Annual Report (Form 10-K), fiscal year 1994




Item 2. PROPERTIES); 2) purchases from other utilities and from QFs and IPPFs; 3) demand-side options; and 4) new generation alternatives, including repowering Fort St. Vrain.
Peak Load
During 1995, net firm system peak demand for the Company and Cheyenne is estimated to be 4,112 Mw, assuming normal weather conditions. Net dependable system capacity is projected to be, after accounting for 53 Mw of demand-side options, 4,912 Mw (generating capacity of 3,186 Mw and firm purchases of 1,726 Mw) at the time of the anticipated 1995 system peak (summer season), resulting in a reserve margin of approximately 19%.
The net firm system peak demand for the Company and Cheyenne for each of the last five years was as follows:
1990 1991 1992 1993 1994
Net Firm System Peak Demand* (Mw) 3,606 3,568 3,757 3,869 3,972
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* Excludes station housepower, nonfirm electric furnace load and controlled interruptible loads (of which approximately 145 Mw, 162 Mw, 156 Mw, 164 Mw and 160 Mw in the years 1990-1994, respectively, was not interrupted at the time of the system peak).
The net firm system peak demand for the Company and Cheyenne for the years 1991, 1992, 1993 and 1994 occurred in the summer. The net firm system peak demand for 1990 occurred in the winter. The net firm system peak demand for 1994, which occurred on August 26, 1994, was 3,972 Mw. At that time, the net dependable system capacity totaled 4,980 Mw (generating capacity of 3,186 Mw, together with firm purchases of 1,794 Mw), which represented a reserve margin of approximately 25%. Net dependable system capacity is the maximum net capacity available from both Company-owned generating units and purchase power contracts to meet the net firm system peak demand.
Purchased Power
The Company purchases capacity and energy from various regional utilities as well as QFs and an IPPF in order to meet the energy needs of its customers. Capacity, typically measured in Kws or Mws, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in Kwhs or Mwhs, is a measure of the amount of electricity produced from a particular generating source over a period of time. Purchase power contracts typically provide for a charge for the capacity from a particular generating source, together with a charge for the associated energy actually purchased from such generating source. The Company and Cheyenne have contracted with the following sources for the firm purchase of capacity and energy at the time of the anticipated summer 1995 net firm system peak demand through the expiration of the contracts:
See Note 8. Commitments and Contingencies-Purchase Requirements in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for information regarding the Company's financial commitments under these contracts. See Transmission and Distribution Property in Item 2. PROPERTIES for a discussion of the Company's interconnections with these sources.
Based on present estimates, the Company and Cheyenne will purchase approximately 34% of the total electric system energy input for 1995, compared to approximately 37% in 1994. In addition, based on the capacity associated with the purchase power contracts described above, approximately 35% of the total net dependable system capacity for the summer 1995 net firm system peak demand for the Company and Cheyenne will be provided by purchased power, compared to approximately 36% in 1994. This decrease is due to the expiration of a short-term purchase contract with Public Service Company of New Mexico for 75 Mw. This capacity is no longer required due to the additional 340 Mw of capacity provided by new QFs in 1994.
In accordance with the Public Utility Regulatory Policies Act of 1978 ("PURPA"), the Company is obligated to purchase at "avoided cost" capacity and energy from QFs. The Company has had tariffs in effect since 1984 for these purchases.
In December 1987, the CPUC issued an order imposing a moratorium during which the Company was no longer required to continue to execute additional QF contracts due to the fact that excess generating capacity would be created if additional contracts were executed. Although a comprehensive QF bidding procedure was adopted in 1988 which allowed the Company to purchase the most competitively priced QF power, all of the QF capacity purchased by the Company, including approximately 37 Mw of additional capacity scheduled to come on line in the future, is being purchased under contracts entered into prior to the adoption of such procedure. Based on current CPUC criteria, QFs could provide up to 20% of the Company's net firm system peak load. In 1994, approximately 15% of the Company's summer net firm system peak demand was contracted to be provided by QFs.
In addition to long-term and QF purchases, the Company also made short- term and non-firm purchases throughout the year to replace generation from Company owned units which were unavailable due to maintenance and unplanned outages, to provide the Company's reserve obligation to the Pool, to obtain energy at a lower cost than that which could be produced by higher-cost resource options, including Company owned generation and/or long-term purchase power contracts, and for various other operating requirements. Short-term and non-firm purchases accounted for approximately 3% of the Company's total energy requirement in 1994.
Based on current projections, the Company expects that purchased capacity will continue to meet a significant portion of system requirements at least for the remainder of the 1990s.
Purchases of capacity and energy do not have a significant effect on the earnings of the Company because the costs thereof, without mark-up, are billed to customers through base rates, the ECA and the QFCCA. The CPUC, however, has established a schedule for reviewing the ECA (see Note 8. Commitments and Contingencies-Regulatory Matters in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). Such purchases neither require the Company to make an investment nor afford the Company an opportunity to earn a return.
The Company is a member of the Pool which is composed of members each of which owns and/or operates electric generation and/or transmission systems which are interconnected to one or more other member systems. The objective of the Pool is to provide capacity which is categorized as 1) immediately accessible; 2) accessible within ten minutes; and 3) accessible within twelve hours, as required. As a result of membership in the Pool, the Company can supply and protect its electric system with less aggregate operating reserve capacity than otherwise would be necessary; emergency conditions can be met with less likelihood of curtailment or impairment of electric service; and generation and transmission facilities and interconnections can be used more efficiently and economically.
