective year were:
1996 1995 7.75 %
7.25 %
Discount rate.
5.0 %
4.5 %
Ultimate health care cost trend rate.
4.0 %
4.0 %
Expected long-term increase in compensation level..
The assumed health care cost trend rate for 1997 is 9.0%, decreasing to 4.5% in 2006 in 0.5% ann A 1% increase in the assumed health care cost trend will increase the estimat increments.
62
I NOTES TO CONSOlJDATED FINANCI AL STATEMENTS (Continued) benefit obligation by $35.1 million, and the service and interest cost components of net periodic postretirement benefit costs by $5.1 million.
Postemployment benefiits The Company and Cheyenne adopted SFAS 112 on January 1,1994, the effective date of the statement.
' SFAS 112 establishes the accounting standards for employers who provide benefits to former or inactive employees after employment but before retirement.(postemployment benefits). At December 31,1996 and 1995, the Company had recorded a $24.8 million and $23.5 million regulatory asset and a corresponding liability on the consolidated balance sheet, assuming a 7.75% and an 7.25% discount rate, respectively. The Company has historically recorded these costs on a pay-as-you-go basis. The Company filed a FERC rate case in December l
1995 and a retail gas rate case in June 1996 which inele: led a request for recovery of all electric wholesale and retailjurisdiction SFAS 112 costs. For discussion regarding the recovery of these costs, see Note i and Note 9.
incentive compensation The Omnibus incentive Pir.n ("OlP") provides for annual and long-term incentive awards for officers and management employees. One million shares of common stock have been authorized for awards under the OIP as it allows for the issuance of restricted shares and/or stock options. The Company recognizes compensation s
expense for restricted stock awards based on the fair value of the Company's common stock on the date of grant, consistent with SFAS 123. Cash, restneted stock awards (restrictions lapse two years from the grant date) and stock option awards (which vest ratably during a three-year period) were made under the OIP during 1996, 1995 and 1994.
As allowed in SFAS 123, the Company applies APB Opinion No. 25 in accounting for its stock-based compensation and, accordingly, no compensation cost is recognized for the issuance of stock options as the exercise price of the options equals the fair-market value of the Company's common stock at the date of grant.
j Assuming compensation cost for stock options granted in 1996 and 1995 had been determined consistent with i
SFAS 123 using the fair-value based method, the Company's reported net income would have been reduced by 1
$0.3 million in 1996 and $0.2 million in 1995 which would not have impacted reported earnings per share for i
1996 and 1995. SFAS 123's method of accounting for stock-based compensation plans has not been applied to options granted prior to January 1,1995 and as a result the pro forma compensation cost may not be representative of that to be expected in future years.
A summary of the Company's stock options at December 31,1996,1995 and 1994 and changes during the years then ended is presented in the table below:
1996 1995 1994 Weighted.
Weighted-Weighted.
Average Average Average Shares Exer ise Price Shares Exercise Priry Shares Exercise Price Outstanding at beginning of year 347,931
$ 29.33 195,744 5
28.53 58,544 28.13 Granted 158,270
$ 35.13 161,000 30.29 149,700 28.73 Exercised (51,673)
$ 30.21 (267) 29.00 Forfeited
.1133 3.0.1)
$ 32.84 (8.546) 29.17 (12.500) $
29.00 Outstanding at end of year 441.227
$ 31.38 347.931 29.33 195.744 28.53 Exercisable at end of year 158.970
$ 29.05
.! E 931 28.52 19.515 28,13 Weighted-average fair value of options granted 5
4.31 5
5.39 L
63
NOTES TO CONSOLID ATED FIN ANCIAL STATEMENTS (Continued) f he fair value of each option grant is estimated on the date of grant using the Black-Scholes Option-Pricing Model with the following weighted-average assumptions:
1996 1995 I
10 years 10 years Expected option life.
11.95 %
16.11 %
Stock volatility.........
6.21 %
7.45 %
+
Risk-free interest rate......
5.8 %
6.6 %
l Dividend yield.,
The Employee incentive Plan ("EIP") provides for cash awards to all employees based on the achievement of corporate goals. Certain performance goals were met in each of the last three years.
1996, $6.4 He expenses accmed under the OIP and the EIP totaled approximately $7.8 million in million in 1995 and $6.0 million in 1994.
In the event that the Company is subject to a change in control, all stock-based awards, such as options and restricted shares, will vest 100% and all performance awards will be paid out inunediately in cash, as if th performance objectives have been obtained through the effective date of the change in control. Th effective, qualifies as a change in control condition.
- 12. FinancialInstruments Fair value offinancialinstruments The following table presents the carrying amounts and fair values of the Company's and subsidiaries' significant financial instruments at December 31,1996 and 1995. The carrying amount of all other instruments appmximates fair value. SFAS 107 defines the fair We -1..~..d4 i /..ument as the amount at which the instmment could be exchanged in a entw' maH c i ween willing parties, other than in a forced or liquidation sale.
1996 1995 Carrying Fair Carrying Fair Amount _
Value Amouin
_ Value (Thousands of dollan)
$ 30,249
$ 30.416 7.575 7.623 42,489 43.685 43,865 45.184 Investments, at cost.
Preferred stock subject to mandatory redemption..
1,370.423 1,404.972 1,229.231 1,307.128 Long-term debt..
The fair value of the debt and equity securities included in Investments, at cost, is estimated based on He debt securities are classified as heid-to-maturity quoted market prices for the same or similar investments.
and the equity securities are classified as available-for-sale. The unrealized holding gains and losses for and equity securities are not significant.
He 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 Compan:, and Cheyenne to regulation, any gains or losses related to the difference between the carrying amount ed the fair value J
financial instruments would not be realized by the Company's shareholders.
Off4alance-sheetfinancial instruments YGSC, a wholly-owned subsidiary of e prime, and the Company have guaranteed 50% of amounts financed under a $32 million Credit Agreement among Young Gas and various lending institutions entered into on 1
64
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 27,1995, This debt financing is for the development, construction and operation of an underground natural gas storage facility in northeastern Colorado.
Concentration of credit risk - accounts receimble No individual customer or group of customers engaged in similar activities represents a material concentration of credit risk to the Company and its subsidiaries.
- 13. Income Taxes The provisions for income taxes for the years ended December 31,1996,1995 and 1994 consist of the following:
1996 1995 1994 (Thousands of Dollars)
Current income taxes:
Federal,.
41.737 5
58,728 5
22.081 State.
951 2.807 (2.016)
Total current income taxes..
42.688 61.535 20.065 Deferred income taxes:
Federal..
53,612 38,006 31,042 State.
7.287 1.164 3.192 4
Total deferred income taxes.
60.899 39.170 34.234 investment tax credits - net.
(7.2),6)
(5.348)
(5.799)
Total provis;on for income taxes.
96.331 95,357 48,500 During 1994, as a result of a detailed analysis of the income tax accounts, the Company recorded a decrease in its income tax liabilities, which served to reduce Federal and state income tax expenses by approximately $21.3 million, or 34 cents per share. The detailed analysis was completed in conjunction with the Company's implementation of the full normalization method of accounting for income taxes as provided for in a rate order from the CPUC.