Construction Program
At December 31, 1994, the Company and its subsidiaries estimated the cost of their construction program, including AFDC, in 1995, 1996 and 1997 to be $323 million, $347 million and $316 million, respectively (see Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS). Included in these estimated costs is $117 million associated with the conversion of Fort St. Vrain to a 471 Mw gas fired combined cycle steam plant. The total conversion project cost is approximately $231 million. A CPCN for the conversion of Fort St. Vrain was approved by the CPUC in July 1994 (see Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
Fort St. Vrain
See Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Electric Fuel Supply
The following table presents the delivered cost per million Btu of each category of fuel consumed by the system for electric generation of the Company and its utility subsidiaries during the years indicated, the percentage of total fuel requirements represented by each category of fuel and the weighted average cost of all fuels during such years:
Coal
The Company's primary fuel for its steam electric generating stations is low-sulfur western coal. The Company's coal requirements are purchased primarily under seven long-term contracts with suppliers operating in Colorado and Wyoming, the largest of which is with Cyprus/Amax Coal Company, which operates the Belle Ayr and Eagle Butte Mines near Gillette, Wyoming and the Foidel Creek and Empire Energy mines in northwestern Colorado.
Long-term contracts presently in existence provide for a substantial portion of future annual coal requirements for existing plants through 1997. Any shortfall will be provided by purchases on the spot market. During the year ended December 31, 1994, the Company's coal requirements for existing plants were approximately 8,502,170 tons, a substantial portion of which was supplied pursuant to long-term supply contracts. Coal supply inventories at December 31, 1994 were approximately 52 days usage, based on the average peak burn rate for all the Company's coal-fired plants.
The following table is a synopsis of the basic supply provisions of the existing long-term contracts, which provide a minimum delivery of approximately 92 million tons of low-sulfur coal over their remaining life (see Note 8. Commitments and Contingencies-Purchase requirements in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ).
Each coal contract contains adjustment clauses which permit periodic price increases or decreases. See Note 8. Commitments and Contingencies-Purchase requirements in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for information regarding the Company's financial commitments under these contracts as well as coal transportation contracts.
Natural Gas and Fuel Oil
The Company uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas used in steam heat production facilities and as boiler fuel in the Company's Denver area generating stations and Comanche is purchased primarily from North American Resources Co. pursuant to a Gas Sales Agreement that went into effect for a 12-month period beginning October 1, 1994. The agreement with North American Resources Co. provides for firm supplies ranging from 10,000 MMbtu per day (during the seven month summer season) to 20,000 MMbtu per day (during the five month heating season), with varying daily purchase obligations by the Company. Requirements above these levels are secured by purchasing competitively priced gas from other suppliers on an as-needed basis. Natural gas supplies for the Valmont and Ft. Lupton power plants are purchased from various suppliers on an as-needed basis.
Natural Gas Operations
During the period 1990-1994, the PSCo Gas Companies experienced growth in the number of commercial and residential customers ranging from 1.3% to 2.8% annually. Since 1990, commercial and residential gas volumes sold have averaged 150.6 Bcf annually, while industrial volumes sold have declined from 3.6 Bcf in 1990 to 0.1 Bcf in 1994. The growth of commercial and residential sales has been moderate due primarily to economic conditions in Colorado and Wyoming. Industrial sales have declined primarily because a majority of industrial customers have switched to purchasing gas directly from suppliers. In most cases, the PSCo Gas Companies transport gas from the suppliers to such industrial customers through the PSCo Gas Companies' transmission and distribution facilities. Fees for this transportation service, which are paid by these industrial customers, substantially offset the effect on net income of the revenue loss from decreased sales of gas to these industrial customers. During 1994, transportation services of the PSCo Gas Companies generated revenues of $23.5 million compared to $23.2 million in 1993 and $20.6 million in 1992.
Gas Supply
The PSCo Gas Companies have attempted to maintain low cost, reliable gas supplies by optimizing the balance between long- and short-term gas purchase contracts. During 1994, the PSCo Gas Companies purchased 132.6 Bcf (at 14.65 pounds per square inch) from 87 suppliers, including the following major suppliers: Interstate (44.7 Bcf); Associated Natural Gas, Inc. (8.9 Bcf); KN Energy and affiliates (7.2 Bcf); and Western Gas Resources, Inc. (5.2 Bcf). In 1994, the average delivered cost per Mcf for the PSCo Gas Companies was $2.86 compared to $2.82 per Mcf in 1993 and $2.72 per Mcf in 1992.
As indicated above, Interstate was the primary supplier to the PSCo Gas Companies in 1994. During 1993, the PSCo Gas Companies entered into two non- regulated supply agreements, as allowed under FERC Order 636. Under the agreement with Interstate, which covers the period from October 1, 1993 through September 30, 1996, the annual quantities to be purchased declined from 44 Bcf in the first year to 33 Bcf in the second year and will decline to 22 Bcf in the third year. Under the agreement with KN Gas Supply Services, Inc., which covers the period from September 1, 1993 through August 31, 1996, the annual quantities to be purchased are fixed at 4 Bcf.
This continued purchase of gas quantities from Interstate and KN Gas Supply Services, Inc. will eliminate any Gas Supply Realignment costs otherwise applicable under FERC Order 636. See Note 8. Commitments and Contingencies-Purchase requirements in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for information regarding the Company's financial commitments under these contracts.
Young Storage
Young Storage, a partnership among Young Gas Storage Company and CIG Gas Storage Company, each 47.5% general partners, and The City of Colorado Springs Department of Public Utilities ("Colorado Springs"), a limited partner, is converting a depleted natural gas field into an underground natural gas storage facility at a cost of approximately $45 million. The facility, when fully developed by 1998, will have a maximum working gas capacity of 5.3 Bcf and a maximum daily deliverability of 200,000 Mcf. Commercial operations are expected to begin by mid-1995. On September 13, 1993, the Company signed a thirty year contract with Young Storage for natural gas storage services with a maximum available capacity of 4.77 Bcf and a maximum daily injection/withdrawal capacity of 180,000 Mcf per day. The remainder of the storage capacity has been contracted by Colorado Springs. Young Storage will be subject to FERC regulation.
In December 1994, the Board of Directors of the Company approved exercising the option to acquire Young Gas Storage Company's 47.5% general partnership interest in Young Storage pursuant to the Company's Option For Purchase and Sale of the Young Gas Storage Company dated August 31, 1993. The Company expects to exercise this option during the first quarter of 1995 resulting in an investment of approximately $6.5 million.
WGI
WGI is engaged in transporting gas to Cheyenne, Wyoming via a thirteen mile connecting pipeline between Chalk Bluffs, Colorado and Cheyenne, Wyoming. Gas transportation volumes were approximately 1.7 Bcf for 1994.
WGT
WGT holds a one-third interest ($3.4 million) in the TransColorado Project. The TransColorado Project is a partnership of WGT and subsidiaries of KN Energy and Questar Pipeline Company for developing a pipeline to transport natural gas out of western Colorado and the Rocky Mountain Region into major western and midwestern markets. The TransColorado Project has been designed and engineered for a 300 mile pipeline capable of transporting 300 MMcf per day. The partnership is currently marketing the transportation service to producers in western Colorado and to marketers and local distribution companies in an effort to gain firm contracts to support the project. FERC approval was received in October 1994. Construction of the pipeline is scheduled to begin during 1996, depending upon the success of the marketing efforts. The Company is currently evaluating the possible divestiture of its interest in WGT.
WGG
WGG owned and operated natural gas gathering and processing facilities in Southern Colorado. On August 30, 1994, the Company sold all of its outstanding common stock of WGG (see Note 3. Divestiture of Nonutility Assets in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
Fuelco
Fuelco has been engaged principally in the exploration for, and the development and production of, natural gas and crude oil. Fuelco also marketed and brokered natural gas to re-marketers and directly to end users. As part of the Company's strategy to focus its efforts on its core electric and gas businesses, during 1994 and 1993, the Company disposed of certain assets related to the Company's investment in Fuelco and its wholly-owned subsidiary, Synhytech. The Company is re-evaluating its alternatives related
to the disposition of the remaining assets (see Note 3. Divestiture of Nonutility Assets in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
Regulation and Rates
The Company is subject to the jurisdiction of the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. Cheyenne is subject to the jurisdiction of the WPSC. The Company is subject to the jurisdiction of the DOE through the FERC with respect to its wholesale electric operations and accounting practices and policies. The Company is also subject to the jurisdiction of the NRC with respect to the decommissioning of Fort St. Vrain. Although the Company is a "holding company" under the PUHCA, it has filed an annual exemption statement pursuant to Rule 2 of the SEC under that Act and is, therefore, exempt from all of the provisions of such Act and the Rules thereunder, except Section 9(a)(2) thereof. Such exemption is subject to termination under Rule 6 of PUHCA. The Company holds a FERC certificate which allows it to transport natural gas in interstate commerce pursuant to the provisions of the Natural Gas Act, the Natural Gas Policy Act of 1978 and FERC Order Nos. 436 and 500 without the Company becoming subject to full FERC jurisdiction. WGI holds a FERC certificate which allows it to transport natural gas in interstate commerce pursuant to the provisions of the Natural Gas Act. WGI is subject to FERC jurisdiction.
State Regulation
CPUC
The CPUC consists of three full-time members appointed by the Governor and approved by the Colorado Senate. Only two members may be from the same political party.
Electric and Gas Adjustment Clauses
The Company's ECA mechanism was revised and a new QFCCA mechanism was implemented on December 1, 1993, along with the base rate changes resulting from the 1993 rate case (see "1993 Rate Case"). Under the revised ECA, fuel used for generation and purchased energy costs from utilities, QFs and IPPFs (excluding all purchased capacity costs) to serve retail customers, are recoverable. Purchased capacity costs are recovered as a component of base rates, except as described below. The ECA rate is revised annually on October 1 and whenever total costs recoverable through the ECA change by $0.001 per kilowatt hour or more. Recovered energy costs are compared with actual costs on a monthly basis and differences, including interest, are deferred. The balance in the deferred account on June 30 of each year (including interest if the balance is negative) is reflected in the ECA over a 12 month period commencing October 1 of such year. Under the QFCCA, all purchased capacity costs from new QF projects, not otherwise reflected in base rates, are recoverable similar to the ECA. While the CPUC approved the QFCCA, recovery of such costs may be subject to an earnings test, which has not yet been defined by the CPUC. The OCC has proposed an annual earnings test that may result in a reduction of QFCCA recoveries to the extent the Company's earnings are in excess of its 11% authorized rate of return on regulated common equity granted in the 1993 rate case. Hearings regarding this matter are scheduled for April 1995.
The Company, through its GCA, is allowed to recover the difference between its actual costs of purchased gas and the amount of these costs recovered under its base rates. The GCA rate is revised annually on October 1 and as needed, to coincide with supplier rate changes. Purchased gas costs and revenues received to recover such gas costs are compared on a monthly
basis and differences, including interest, are deferred. The balance in the deferred account on June 30 of each year (including interest if the balance is negative) is reflected in the GCA over a 12 month period commencing October 1 of such year.
The Company and Cheyenne are required to file applications with their respective state regulatory commissions for approval of adjustment mechanisms in advance of the proposed effective date. The applications must be acted upon before becoming effective. In addition, the CPUC holds hearings to review the Company's adjustments made during preceding time periods, and the Company is required to file quarterly reports on matters relevant to the adjustments.