A reconciliation of the statutory U.S. income tax rates and the effective tax rates follows:
1996 1995 1994 iThousand sf Dullars)
Tax computed at U.S. statutory rate on pre-tax accounting income.
$ 100,337 35.0 % $ 95,975 35 0 % $ 76,569 35 0 %
Increase (decrease) in tax from:
AILwance for funds used during construction..
(1,438)
(0.5)
(2,495)
(0.9)
(2,449)
(1.1)
Amortization ofinvestment tax credits..
(7.256)
(2.5)
(5.348)
(1.9)
(5,792)
(2.6)
Cash surrender value of life insurance policies..
(l l,265)
(3.9)
(9,546)
(3.5)
(7,643)
(3.5)
Amortization of prior flow-through amounts.
10,509 3,6 10,509 3.8 10,509 4.8 Tax accrual adjustment..
(21,262)
(9.7)
Other-net..
5.444 1.9 6.262 23 (1.432)
(0.7) e Total in ome taxes..
$ 96.331 33 6 % $
95.357 34 8 % $ 48,500 22 2 %
The Company and its regulated subsidiaries have historically provided for deferred income taxes to the extent allowed by their regulatory agencies whereby deferred taxes were not provided on all differences between financial statement and taxable income (the flow-through method). To give effect to temporary differences for which deferred taxes were not previously required to be provided, a r ;ulatory asset was recognized. The regulatory asset represents temporary differences primarily associated with prior flow-through amounts and the equity component of allowance for funds used during construction, net of temporary differences related to 65
-~
NOTES TO CONSOUDATED FINANCI AL STATEMENTS (Continued) unamortized investment tax credits and excess deferred income taxes that have result in tax rates (see Note 1).
The tax effects of significant temporary differences representing deferred tax liabilities and assets as o December 31,1996 and 1995 are as follows:
1996 1995 (Thousands of Dollan)
Deferred income tax liabilities:
412.047 5
376,468 Accelerated depreciation and amortiution..
132,149 152,631 Plant basis difb.ances (prior flow-through)..
48,952 50,411 w ;ty funds used during construction..
38,790 36,583 Allowance for u
Pensions..
68.940 50.760 Other..
700,878 666,853 Total..
Deferred income tax assets:
65,278 69,751 Investment tax credits,
63,317 55,654 Contributions in aid of construction.
28.641 52.534 Other..
157.236 177.939 Total..
543.642 5
438.914 Net deferred income tax liability..
the Company has cumulative AMT cariyforwards of approximately $3.8 As of December 31, 1996, A valuation allowance has not teen million and state tax credit carryforwards of approximately $1.6 million.
recorded as the Company expects that all deferred income tax assets will be realized in the future.
e b
O 66
-. ~ - ~. -..
~. -. ~
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) i
- 14. Segments of Business 19 %
Electric Can Other Total (Thousands of thdian) l Operating revenues..
$ 1.488.990 640.497 41.899 $ 2.171.386 Operating expenses, excluding depreciation and income taxes.,
1,006,904 549,223 5,813 1,561,940 Depreciation and amortization.
116.801 35.735 2.095 154.6,,31 j
1.123.705 584.958 7.908 1.716.571 Total operating expenses *...
l Oper6 ting income *,
365.285 55.539 33.991 454.815 j
Plant construction expenditures"..
223.395 96.842 925 321.I62 Identifiable assets:
f Property, plant and equipment"..
2,733,699 805,372 59,824 3.598.895 Materials and supplies..
41,418 7,325 229 48,972 Fuel inventory.
24,594 145 24,739 42,826 Gas in underground storage..
42,826
+
Other corporate assets..
857.216
$ 4 572,648 i
1995 Operating revenues..
$ 1.449.0 % $
624.585
$. 36.920 $ 2.110.601 Operating expenses, excluding depreciation I
1,002,381 538,620 7,046 1,548,047 and income taxes.
Depreciation and amortization..
109.498 29.901 1.981 141.380 i
Total operating expenses *.,
1.111.879 568.521 9.027 1.689.427 Operating income *.
337.217 56.064 27.893 421.174 j
Plant construction expenditures **.
198.341 86.482 693 285.516 Identifiabla assets:
Property, plant and equipment"..
2,645,045 777,420 58,247 3,480,712 Materials and supplies..
47,636 8,886 3
56,525 Fuel inventory,,..
35,509 145 35,654 Cas in underground storage..
44,900 44,900 l
Other corporate assets..
733.998
$ 4.351.789 1994 I
Operating revenues..
$ 1.399.836 624.922 32.626 $ 2.057.384 Operating expenses, excluding depreciation and income taxes (1)...
1,032,3 %
558,929 7,732 I,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 36315 22.706
'I19.292 Plant construction expenditures".
223.773 91.492 1.873 317.138 Identifiable assets:
f Property, plant and equipment".
2,543,267 674,974 73,161 3,291,402 l
Materials and supplies..
55,756 11,782 62 67,600 l
Fuel inventory..
31,225 145 31,370 t
Oas in underground storage..
42,355 42,355 Other corporate assets..
775.105 I
$ 4.207.832 i
P (1) includes additional expense of approximately $43.4 million for defueling and decommissioning.
1 l
- Before income taxes.
i
" Includes allocation of common utility property.
j 4
h I
i e
67 l
I l
I
NOTES TO CONSOUDATED FIN ANCI AL STATEMENTS (Continued)
- 15. Quarf erly Mnancial Data (Unaudited)
The following summarized quarterly information for 1996 and 1995 is unaudited, but includes all j
adjustments (consisting only of normal recurring accruals) which the Company considers necessary presentation of the results for the periods. Information for any one quarterly period is not necessar the results which may be expected for a twelve-month period due to seasonal and other factors.
l Three Months ended i
Marrh 31 June 30 Senteenher 30 Dmmher 31 l
(In thousands-except per share data) 1996
$ 622,917
$ 484,787 5 476,861 5 586,821 Operating revenues.,
$ 104,846
$ 73,286
$ 88,222 F 92,130 Operating income (1).
Net income..
$ 64,429
$ 34,537
$ 39,256
$ 52,124
$ 61,457
$ 31,566
$ 36,294
$ 49,181 Earnings available for common stock..
63.679 63,998 64,324 64,748 Weighted average common shares outstanding,
$0.97
$0.49
$0.56
$0.76 Earnings per weighted average common share.
9 1995 5 620,596
$ 498,699
$ 468,453
$ 522,853 Operating revenues.,
$ 91,689
$ 62,736
$ 82,736
$ 88,656 Operating income (l).
$ 53,644
$ 28,255
$ 45,819
$ 51,138 Not income..
$ 50,643
$ 25,255
$ 42,828
$ 48,167 i
Earnings available for common stock..
62,513 62,846 63,077 63,291 l
Weighted average comnum ahares outstandmg,
$0.81
$0.40
$0.68
$0.76 Earnings per weighted average comumn share.