The CPUC held a prehearing conference on May 24, 1994 for the purpose of establishing a schedule for reviewing the justness and reasonableness of GCA and ECA mechanisms used by gas and electric utilities within its jurisdiction resulting in the opening of an investigatory docket. Open hearings were held in December 1994. The OCC and the CPUC staff are recommending the elimination of these cost adjustment mechanisms. The Company is in opposition to the elimination of these cost adjustment mechanisms and has filed initial comments, as well as responded to the comments filed by the other parties. On February 6-7, 1995, as part of an open hearing, the CPUC determined that proceeding with a generic ECA rulemaking docket was not appropriate. However, the Company is required to make an individual filing with the CPUC related to its ECA by September 1, 1995 to assess whether the ECA should be maintained in its present form, altered or eliminated. Additionally, the CPUC preliminarily determined that the GCA will continue under current practices. The CPUC staff will hold informal roundtable discussions for the purpose of clarifying the review procedures for the GCA.
Incentive Regulation and Demand Side Management
The Company, in collaborative process with public interest groups, consumers and industry, has developed DSM programs (programs designed to reduce peak electricity demand, shift on-peak demand to off-peak hours and provide for more efficient operation of the electric generation system), including incentive and cost recovery mechanisms. On May 5, 1993, the CPUC approved the programs along with a schedule to be implemented over a three- year period. Effective July 1, 1993, the Company placed into effect a DSMCA clause which permits it to recover deferred DSM costs over seven years while non-labor incremental expenses, carrying costs associated with deferred DSM costs and certain incentives associated with the approved DSM programs are recovered on an annual basis.
Under a separate CPUC order issued in December 1992, the Company has implemented a Low-Income Energy Assistance Program. The costs of this energy conservation and weatherization program for low-income customers are recoverable through the DSMCA.
In addition, on June 8, 1994, the CPUC approved the recovery of certain "energy efficiency credits" from retail jurisdiction customers through the DSMCA (see Note 8. Commitments and Contingencies - Regulatory Matters in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
The CPUC has opened a separate docket to investigate issues relating to the adoption and implementation of incentive regulation, which includes the concept of decoupling the Company's earnings from sales, and additional DSM incentives. On February 10, 1994, the parties to this docket filed a unanimous stipulation and settlement agreement with the CPUC. Provisions of the stipulation include, among other things, retaining the cost recovery component of the DSMCA through December 31, 1998, modifying slightly the DSM
incentive mechanism for 1994 and 1995 and forming a technical working group to study and analyze various alternative annual revenue reconciliation mechanisms and incentive mechanisms for 1996 through 1998, which would replace existing DSM incentives until another mechanism or regulatory approach is approved by the CPUC. The stipulation agreement, which includes a procedural schedule to review the results of all studies and simulations over the next year, was approved by the CPUC on June 16, 1994. The technical working group will present to the CPUC a detailed analysis demonstrating the effect of the various proposed mechanisms by the end of the first quarter of 1995.
1993 Rate Case
On November 26, 1993, the CPUC issued its final written decision regarding the Company's 1993 rate case, authorizing the Company to earn a return on regulated common equity of 11% and an annual rate of return on regulated rate base of 9.4%, lowering the Company's annual base rate revenue requirement by approximately $5.2 million (a $13.1 million electric revenue decrease partially offset by a $7.1 million gas revenue increase and a $0.8 million steam revenue increase). The new rates became effective December 1, 1993. As part of the final decision, the CPUC adopted the following significant positions:
. the rejection of the Company's proposed use of a fully forecasted test year in the establishment of revenue requirements in favor of an historical test year ended September 30, 1992,
. the adoption of full income tax normalization with a 13-year amortization of prior flow-through amounts currently reflected as a regulatory asset on the balance sheet, and
. continued inclusion in rate base of the Pawnee 2 engineering costs ($18 million) and the investment in Southeast Water Rights ($28 million), but with an allowed rate of return on such assets based on the Company's weighted cost of debt and preferred stock.
The OCC filed in Denver District Court an appeal of the CPUC's decision. The OCC has claimed that accounting related to a specific income tax issue results in the overcollection of costs from ratepayers. The Company is in opposition to the appeal. The Company believes that the resolution of this appeal will not have a material effect on its financial position or results of operations.
On August 1, 1994, the Company filed its Phase II testimony. The Phase II proceedings will address cost allocation issues and specific rate changes for the various customer classes based on the results of the Phase I hearings and decision that became effective December 1, 1993. A final CPUC decision on the Phase II proceedings is expected in late 1995.
IRP - Electric
On October 1, 1993, the Company filed its first IRP pursuant to the Electric Integrated Resource Planning Rules of the CPUC. The Company's IRP describes the mix of resources to be utilized and/or acquired by the Company for the following three years, including the repowering of Fort St. Vrain as a gas fired combined cycle steam plant (see Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). In addition, certain DSM measures have been identified and described which are intended to reduce the amount of additional capacity required to be supplied by the Company in the future. Hearings regarding the Company's and other electric utilities' specific IRPs were held before the CPUC in April 1994 and an interim order
approving the Company's IRP was issued on June 10, 1994. The final order has not yet been received; however, no changes are expected to result from the final order. The Company's next IRP is scheduled to be filed with the CPUC on or about July 1, 1996.
IRP - Gas
In December 1992, the CPUC established a separate docket to consider the need for a gas IRP. The CPUC has held several pre-hearing conferences and has determined to conduct roundtable discussions to explore the impacts of the EPAct and the mandates in the EPAct regarding the consideration by state regulatory agencies of the adoption of standards for gas integrated resource planning and conservation incentives, as well as the impact on small businesses of adopting these standards. These proceedings have been completed and the CPUC determined there was no need to establish a gas IRP in Colorado.
WPSC
On July 31, 1992, Cheyenne filed a rate case application with the WPSC. On December 17, 1992, the WPSC issued an order approving a Settlement Agreement reached between Cheyenne and the Consumer Representative Staff of the WPSC. The Settlement Agreement provided for a return on equity of 11.66% which, in addition to new rates, became effective January 1, 1993.
In June 1993, Cheyenne filed gas and electric IRPs with the WPSC pursuant to the Settlement Agreement. The WPSC has not formally acted on these filings.
The WPSC has approved adjustment mechanisms for Cheyenne which are similar to the Company's ECA and GCA.
Environmental Matters
See Note 8. Commitments and Contingencies - Environmental Issues in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for a discussion of the impact on the Company of environmental site clean-up, the Clean Air Act Amendments of 1990 and other environmental matters not discussed below.
For the years 1995, 1996 and 1997, the estimated expenditures for environmental control facilities are $11.3 million, $18.2 million and $26.9 million, respectively. These figures include estimated expenditures to install SO2 and NOx reduction equipment for the years 1995, 1996 and 1997 of $4.7 million, $14.1 million and $20.3 million, respectively.
The Metro Denver Brown Cloud II Study, designed to investigate the formation of secondary particulates in the Denver metropolitan area, began in July 1990 and the results were released in December 1993. The study was inconclusive and did not offer any policy recommendations. As a result, the study will not impact the Company's current programs to reduce SO2 and NOx emissions. However, the Metro area brown cloud continues to be of concern, which may require the Company to participate in a Metro Area Brown Cloud III Study.
The Company continues to research and implement various SO2 and NOx emissions reduction projects, including two CCT3 projects. The CCT3 projects are part of a larger DOE Clean Coal Program, which co-funds developing technologies aimed at more efficient and environmentally acceptable methods of burning coal. Research and implementation continues on the two CCT3 projects, which involve Arapahoe Unit 4 and Cherokee Unit 3. Testing is expected to be completed at both units in late 1995.
The Mount Zirkel Wilderness Area Reasonable Attribution Study, which is designed to ascertain the contribution of various emission sources to visibility impairment in the Mount Zirkel Wilderness Area began in 1994. The Company is a participant in the Hayden and Craig generating stations, in the nearby Yampa Valley. Depending upon the outcome of the study, the participants may need to install emissions control equipment. However, the type and extent of equipment necessary will not be determined until after the conclusion of the study.
Installation of a fabric filter dust collector at Pawnee, which was accelerated as a result of a Consent Decree between the Company, the DOJ, the EPA and the State of Colorado, was completed in December 1994. The cost of installing this equipment was approximately $41.6 million.
Pursuant to the requirements of the Federal Clean Water Act, as amended, and the Colorado Water Quality Control Act and regulations issued thereunder, the Company receives NPDES permits to discharge effluents into various streams and waters of the State of Colorado for each of its generating stations. These permits, which have a five-year life, are issued by the CWQCD, but are subject to review by the EPA. The Company believes it is presently in compliance with such discharge permits.
Renewed wastewater discharge permits have been issued for: 1) Fort St. Vrain, effective April 1, 1993; 2) Cherokee, effective July 1, 1994; 3) Zuni, effective August 1, 1993; 4) Hayden, effective August 1, 1994; 5) Valmont, effective October 1, 1994; 6) Arapahoe, effective December 1, 1994 and 7) Cameo, effective December 1, 1994. A permit renewal application was submitted for the Comanche generating station prior to the expiration of its existing permit. All discharge permits that are not renewed by the CWQCD prior to their expiration date automatically receive an administrative extension pending the issuance of a final permit.
Environmental regulations at the Federal, state and local levels, including the Clean Air Act Amendments of 1990, some of which are discussed in Note 8. Commitments and Contingencies - Environmental Issues in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, are expected to have a continuing impact on the Company's operations. The Company continues to strive to achieve compliance with all environmental regulations currently applicable to its operations. However, it is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations or, generally, what effect future laws or regulations may have upon the Company's operations.
Competition
Industry Outlook
During 1994, unprecedented change occurred in the electric utility industry nationwide, furthering the development of a competitive environment. In general, the economics of the electric generation business have fundamentally changed with open transmission access and the increased availability of electric supply alternatives. Such alternatives will ultimately serve to lower customer prices, particularly in areas where only higher cost energy is currently provided. Customer demands for lower prices and supplier choices, coupled with the availability of alternative supplies (IPPFs, QFs, EWGs and power marketers), have created significant pressure for open access to the utility transmission grid and the creation of a commodity market for bulk electric supply. The EPAct directly addressed this issue by giving FERC the authority to require utilities to provide non-discriminatory open access to the transmission grid for purposes of providing wholesale
customers with direct access. Additionally, an increasing number of states have recently begun to evaluate or pursue regulatory reform in an effort to proactively respond to this changing business environment and address the issue of retail wheeling.
The presence of competition and the associated pressure on prices may ultimately lead to the unbundling of products and services similar to what has evolved in the natural gas industry. The concept of a vertically integrated utility, coupled with current regulatory practices, remain increasingly incongruent with the economic forces shaping the industry. Today's market view of the future envisions an unbundled electric utility industry consisting of at least four major business segments: energy supply, transmission, distribution and energy services- each having a different driving force.