(1)
Operating income amounts have been restated to reflect the reclassification of Merger expenses from operating expenace to miscellaneous income and deductions in accordance with FERC guidance received during the third quarter of 1996.
j 3
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1
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i i
l SCllEDULE II PUBLIC SERVICE COMPANY OF COLORADO i
AND SUBSIDIARIES 1
r VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Years Ended Dwesaber 31,1996,1995 and 1994 l
Additions l
Balance at Charged Charged to Deductiems Balance
+
beginning to other from at and of neriod income accounts (1) reserves (2) of tear i
(Thoussads of Dollars)
Reserve deducted from related assets:
Provision for uncollectible accounts:
I 1996.
3.630 6.741 477 5 6.799 4.049 y
l 1995.
3.173 7.R 15 4 5 7.362 3.630 i
t 1994.
3.776 R.533 132 $
8,7(.8 3.173
[
i (1) Uncollectible accounts subsequently recovered, transfers from customers' deposit, etc.
(2) Uncollectible accounts written off.
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I g.-
e
[
t b
69 E
EXillillT 12(a)
PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES COMPUTATION OF RATIO OF CONSOLIDATED EARNINGS TO CONSOLIDATED FIXED CilARGES (not covered by Report of Independent Public Accountants)
Year Ended Dwesaber 31.
1996 1995 1994 1993 1992 (Thousands of Dollars, excegd ration)
Fixed charges:
5 92,205
$ 85,832 5 89,005
$ 98,089
$ 92,581 40,160 34,717 29,786 25,333 18,312 Interest on king-term debt.,
Interest on borrowings against COLI contracts.
17,238 23,392 14,235 9,445 12,357 3,621 3,278 3,126 2,018 1,790 Other interest.
Amortization of debt discount and expense less premium,
10.649 6.729 6.888 6.824 7.904 Interest component of rental expense.
$ 163,873
$ 153.948
$ 143.040
$ 141,709
$132,944 Total i
Earnings (before fixed charges and taxes on income):
$ 190,346 178.856
$ 170,269
$ 157,360
$136,623 163,873 153,948 143,040 141,709 132,944 Net income.,
Fixed charges as above..
Provisions for Federal and state taxes on income, 96.33) 95.357 48.500 60.994 53.l49 net of investment tax credit amortization.,
$ 450.550 428,161
$ 361.809
$ 360 063
$322,716 Total.
2 75 2 78 2 53 2.54 2 43 Ratio of earnings to fixed charges..
4 O
70
EXHIBIT 12(b)
PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES COMPUTATION OF RATIO OF CONSOLIDATED EARNINGS I
l TO CONSOLIDATED COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS (not conmi by Report of Independent Public Accountants)
(
Year Ended IMember 31.
1996 1995 1994 1993 1992 (Thousands of Dollars, except ratios)
Fixed charges and preferred stock dividends:
Interest on long-term debt..
$ 92,205
$ 85,532 5 89,005 5 98,089 5 92,581 Intersat on borrowings against COU contracts.
40,160 34,717 29,786 25,333 18.312 Other interest.
17,238 23,392 14.235 9,445 12,357 Amortization of debt discount and expense less premium.
3,621 3,278 3.126 2,018 1,790 j
interest component of rental expense.
10,649 6,729 6,888 6,824 7,904 Preferred stock dividend requirement..
11,848 11,% 3 12,014 12.031 12,077 Additional preferred stock dividend requinment..
5.995 6.377 3.422 4 f62 4.699 Total 5 181.716
$ 172,288
$ 158.476 5 158.402
$149.720 l
Earamas (before Exed charges and taxes on income):
Net income..
5 190,346 5 178,856
$ 170,269
$ 157.360
$136,623 Interest on long-term debt..
92,205 85,832 89,005 98.089 92,581 Interest on borrowings against COU contracts,
40,160 34.717 29,786 25,333 18,312 Other imerest.
17,238 23.392 14.235 9,445 12,357 Amortization of debt discount and expense less premium.
3,621 3,278 3.126 2.018 1,790 Interest component of rental expense.
10,649 6,729 6,888 6,824 7,904.
l Provisions for Federal and state taxca on income, net ofinvestment tax credit amortization,,
96.331 95.357
_ 4R.500 60.994 53.149 Total.
54so.550
$ 428,161
$ 361.R09
$ 360 063
$322,716 l
Ratio of earnings to Esed charges i
and preferred stuck dividends..
2 48 2 49 20R 2 27 2 16 l*
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r1
ENIIIBIT 99 NCE UNAUDITED PRO FORMA INFORMATION 31, 1996 gives effect to the The following unaudited pro forma combined balance sheet at December Merger as if it had occurred at December 31,1996, The unaudited pro forma combined statem give effect to the Merger as if it had occurred on January 1, each of the three years ended December 31,1996 1994. These statements are prepared on the basis of accounting as required under a pooling of interes reflect any cost savings or other synergies anticipated by management as a result of the Merge pro forma information is not necessarily indicative of the financial position or results of ope have occurred had the Merger been consummated for the periods for which it is given effect, nor is it nece indicative of future operating results or financial condition.
NEW CENTURY ENERGIES, INC.
UNAUDITED PRO FORMA COMBINED BALANCE SIIEET (Thousands of Dollars)
December 31,1996 ASSETS PSCo SPS Pro Fonne Property, plant and equipment, at cost:
$ 3,931,413
$ 2,517,580
$ 6,448,993 Electric.
1,035,394 1,035,394 Gaa.
17,476 17,476 Steam.
60,749 37,541 98,290 Other..
418,263 418,262 260.943 Conunon to all departments.
I81.597 79.346
_~ 8,279,358 Construction in progress.
5,644,891 2,634,467 2.045.996 944.279 2.990.275 Less: accumulated depreciation.
3.598.895 1.690.188 5.289.083 Total property, plant and equipment..
46,550 34,446 80,996 Investments, at cost, and receivables.
Current assets:
9,406 40,609 50,015 Cash and temporary cash investments..
215,132 67,780 285,912 Accounts receivable not,
85,894 20,304 106,198 Accrued unbilled revenues..
31,288 15,715 47,003 Recoverable purchased gas and electric energy costs..
48,972 17,776 66,748 Materials and supplies, at average cost.
24,739 2,320 27,059 Fuelinventory, at average cour.
42,826 42,826 Gas in underground storage, at cost (LIFO)..
44,110 44,110 Regulatory assets recoverable within one year.
4L790 7.469 49.259 Prepaid expenses and other..
547.157 171.973 719.130 Total current assets.
e Deferred charges:
304.456 107,834 412,290 3
Regulatory assets.
10,975 9,864 20,839 Unamortized debt expense.
64.615 30.489 95.104 Other..
380.046 148.187 528.233 Total deferred charges.
$ 4.572,648
$ 2,044.794
$ 6,617.442 The accompanying notes to unsudited pro forma combined balance sheet and statements ofincome are an integral part of this statement.