State Regulatory Environment
Colorado law permits the CPUC to authorize rates negotiated with individual electric and gas customers which have threatened to discontinue using the services of the Company, so long as the CPUC finds that such authorization 1) in the case of electric rates, will not affect adversely the Company's remaining customers and 2) in the case of gas rates, will not affect the Company's remaining customers as adversely as would the alternative. In response to the increasingly competitive operating environment for utilities, the regulatory climate also is changing. Currently, the Company is participating in several CPUC dockets that address this change, and it is in the process of investigating various incentive/performance-based alternative forms of regulation. However, the Company believes it will continue to be subject to rate regulation that will allow for the recovery of all of its deferred costs (see Note 1. Summary of Significant Accounting Policies - Business and Regulation - Regulatory Assets and Liabilities and Note 8. Commitments and Contingencies - Regulatory Matters in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
Electric
The wholesale electric business faces increasing competition in the supply of bulk power due to provisions of the EPAct and Federal and state initiatives with respect to providing open access to utility transmission systems. The Company does not anticipate that these provisions will have a material impact on its operations in the near-term. For 1994, the Company's wholesale revenues totaled approximately 9% of total electric revenues. A substantial portion of these revenues related to firm sales contracts, which are expected to continue at current levels for a minimum of 8 years. In addition, since 1992, the Company has had a FERC-approved transmission tariff, which provides for open access, with certain limitations. During 1994, the Company was notified by one wholesale customer of its intent to reduce future firm and peaking power purchases in accordance with current contractual arrangements. This customer is seeking a CPCN to construct its own generation facilities to serve its customers' needs. The Company has proposed alternative power supply arrangements for such customer's consideration.
Today, the retail electric business faces increasing competition from industrial and large commercial customers who have the ability to own or operate facilities to generate their own electric energy requirements. In addition, customers may have the option of substituting fuels, such as natural gas for heating, cooling and manufacturing purposes rather than electric energy, or of relocating their facilities to a lower cost environment. While the Company faces these challenges, it believes its rates are competitive with currently available alternatives. The Company is taking actions to lower operating costs and is working with its customers to analyze the feasibility of various options, including energy efficiency, load management and co-
generation in order to better position the Company to more effectively operate in a competitive environment.
Natural Gas
Historically, gas utilities have competed with suppliers of electricity and fuel oil, as well as, to a lesser extent, propane, for sales of gas to customers for heating and/or cooling purposes. In the 1980s, industrial and large commercial customers began to "by-pass" the local gas utility through the construction of interconnections directly with, and the purchase of gas directly from, interstate pipelines, thereby avoiding the additional charges added by the local gas utility. In addition, industrial and commercial customers sought to purchase less expensive supplies of natural gas directly from producers, marketers and brokers. The Company has been actively involved for several years in providing transportation services for those industrial and large commercial customers who chose to purchase gas directly from suppliers. In addition, the Company has provided flexible transportation rates for several years. The per-unit fee charged for transportation services, while significantly less than the per-unit fee charged for the sale of gas to a similar customer, provides an operating margin approximately equivalent to the margin earned on gas sold. Therefore, increases in such activities will not have as great an impact on gas revenues as increases in deliveries from the sale of gas, but will have a positive impact on operating margin.
Franchises
The Company and its subsidiaries held nonexclusive franchises to provide electric or gas service or both services in 119 incorporated cities and towns at December 31, 1994. These franchises consist of 69 combined gas and electric service franchises, 28 electric service franchises and 22 gas service franchises. The Company is currently providing gas and electric service to one previously franchised municipality while a new franchise is being negotiated. The Company's franchise with the City of Denver will expire in 2006. The Company and its subsidiaries supply electric or gas service or both services in about 114 unincorporated communities in which franchises are not required.
Employees
The number of employees of the Company and its subsidiaries decreased from 6,507 at December 31, 1993 to 5,160 at December 31, 1994. The number of employees covered by collective bargaining agreements at December 31, 1994 was 2,449. The decrease in the number of employees is primarily due to an early retirement/severance package offered by the Company in 1994 and to an involuntary severance program implemented as part of the Company's restructuring activities in 1994. Effective February 13, 1995, approximately 390 positions were outsourced as part of a ten-year agreement with ISSC to manage most of the Company's information technology systems and network infrastructure.
Research and Development
The Company and its utility subsidiaries spent approximately $3.8 million in 1994, $4.3 million in 1993 and $4.8 million in 1992 on research and development. The major portion of those expenditures went to utility associations which engage in research projects to benefit the electric and gas industries as a whole. The balance of the expenditures went for smaller internal and external projects dealing with such areas as pollution control and alternative fuels research.
Nuclear Property
Fort St. Vrain, near Platteville, the Company's only nuclear generating station, ceased operations on August 29, 1989 (see Note 2. Fort St. Vrain in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA).
Transmission and Distribution Property
On December 31, 1994, the Company's transmission system consisted of approximately 182 circuit miles of 345 Kv overhead lines; 1,832 circuit miles of 230 Kv overhead lines; 15 circuit miles of 230 Kv underground lines; 65 circuit miles of 138 Kv overhead lines; 965 circuit miles of 115 Kv overhead lines; 19 circuit miles of 115 Kv underground lines; 355 circuit miles of 69 Kv overhead lines; 170 circuit miles of 44 Kv overhead lines; and 1 circuit mile of 44 Kv underground lines. The Company jointly owns with another utility approximately 347 circuit miles of 345 Kv overhead lines and 330 miles of 230 Kv overhead lines, of which the Company's share is 182 miles and 114 miles, respectively, which shares are included in the amounts listed above.
The Company's transmission facilities are located wholly within Colorado. The map on page 18 illustrates the Company's transmission interconnected system. The system is interconnected with the systems of the following utilities with which the Company has major firm purchase power contracts; capacity and energy are provided primarily by generating sources in the locations indicated:
The Company has wheeling agreements with the above, and with other utilities and public power agencies, which are utilized to provide capacity and energy to the Company's system from time to time.
The Company is a member of the WSCC, an interstate network of transmission facilities which are owned by public entities and investor-owned utilities. WSCC is the regional reliability coordinating organization for member electric power systems in the western United States.