72
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1 NEW CENTURY ENERGIES, INC.
UNAUDITED PRO FORMA COMBINED BALANCE SHEET (Thousands of Dollars)
Decanher 31,1996 CAPITAL AND LIABILITIES PSCo SPS Pro Forrat Common stock (2).
$ 324.094 40.918
$ 103,691 Paid in capital (2)...
724,353 307.484 1.293,158 Retained eernings (5)...,..
389.841 383.350 764.646 Total common equity....
1,438,288 731,752 2,161,495 Preferred stock:
Not subject to mandatory redemption..
140,008 140,008 Subject to mandstory redemption at par.,.
39,913 39,913 teng-term debt.,
1.259.528 720.400 1.979.928 2.877.737 1.452,152 4.32I.344 Noncurrent liabilities:
Employees' postretirement benefits other than pensions..
55,677 2,967 58,644 Employees' postemployment benefits..
25.182 2.369 27.551 Total noncurrent liabilities..
80.859 5.336 86.195 Current liabilities:
Notes payable and commerclat paper...
244,725 53,836 298,561 teng-term debt due within one year..
155,030 15,231 170,261 Preferred stock subject to mandatory redemption within one year.,
'2.576 2,576 Accounts payable....
254.,256 63,004 317.260 i
Dividends payable.,,
36,973 36.973 Customers' deposits...
21,441 5,842 27,283 Accrued taxes..
58,990 19,999 78,989 i
33,797 13,151 46,948 Accrued interest,.
Current portion of defueling and decommissioning liability..
8,665 8.665
(
Current portion of accumulated deferred income taxes.
4,560 3,583 8,143 Merger costs (5).
8,545
[
Other..
69.203 28.503 97.706 i
Total current liabilities.
890.216 203.149 1.101.910 Deferred credits:
Customers' advances for construction..
50.269 366 50.635 Unamortized investment tax credits.
105,928 5,719 111,647 Accumulated deferred income tsmes.
539,082 367,272 906.354 i
Other..
28.557 10.800 39.357 Total deferred credits..
723.836 384.157 1.107.993
$ 4,572,648
$ 2,044,794
$ 6 617.442 The accompanying notes to unaudited pro forma combined balance sheet and statements of income are an integral part of this statement.
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NEW CENTURY ENERGIES, INC, UNAUDITED PRO FORMA COMBINED STATEMENTS OF LNCOME (Thousands of Dollars, Except per Share Data)
Year ended Dwember 31,1996 PSCo SPS Pro Forma Operating revenues:
$ 1,468,990
$ 927,549
$ 2,416,539 Electric.
Oss.
640,497 640,497 Other..
41.899 41.899 2,171,386 927,549 3,098,935 Operating expenses:
Fuel used in generation..
195,442 439,838 635,280 Purchased power..
490,428 20.154 510,582 Cas purchased for resale.
393,163 393,163 Other operating expenses.
336,100 113,123 449.223 Maintenance..-
63,908 34,376 98,284 Depreciation and amortization.
154,631 65,864 220,495 Taxes (other than income taxes) 82,899 45,3 %
128,205 Income taxes.....
96.331 57.322 153.653 1.812.902 775.983 2.588.885 358,484 151,566 510,050 Operating income..
h Other income and deductions:
Allowance for equity funds used during construction.
757 179 936 Miscellaneous income and deductions - not.
(19.015)
(5.018)
(24.033)
(18,258)
(4,839)
(23,097)
Interest charges:
Interest on long-term debt..
92,205 46,096 138,301 Amortization of debt discount and expense less premium.
3,621 2,145 5,766 Other interest...
57,398 5,597 62,995 Allowance for borrowed funds used during construction..
(3,344)
(2,601)
(5,945)
Dividend requirements on preferred stock of subsidiaries..
1.526 13.495 149.880 52.763 214.612 Net income..
190,346 93,964 272,341 Dividend requirements on preferred stock..
11.848 121 Earnings available for common stock..
178.498 93.843 5 272.341
, Weighted average common shares outstanding (2)..
(4.187 40.918 103.059 Earnings per weighted average share of common stock outstanding.
Q Q
M The accompanying notes to unaudited pro forma combined balance sheet and statements ofincome are an integral part of this statement, e
1, 4
74
d i
l NEW CENTURY ENERGIES, INC.
UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME
[
(Thousands of Dollars, Except per Share Data)
Year ended December 31,1995 PSCo SPS Pro forma i
Operating revenues:
Electric.
$ 1,449,096
$ 852.510
$ 2,301,606 Oss.
624,585 624,585 Other.....
36.920 36.920 2,llo,tiO!
852,510 2,963,111 Operating expensea:
Fuel used in generation..
I81,995 376,544 558,539 Purchased power...
481,958 6,485 488,443 392.680 392,680 Oss purchased for resale..
Other operating expenses (3),.
346.025 108,411 454.436 Maintenance.
64,069 27,594 91,663 I
Depreciation and amortization.
141,380 62,552 203.932 Taxes (other than income taxes)..
81,319 43,316 124.635
[
Income taxes...
95.357 69 840 165.197 1.784.783 604.742 2.479.525 325,818 157,768 483,586 Operating income..
y Other income and deductions:
Allowance for equity funds used during construction..
3,782 245 4.027 Miscellaneous income and deductions - net (3)..
(6.838) 8.141 1.303 (3,056) 8,386 5,330 Interest charges:
85,832 42,421 128,253 Interest on long4erm debt..
3,278 2.048 5,326 Amortization of debt discount and expense less premium.
Other interest.
58,109 1,695 59,804 Alinwance for borrowed funds used during construction.
(3,313)
(2,744)
(6.057) 17.588 Dividend requirements on preferred stock of subsidiaries..
143.906 43.420 204.914 178.856 122,734 284,002 Net income..
Dividend requirements on preferred stock...
11.963 5.625 Earnings available for common stock..
S 166 893 5
117.100 284.(K)2 62.932 40.018 101.R04 Weighted average common shares outstanding (2)...
Earnings per weighted average share of common stock outstanding.
M M
M i
The accompanying notes to unaudited pro forma combined balance sheet and statements of income 1
are an integral part of this statement.
e I
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I NEW CENTURY ENERGIES, INC.
UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME (Thousands of Dollars, Except per Share Data)
Year ended December 31,1994 PSCo SPS Pro Fonna Operating revenues:
$ 1,399,836
$ 824,008
$ 2,223.844 Electric.
624,922 624.922 Ges.
32 626 32.626 Other..
2,057,384 824,008 2,881,392 Operating expenses:
Fuel uned in generation..
198,118 386,796 584,914 437,087 4,401 441.488 Purchased power..
Gas purchased for resale..
397,877 397,877 Other operating expenses.
369,094 107,130 476,224 Maintenance.
67,097 30,245 97,342 Defueling and decommissioning..
43,376 43,376
' Depreciation and amortization.
139,035
. 59,759 198,794 86,408 42,510 128.918 Tases (other than income taxes).
income taxes.,,,
48.500 57.126 105.626 1,786.592 687.967 2.474.559 Opersting income...
270,792 136,041 406,833 Other income and deductions:
- Allowance for equity funds used during construction.
3,140 179 3,319 34,485 Osin on sale of WestGas Oathering, Inc.
34,485 Miscellaneous income and deductions net.
(6.014) 1.867 (4.143 31,611 2,046 33,657 Interest charges:
Interest on long-term debt..
89,005 37,710 126.715 Amortitation of debt discount and expense less premium..
3,126 2,020 5,146 Other interest.
44,021 2,028 -
46,049 Allowance for borrowed funds used during construction..
(4,018)
(1,303)
(5,321)
Dividend requirements on preferred stock of subsidiaries....
16.892 132.134 40.455 189.481 Net income..
170,269 97,632 251,009 Dividend requirements on preferred stock...
12.014 4.1,78 Earnings available for common stock..
158.255 92.754 5 251.009 Weighted average common shares outstanding (2)..
61.547 40.918 100.419 Earnings per weighted average share of common stock outstanding..
g g
g The accompanying notes to unaudited pro forma combined balance sheet and statements ofincome are en integral part of this statement.
e 76
NEW CENTURY ENERGIES, INC.
Notes to Uncudited Pro Forma Combined Balance Sheet and Statements of Income December 31,1996 (1) He unaudited pro forma comt,L di statements of income have been prepared from the historical consolidated financial statements of PSCo and SPS and are presented as if the companies were combined during all periods presented herein.
(2) ne unaudited pro forma combined balance sheet and statements of income reflect the conversion of each outstanding share of PSCo Common Stock into one share of NCE Common Stock, and each outstanding share of SPS Common Stock into 0.95 of one share of NCE Common Stock in ace, rdance with the terms of the Merger.
(3) Here were no intercompany transactions and, accordingly, no pro forma elimination adjustments were made. Certain amounts have been reclassified in order to provide consistent presentation.
(4) For a discussion regarding material commitments and contingencies relating to PSCo, see Note 9.
Commitments and Contingencies in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. For SPS, reference is made to its 1996 Annual Report on Form 10-K and its Form 10-Q for the quarter ended November 30,1996.
(5) He unaudited pro forma combined financial statements include nonrecurring charges directly related to the Merger totaling $9.4 million and $6.8 million for the years ended December 31,1996 and 1995, respectively. These nonrecurring charges include merger transaction costs and benefits expense resulting from an accelerated vesting of certain benefits. The unaudited pro forma combined statements of income do not reflect future rionrecurring charges directly related to the Merger, estimated to total approximately $8.5 million. The pro forma combined balance sheet at December 31,1996 has been adjusted to include these items with the recognition of additional current liabilities and the reduction of reutined earnings.
77
han 9. Changes in and Disagreements with Accountants on Accounting and Rnancial Disdosure Does not apply.
PART III Item 10. Directors and Executive Officers of the Registrant Biographies concerning the directors of the registrant are contained under ELECTION OF DIRECTORS in the registrant's 1997 Proxy Statement, which is incorporated herein by reference. The following table sets forth certain information concerning the directors and executive officers of the Company as of December 31, 1996.
Name Age Occur >ationfritle Initial Date as Director D.D. Hock (b) 61 Chairman of the Board 1985 Wayne H. Brunetti 54 President and CEO 1994 Collis P. Chandler, Jr. (g) 70 Chainnan, Chandler & Associates, Inc.,
Chandler-Simpson, Inc. and Chandler Drilling Corp.
1985 Doris M. Drury, Ph.D. (a)(h) 70 John J. Sullivan Professor of Free Enterprise Economics at Regis University, and President of the Center for Business and Economic Forecasting, Inc.
1975 Thomas T. Farley (c) 62 President, Petersen & Fonda, P.C.
1983 Gayle L Greer (c) 55 Vice President, Time Wamer Cable 1986 A. Barry Hirschfeld (e) 54 President, A.B. Hirschfeld Press, Inc.
1988 George B. McKinley (a)(g) 69 Chairman and CEO, First National Banks of Evanston and Kemmerer, Wyoming and President &
CEO, First McKinley Corporation 1976 Will F. Nicholson, Jr. (a)(g) 67 Chairman, Rocky Mountain Bank Card System 1981 J. Michael Powers (d) 54 President, Powers Products Co. and Powers Masonry Supply 1978 Thomas E. Rodriguez (c) 52 President and General Manager, Thomas E. Rodriguez
& Associates, P.C.
1986 o
Rodney E. Slifer (e) 62 Partner, Slifer, Smith & Frampton/ Vail Associates Real Estate 1988 W. Thomas Stephens (f)(g) 54 Retired Chairman, Manville Corporation 1989 Robert G. Tointon (a)(g) 63 President and CEO Phelps-Tointon, Inc.
1988 (a) Member of Executive Committee.
(b) Chairperson of Executive Committee.
(c) Member of Audit Committee.
78
(d) Chairperson of Audit Committee.
(e) Member of Pension Investment Committee.
(f) Chairperson of Pension Investmmt Committee.
(g) Member of Compensation Committee.
(h) Chairperson of Compensation Committee.
Executive Officers Initial Effective D te D. D. Hock, Age 61 Chairman of the Board......
February 28,1989 Chairman of the Board, Cheyenne Light, Fuel and Power Company..........
September 21,1988 Chairman of the Board, Fuel Resources Development Co................
March 22,1989 Chairman of the Board,1480 Welton, Inc...
September 26,1988 Chairman of the Board, PSR Investments, Inc...........
March 22,1990 Chairman of the Board, PS Colorado Credit Corporation............
March 22,1990 Chairman of the Board, Green and Clear lakes Company.
December 6,1988 Chairman of the Board, WestGas Interstate, Inc....
April 22,1993 Chairman of the Board, Natural Fuels Corporation..............
June 11,1993 Chairman of the Board, e prime, inc......
January 30,1995 Chairman of the Board, Young Gas Storage Company....
June 27,1995 Company Service: September,1962 Wayne H. Brunetti, Age 54 President June 28,1994 and Chief Executive Officer............................................... January 1,1996 President,1480 Welton, Inc...
March 29,1996 President, PSR Investments, Inc...
March 29,1996 President, PS Colorado Credit Corporation.
March 29,1996 President, WestGas In terState, Inc..................................................... April 19,1995 l
President, Fuel Resources Development Co...........
April 27,1995 President, Natural Fuels Corporation.....
April 25,1996 President, Green and Clear lakes Company.
December 5.1995 1
Company Service: June,1994 I
Richard C. Kelly, Age 50 Senior Vice President, Finance, Treasurer.........
June 28,1994 l
and Chie f Financial Officer........................
January 23,1990 l
President and Treasurer, New Century Energies, Inc..
August 21,1995 I
Vice President, Fuel Resources Development Co......
April 26,1990 Treasurer, Fuel Resources Development Co..
August 5,1994 Vice President, PSR Investments, Inc.