At December 31, 1994, the distribution systems consisted primarily of approximately 12,887 miles of overhead line, 1,068 miles of which are located on poles owned by other utilities under joint use agreements. The Company also owned approximately 7,389 cable miles of underground distribution system (excluding street lighting) located principally in the Denver metropolitan area. The Company owned 214 substations (four of which are jointly owned) having an aggregate transformer capacity of 18,179,300 Kva, of which 4,145,827 Kva is step-up transformer capacity at generating stations.
Gas Property
The gas property of the Company at December 31, 1994 consisted chiefly of approximately 14,619 miles of distribution mains ranging in size from 0.50 to 30 inches and related equipment. The Denver distribution system consisted
of 8,100 miles of mains. Pressures in the low pressure system are varied to meet load requirements and individual house regulators are installed on each customer's premises to provide uniform flow of gas to appliances.
Other Property
The Company's steam heating property at December 31, 1994 consisted of 10.5 miles of transmission, distribution and service lines in the business district of Denver, including a steam transmission line connecting the steam heating system with Zuni. Steam is supplied from boilers installed at the Company's Denver Steam Plant which has a capability of 295,000 pounds of steam per hour under sustained load and an additional 300,000 pounds of steam per hour is available from Zuni on a peak demand basis. The Company also owns service and office facilities in Denver and other communities strategically located throughout its service territory.
Property of Subsidiaries
The book value of the properties of the consolidated subsidiaries of the Company aggregates approximately 3% of the total book value of the properties of the Company and such subsidiaries combined. Such properties consist largely of electric and gas properties similar in character to the properties of the Company, except for the exploration, development and production properties still held by Fuelco (see Note 3. Divestiture of Nonutility Assets in Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA). Unregulated subsidiary property is approximately 2% of the total book value of the properties of the Company and consolidated subsidiaries combined. 1480 Welton, Inc. owns office buildings in Denver that are used by the Company.
Character of Ownership
The steam electric generating stations, the majority of major electric substations and the major gas regulator stations owned by the Company and its subsidiaries are on land owned in fee. Approximately half of the compressor stations and a limited number of town border and meter stations are also on land owned in fee. The remaining major electric substations and compressor stations and the majority of gas regulator stations and town border and meter stations are wholly or partially on land leased from others or on or along public highways or on streets or public places within incorporated towns and cities. The Company's Cabin Creek Pumped Storage Hydroelectric Generating Station, its Shoshone Hydroelectric Generating Station and a portion of the related intake tunnel are located on public lands of the United States. As to substantially all property on or across public lands of the United States, the Company or its subsidiaries hold licenses or permits issued by appropriate Federal agencies or departments. The Leyden gas storage facility is located largely on leased property under leases expiring December 31, 2040. The Company and its utility subsidiaries have the power of eminent domain pursuant to Colorado law to acquire property for their electric and gas facilities. The electric and gas transmission and distribution facilities are for the most part located over or under streets, public highways or other public places and on public lands under franchises or other rights, and on land owned by the Company or others pursuant to easements obtained from the record holders of title. The water rights of the Company and its subsidiaries are owned subject to divestment to the extent of any abandonment thereof.
Substantially all of the utility plant and other physical property owned by the Company and its utility subsidiaries is subject to the liens of the respective indentures securing the mortgage bonds of the Company and its utility subsidiaries.
Item 3.

Item 3. Legal Proceedings
See Note 2. Fort St. Vrain and Note 8. Commitments and Contingencies in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Item 4.

Item 4. Submission of Matters to a Vote of Security Holders
Does not apply.
PART II
Item 5.

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
The Company's common stock is listed on the New York, Chicago and Pacific Stock Exchanges. The following table sets forth for the periods indicated the dividends declared per share of common stock and the high and low sale prices of the common stock on the consolidated tape as reported by The Wall Street Journal.
At December 31, 1994, the book value of the common stock was $20.39 per share. At February 24, 1995, there were 64,366 holders of record of the Company's common stock.
The dividend level is dependent upon the Company's results of operations, financial position and other factors and is evaluated quarterly by the Board of Directors. The Company is subject to various uncertainties, including those associated with the eventual resolution of Fort St. Vrain decommissioning issues. See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
On February 26, 1991, the Company's Board of Directors declared a dividend of one common share purchase right ("right") on each outstanding share of the Company's common stock. All future common shares issued will contain this right. Each right stipulates an initial purchase price of $55 per share and also prescribes a means whereby the resulting effect is such that, under the circumstances described below, shareholders would be entitled to purchase additional shares of common stock at 50% of the prevailing market price at the time of exercise. The rights are not currently exercisable, but would become exercisable if certain events occurred related to a person or group acquiring or attempting to acquire 20% or more of the outstanding shares of common stock of the Company.
In the event a takeover results in the Company being merged into an acquiror, the unexercised rights could be used to purchase shares in the acquiror at 50% of market price. Subject to certain conditions, if a person or group acquires 20% but no more than 50% of the Company's common stock, the Company's Board of Directors may exchange each right held by shareholders other than the acquiring person or group for one share of common stock (or its equivalent).
If a person or group successfully acquires 80% of the Company's common stock for cash, after tendering for all of the common stock, and satisfies certain other conditions, the rights would not operate. The rights expire on March 22, 2001; however, each right may be redeemed by the Board of Directors for one cent at any time prior to the acquisition of 20% of the common stock by a potential acquiror. For a description of the rights and their terms see the Company's Rights Agreement set forth as Exhibit 1 to the Company's Form 8-A filed with the SEC on March 1, 1991, which is incorporated herein by reference.
Item 6.