September 22,1986 Vice President, PS Colorado Credit Corporation...
March 30,1987 Treasurer, Cheyenne Light, Fuel and Power Company....
July 15,1994 Treasurer,1480 Welton, Inc.......
July 15,1994 Treasurer, Green and Clear Lakes Company.
July 15,1994 i.
Treasurer, WestGas Interstate, Inc...........
July 15,1994 Vice President and Treasurer, e prime inc........................................
January 30,1995 l
Vice President and Treasurer, Young Gas Storage Company...............
June 27,1995 Company Service: May,1968 79
Patricia T. Smith, Age 49 Senior Vice President and G eneral Counsel....................................
December 5,1994 Company Service: December,1994 W. Wayne Brown, Age 46 Controller................................
November 24,1987 Co rporate Secretary.......................................................
November 23,1993 Secretary, Cheyenne Ught, Fuel and Power Company.......................
December 15,1993 December 16,1993 Secretary,1480 Welton, Inc..................
Secretary, PSR Investments, Inc........................................................ December 16,1993 Secretary, PS Colorado Credit Corporation.............................................. December 16,1993 Secretary, Green and Clear Lakes Company........................
December 7,1993 Secretary, Fuel Resources Development Co..........................................
January 27,1994 Msy 2,1994 Secretary, WestGas Interstate, Inc..................
Secretary, e pri me, inc................................................................... January 30,1995 Secretary, Young Gas Storage Company............................
June 27,1995 Company Service: June,1972 A. Clegg Crawford, Age 64
- Vice President, Engineering and Operations Support..................
June 28,1994 Company Service: May,1989 Ross C. King, Age 55 Vice President, Gas and Electric Distribution.....................................
June 28,1994 i
President, Cheyenne Ught, Fuel and Power Company.........
July 15,1994 Company Service: Febmary,1%6 Earl E. Mclaughlin, Jr., Age 56 Vice President, Retail Energy Services....................................
June 28,1994 Vice President, Cheyenne Ught, Fuel and Power Company.......................
March 24,1994 Company Service: August,1960 Ralph Sargent III, Age 47 Vice President, Production and System Operations................................... June 28,1994 Company Service: July,1978 Marilyn E. Taylor, Age 54 Vice President, }fuman Resources...
June 28,1994 Company Service: December,1987
- On February 7,1997, Mr. Crawford retired from the Company.
Each of the above executive officers, except Mr. Brunetti and Ms. Smith, has been employed by the Company and/or its subsidiaries for more than five years in executive or management positions. Prior to election to the positions shown above and since January 1,1991:
Mr. Hock has been Chief Operating Officer and President; Mr. Brunetti has been Chief Operating Officer of the Company and President and Chief Executive Officer of Management Systems International from June 1991 through July 1994 and Executive Vice President of Florida Power & Ught Company from 1987 through May 1991; I
l 80
Mr. Kelly has been Vice President, Financial Services, Principal Accounting Officer and Senior Vice President, Finance and Administration; Ms. Smith has been Vice President and General Counsel for South Carolina Electric and Gas Company from May 1992 through December 1994 and Vice President, Rejnlatory Affairs and Purchasing from 1988 through May 1992; Mr. Crawford has been Vice President, Nuclear Operations and Vice President, Electric Production; Mr. King has been Manager, Denver Metro Region; Vice President, Regional Customer Operations and Vice President, Metropolitan Customer Operations; Mr. McLaughlin has been Vice President, Marketing, Customer Services and Support Services; Mr. Sargent has been Executive Assistant to Chairman, President and Chief Executive Officer and Vice President, Finance, Planning and Communications and Treasurer; Ms. Taylor has been Vice President, Human Resources and Vice President Administrative Services.
There are no family relationships between executive officers or directors of the Company. There are no arrangements or understandings between the executive officers individually and any other person with reference to their being selected as officers. All executive officers are elected annually by the Board of Directors.
Information concerning the directors of the registrant is contained under ELECTION OF DIRECTORS in the registrant's 1997 Proxy Statement, which information is incorporated herein by reference.
Item 11. Executive Compensation Information concerning executive compensation is contained under COMPENSATION OF EXECLTTIVE OFFICERS AND DIRECTORS in the registrant's 1997 Proxy Statement, which information is incorpon.ted herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Marmgement Information concerning the security ownership of the directors and officers of the registrant is contained under ELECTION OF DIRECTORS in the registrant's 1997 Proxy Statement, which information is incorporated herein by reference.
(
ltem 13. Cenain Relationships and Related Transactions f
)
Information concerning relationships and related transactions of the directors and officers of the registrant is contained under CFRTAIN RELATIONSHIPS AND RELATED 'DtANSACTIONS in the registrant's 1997 Proxy Statement, which information is incorporated herein by reference.
t PARTIV Item 14. Exhibits, nnancialStatement Schedules and Repons on Form 8-K
)
I (a) Financial Statements, Financial Statement Schedules, and Exhibits.
P.agt
- 1. Financial Statements:
Report of the Audit Committee...........
33 Report of Management.........................
34 8i
{
35 Report ofIndependent Public Accountants......
36 Consolidated Balance Sheets, December 31,1996 and 1995....
Consolidated Statements of income for each of the three 38 years in the period ended December 31,1996....
Consolidated Statements of Shareholders' Equity for each 39 of the three years in the period ended December 31,1996.....
Consolidated Statements of Cash Flows for each of the three 40 years in the period ended December 31, 1996..........................
41 Notes to Consolidated Financial Statements........................
- 2. Financial Statement Schedules:
11 Valuation and Qualifying Accounts and Reserves (Consolidated) for each of the three years in the period 69 ended December 31, 1996.................
All other schedules have been omitted since the required information is not present or not present in
. amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or the notes thereto.
Financial statements of several unconsolidated majority-owned subsidiaries are omitted since such subsidiaries, considered in the aggregate as a single subsidiary, would not constir* significant subsidiary.
- 3. Exhibits:
S7 Exhibits are listed in the Exhibit index......
He Exhibits include the management contracts and compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by item 601 (10) (iii) of Regulation S-K.
(b) Reports on Form 8-K:
A report on Form 8-K, dated January 18, 1996, was filed on January 29, 1996. He item reported was item 5 - Other Events, which presented updated information related to litigation, a notice of violation issued by the EPA and environmental matters associated with the operations of the Hayden Steam Electric Generating Station.
A rey n on Form 8-K, dated January 31, 1996, was filed on February 1,1996. He item reported was item 5 - Other Events, which reported that on January 31,1996, at separate meetings of shareholders, the holders of Company Common Stock, Company Preferred Stock, and SPS Common Stock approved the Merger Agreement.
A report on Form 8-K, dated May 21,1996, was filed on May 22,1996. He item reported wa. lxm 5 -
Other Events, which presented updated information on the settlement of environmental matters associated with the operations of the Hayden Steam Electric Generating Station.
A report on Form 8-K, was dated and filed on February 24,1997. De item reported was item 5 - Other Events, which presented information on the Proposed Acquisition of Yorkshire Electricity by the Company and AEP.
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EXPERTS The consolidated balance sheets of the Company and its subsidiaries as of December 31,1996 and 1995, the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1996, and the related financial statement schedule, appearing in this Annual Report on Form 10-K, have been audited by Arthur Andersen LLP, independent public accountants, and the selected financial data for each of the five years in the period ended December 31,1996, appearing in item 6 of this Annual Report on Form 10-K, other than the ratios and percentages therein, have been derived from the consolidated financial statements audited by Arthur Andersen LLP, as set forth in their report appearing elsewhere herein. The consolidated financial statements, the related financial statement schedule and the selected financial data appearing in Item 6, other than the ratios and percentages therein, which are included in this Annual Report on Form 10-K, are included herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said report.
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E'XIIIBIT 23 CONSENT OFINDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our report included in this Form 10-K, into the Company's previously filed Registration Statement (Form S-3, File No.
33-62233) pertaining to the Automatic Dividend Reinvestment and Common Stock Purchase Plan; the Company's Registration Statement (Form S-3, File No. 33-37431), as amended on December 4,1990, pertaining to the shelf registration of the Company's First Mortgage Bonds; the Company's Registration Statement (Form S-8, File No.
33-55432) pertaining to the Omnibus Incentive Plan; the Company's Registration Statement (Form S-3, File No.
33-51167) pertaining to the shelt registration of the Company's First Collateral Trust Bonds; the Company's Registration Statement (Form S-3, File No. 33-54877) pertaining to the shelf registration of the Company's First Collateral Trust Bonds and Cumulative Preferred Stock; and the Company's Registration Statement (Form S-3, File No. 333-14727) pertaining to the shelf-registration of the Company's First Collateral Trust Bonds (being one or more series of secured medium-term notes) and to all references to our Firm included in this Form 10-K.
ARTHUR ANDERSEN LLP Denver, Colorado j
February 24,1997
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EXIIIBIT 24 POWER OF ATTORNEY Each director and/or officer of Public Service Company of Colorado whose signature appears herein hereby appoints W. H. Brunetti and R. C. Kelly, and each of them severally, as his or her attomey-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.
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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 unders!gned, thereunto duly authorized en the 25th day of February,1997.
PUBLIC SERVICE COMPANY OF COLORADO By
/s/R. C. Kelly J
R.C. KELLY Senior Vice President, Finance, Treasurer and ChiefFinancial Oficer 1
Pursuain to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Public Service Company of Colorado and in the capacities and on the date indicated.
Signature Title Date
/s/W. H. Brunetti l
Principal Executive February 25,1997 W. H. Brunetti Officer and Director President and ChiefExecutive Oficer
/s/R. C. Kelly Principal Financial Officer February 25,1997 R. C. Kelly Senior Vice President, Finance, Treasurer and ChiefFinancial Oficer
/s/W Wayne Brown Principal Accounting Office.
February 25,1997 W. Wayne Brown Controller and Corporate Secretary i
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Signature Title Date
/s/D. D. Hock Chairman of the Board February 25,1997 f
D. D. Hock and Director j
/s/Collis P. Chandler Director February 25,1997
/s/ Doris M. Drury Director February 25,1997
/s/ Thomas T. Farley Direc'or February 25,1997
/s/Gayle L. Greer Director February 25,1997
/s/A. Barry Hirschfeld j
Director February 25,1997 I
/s/ George B. McKinley Director February 25,1997
/s/Will F. Nicholson, Jr.
Will F. Nicholson, Jr.
/s/J. Michael Powers Director February 25,1997
/s/ Thomas E. Rodriguez Director February 25,1997
/s/Rodney E. Slifer Director February 25,1997
/s/W. Thomas Stephens Director February 25,1997 W. Thomas Stephens
/s/ Robert G. Tointon Robert G. Tointon 86
x EXHIBIT INDEX 2(a)*
Merger Agreement and Plan of Reorganization dated August 22,1995 (Form 8-K dated August 22,1995, File No.1-3280 - Exhibit 2),
Restated Articles of Incorporation of the Registrant dated July 9,1990 (Form S-3, File No. 33-3(a)l*
54877 - Exhibit 3(a)).
3(a)2*
Articles of Amendment of the Restated Articles ofincorporation of the Registrant dated May 11, 1994 (Form S-3, File No. 33-54877 - Exhibit 3(b)).
3(b)*
By-laws dated November 30,1992 (Form 10-K,1993 - Exhibit 3(b)).
4(a)(1)*
Indenture, dated as of December 1,1939, providing for the issuance of First Mortgage Bonds (Form 10 for 1946-Exhibit (B-1)).
_)
4(a)(2)*
Indentures supplemental to indenture dated as of December 1,1939:
Previous Filing:
Previous Filing:
Form; Date or Exhibit Form; Date or Exhibit i
Dated jts.gf File No, h
Dated as of File No.
Mar.14,1941 10,1946 B-2 Apr. 25,1969 8-K, Apr.1969 1
' May 14,1941 10,1946 B-3 Apr. 21,1970 8-K, Apr.1970 1
Apr. 28,1942 10,1946 B-4 Sept.1,1970 8-K, Sept.1970 2
Apr.14,1943 10,1946 B-5 Feb.1,1971 8-K, Feb.1971 2
Apr. 27,1944 10,1946 B-6 Aug.1,1972 8-K, Aug.1972 2
l Apr.18,1945 10,1946 B-7 June 1,1973 8-K, June 1973 1
Apr. 23,1946 10-K,1946 B-8 Mar.1,1974 8-K, Apr.1974 2
Apr. 9,1947 10-K,1946 B-9 Dec.1,1974 8-K, Dec.1974 1
June 1,1947 S-1, (2-7075) 7(b)
Oct.1,1975 S-7,(2-60082) 2(b)(3)
Apr.1,1948 S-1, (2-7671) 7(b)(1)
Apr. 28,1976 S-7,(2-60082) 2(b)(4)
May 20,1948 S-1, (2-7671) 7(b)(2)
Apr. 28,1977 S-7,(2 60082) 2(h)(5)
Oct.1,1948 10-K,1948 4
Nov.1,1977 S-7,(2-62415) 2(b)(3)
Apr. 20,1949 10-K,1949 1
Apr. 28,1978 SJ7, (2-62415) 2(b)(4)
Apr. 24,1950 8-K, Apr.1950 1
Oct.1,1978 10-K,1978 D(1) i Apr.18,1951 8-K, Apr.1951 1
Oct.1,1979 S-7,(2-66484) 2(b)(3)
Oct.1,1951 8-K, Nov.1951 1
Mar.1,1980 10-K,1980 4(c)
Apr. 21,1952 8-K, Apr.1952 1
Apr. 28,1981 S-16,(2-74923) 4(c)
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Dec.1,1952 S-9,(2-11120) 2(b)(9)
Nov.1,1981 S-16,(2-74923) 4(d)
Apr.15,1953 3-K, Apr.1953 2
Dec.1,1981 10-K,1981 4(c)
Apr.19,1954 8-K, Apr.1954 1
Apr. 29,1982 10-K,1982 4(c)
Oct.1,1954 8-K, Oct.1954 1
May 1,1983 10-K,1983 4(c)
Apr.18,1955 8-K, Apr.1955 I
Apr. 30,1984 5-3,(2-95814) 4(c)
Apr. 24,1956 10-K,1956 i
Mar.1,1985 10-K,1985 4(c) 0' May 1,1957 S-9,(2-13260) 2(b)(15)
Nov I,1986 10-K,1986 4(c) g Apr.10,1958 K, Apr.1958 i
May 1,1987 10-K,1987 4(c)
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May 1,1959 8-K, May 1959 2
July 1,1990 S-3,(33-37431) 4(c)
Apr.18,1960 8-K,. Apr.1960 1
Dec.1,1990 10-K,1990 4(c)
Apr.19,1961 8-K, Apr.1961 1
Mar.1,1992 10-K,1992 4(d) l Oct.1,1961 8-K, Oct.1961 2
Apr.1,1993 10-Q, June 30,1993 4(a)
Mar.1,1962 8-K, Mar.1962 3(a)
June 1,1993 10-Q, June 30,1993 4(b)
June 1,1964 8-K, June 1964 I
Nov.1,1993 S-3,(33-51167) 4(a)(3)
May 1,1966 8-K, May 1966 2
Jan.1,1964 10-K,1993 4(a)(3) t July 1,1967 8-K, July 1967 2
Sept. 2,1994 8-K, Sept.1994 4(a)
July 1,1968 8-K, July 1968 2
May 1,1996 10Q, June 30,1996 4(a) i 87
4(a)(3)
Supplemental Indenture dated as of November 1,1996, establishing a series of First Mortgage Bone under the Indenture dated as of December 31,1939.
4(b)(1)*
Indenture, dated as of October 1,1993, providing for the issuance of First Collateral Trust Bonds f
(Form 10-Q, September 30,1993 - Exhibit 4(a)).
j 4(b)(2)*
Indentures supplemental to indenture dated as of October 1,1993:
Previous Filing:
Form; Date or Exhibit Dated as of File No.
N_m November 1,1993 S-3,(33-51167) 4(b)(2)
January 5,1994 10-K,1993 4(b)(3)
Septemhr 2,1994 8-K, Sept.1994 4(b)
May 1,1996 10-Q, June 30,1996 4(b) 4(b)(3)
Supplemental Indenture No. 5, dated as of November 1,1996 establishing a series of Secured Medium-Term Notes under the Indenture dated as of October 1,1993.
4(c)(1)*
Rights Agreement dated as of February 26, 1991, between the Registrant and Mellon Bank, N.A.
(Form 8-A, filed on March 1,1991 - Exhibit 1).
p 4(c)(2)*
Amendment to the Rights Agreement dated August 22,1995 (Form 8-K dated August 22,1995, File No.1-3280 - Exhibit 99(b)).
10(a)(1)* Settlement Agreement dated February 9,1996 between the Company and the United States I
Department of Energy (10-K,195 - Exhibit 10(a)(1)).
10(a)(2)* Settlement Agreement dated June 27, 1979 between the Registrant and General Atomic Company (Form S-7, File No. 2-66484 - Exhibit 5(n)(1)).
10(a)(3)* Services Agreement executed June 27, 1979 and effective as of January 1,1979 between the Registrant and General Atomic Company (Form S-7, File No. 2-66484 - Exhibit 5(a)(3)).
10(c)(1)* Amended and Restated Coal Supply Agreement entered into October 1,1984 but made effective as of January 1,1976 between the Registrant and Amax Inc. on behalf ofits division, Amax Coal Company (10-K,1984 - Exhibit 10(c)(1)).
10(c)(2)* First Amendment to Amended and Restated Coal Supply Agreement entered into May 27,1988 but made effective January 1,1988 between the Registrant and Amax Coal Company (10-K,1988
-Exhibit 10(c)(2).**
10(e)(1)*+ Supplemental Executive Retirement Plan for Key Managernent Employees, as amended and restated g
March 26,1991 (10-K,1991 - Exhibit 10(e)(2)).
FWe)(2)*+ Omnibus incentive Plan, as amended on January 1,1996 (10-K,1995 - Exhibit 10(e)(2)).
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10(e)(3)*+ Executive Savings Plan (10-K,1991 - Exhibit 10(e)(5)).
i 10(e)(4)*+ Form of Key Executive Severance Agreement, as amended on August 22, and November 27, 1995.
(10-K,1995 - Exhibit 10(3)(4)).
88
10(f)(1)*+ Form of Director's Agreement (10-K,1987 - Exhibit 10(f)(1)).
10(f)(2)*+ Form of Officer's Agreement (10-K,1987 - Exhibit 10(f)(2)).
10(g)(1)*+ Employment Agreement dated April 8,1994 between the Company and Mr. Delwin D. Hock (10-Q, March 31,1994 - Exhibit 10).
10(g)(2)*+ Employment Agreement dated.luly 18,1994 between the Company and Mr. Wayne H. Brunetti(10-Q, September 30,1994 - Exhibit 10).
10(g)(3)*+ Employment Agreement dated December 5,1994 between the Company and Ms. Patricia T. Smith (10-K,1994 - Exhibit 10(g)(3)).
10(g)(4)*+ Employment Agreement dated March 1,1994 between the Company and Mr. A. Clegg Crawford (10K,1995 - Exhibit 10(g)(4)).
10(g)(5)*+ Amendment to Employment Agreement dated August 22, 1995 between the Company and Mr.
Delwin D. Hock. (10-K,1995 - Exhibit 10(g)(5)).
10(g)(6)*+ Amendment to Employment Agreement dated August 22,1995 between the Company and Mr. Wayne H. Brunetti. (10-K,1995 - Exhibit 10(g)(6)).
10(g)(7)*+ Amendment to Employment Agreement dated August 22, 1995 between the Company and Ms.
Patricia T. Smith. (10-K,1995 - Exhibit 10(g)(7)).
12(a)
Computation of Ratio of Consolidated Earnings to Consolidated Fixed Charges is set forth at page 70 herein.
12(b)
Computation of Ratio of Consolidated Earnings to Consolidated Combined Fixed Charges and Preferred Stock Dividends is set forth at page 71 herein.
21 Subsidiaries 23 Consent of Arthur Andersen LLP is set forth at page 84 herein.
24 Power of Attorney is set forth at page 84 herein.
27 Financial Data Schedule UT 99 NCE Unaudited Pro Forma Financial Information is set forth at pages 72-77 herein.
Previously filed as indicated and incorporated herein by reference.
- Confidential Treatment.
+
Management contracts of compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(10)(iii) of Regulation S-K.
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PAID Permit No.14 Denver, CO PutAic Service Company of Colorado P.O. Box 840 Denver, CO 80201-0840 (303) 571-7511 h
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