Item 6. Selected Financial Data
The following selected consolidated financial data of the Company and its subsidiaries for each of the five years in the period ended December 31, 1994 should be read in conjunction with the consolidated financial statements and the management's discussion and analysis of financial condition and results of operations appearing elsewhere herein.
Item 7.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Industry Outlook
During 1994, unprecedented change occurred in the electric utility industry nationwide, furthering the development of a competitive environment. In general, the economics of the electric generation business have fundamentally changed with open transmission access and the increased availability of electric supply alternatives. Such alternatives will ultimately serve to lower customer prices, particularly in areas where only higher cost energy is currently provided. Customer demands for lower prices and supplier choices, coupled with the availability of alternative supplies (IPPFs, QFs, EWGs and power marketers), have created significant pressure for open access to the utility transmission grid and the creation of a commodity market for bulk electric supply. The EPAct directly addressed this issue by giving FERC the authority to require utilities to provide non-discriminatory open access to the transmission grid for purposes of providing wholesale customers with direct access. Additionally, an increasing number of states recently have begun to evaluate or pursue regulatory reform in an effort to proactively respond to this changing business environment.
The presence of competition and the associated pressure on prices ultimately may lead to the unbundling of products and services similar to what has evolved in the natural gas industry. The concept of a vertically integrated utility, coupled with current regulatory practices, remain increasingly incongruent with the economic forces shaping the industry. Today's market view of the future envisions an unbundled electric utility industry consisting of at least four major business segments: energy supply, transmission, distribution and energy services -each having a different driving force.
Corporate Overview
While the Company continues to pursue the overall long-term strategy of focusing on its core electric and natural gas businesses, during 1994, several short-term strategies, primarily designed to lower operating costs, were implemented to better position the Company to more effectively operate in a competitive environment. Initially, an early retirement/severance program was offered with approximately 550 employees electing to participate. Annual salary savings are estimated to be approximately $22 million. Total program costs, of approximately $39.7 million, are being amortized over 4.5 years, which is the remaining average estimated service life of the program participants.
Following the early retirement/severance program, the Company restructured internally, consistent with an anticipated unbundled business approach, in order to more effectively address customers' needs. In conjunction with the internal restructuring, an involuntary severance program was implemented. Approximately 550 management and staff level positions were eliminated, resulting in an additional estimated annual salary savings of $21 million. Involuntary severance costs of approximately $10.7 million were recognized, of which $8.7 million served to reduce pre-tax earnings. Additionally, in conjunction with the internal restructuring process, 32 customer offices were closed in support of the overall cost-containment effort.
As part of an effort to expand the Company's markets by providing value-added services, in January 1995, the Company and IBM formed an alliance to develop advanced customer service and energy management
applications for utility and energy-using customers. In particular, a subsidiary of IBM, ISSC, and the Company's new subsidiary, e prime, will develop and deliver new information technology-based applications to assist utilities and others across the country to provide more responsive and efficient customer service. IBM has committed to use the services of e prime, thus becoming its first customer. Also as part of the alliance, ISSC, under a ten-year agreement, will manage most of the Company's information technology systems and network infrastructure, resulting in the outsourcing of approximately 390 positions, effective February 13, 1995. Such arrangement is expected to result in an estimated $190 million savings to the Company during the ten-year period.
In spite of having to recognize an additional $43.4 million in costs primarily associated with the decommissioning of Fort St. Vrain in 1994, important milestones were achieved with the repowering and decommissioning activities. In July 1994, the CPUC approved a CPCN allowing the Company to repower the facility in a phased approach. The first phase is expected to be completed in 1996. Additionally, on January 26, 1995, the Company received NRC approval of its Final Survey Plan for Site Release, reducing the future uncertainty related to the completion of the decommissioning project. Decommissioning work is approximately 67% complete at December 31, 1994.
Also supporting the Company's strategy of focusing on its core electric and gas businesses, in August 1994, the Company sold all of the outstanding common stock of WGG and certain related operating assets for $87 million, resulting in a gain of approximately $34.5 million.
In response to the increasingly competitive operating environment for utilities, the regulatory climate also is changing. Currently, the Company is participating in several CPUC dockets that address this change, and it is in the process of investigating various incentive/performance- based alternative forms of regulation. However, the Company believes it will continue to be subject to rate regulation that will allow for the recovery of all of its deferred costs.
Earnings
Earnings per share were $2.57, $2.43 and $2.16 during 1994, 1993 and 1992, respectively. The increase in 1994 earnings was primarily due to the gain on the sale of WGG, as discussed above, and higher electricity sales. Furthermore, during 1994, the Company recognized additional defueling and decommissioning costs associated with Fort St. Vrain and a favorable income tax accrual adjustment following a complete analysis of the Company's income tax liabilities associated with the adoption of full normalization. The lower earnings for 1992 reflect charges related to the divestiture of certain of the Company's nonutility assets.
Electric Operations
The following table details the annual change in electric revenues and energy costs as compared to the preceding year:
Electric operating revenues increased in 1994 and 1993, when compared to the respective prior year, primarily due to favorable weather, moderate customer growth and additional revenues related to the collection of decommissioning, DSM and QF purchased power capacity costs. The increase in 1993 also includes the full-year effect of the April 1992 addition of four new wholesale customers. Warmer weather during the summer months was the primary factor that contributed to 3.4% and 6.4% increases in electricity sales in 1994 and 1993, respectively. Based on weather comparisons, it was 74% warmer than normal in 1994 and 18% warmer than normal in 1993.
Base rates are changed only through rate proceedings with the Company's and Cheyenne's regulatory agencies. Effective December 1, 1993, in connection with the final 1993 rate decision issued by the CPUC, the Company reduced its retail rates by approximately $5.2 million. This $5.2 million is comprised of a $13.1 million electric revenue decrease, a $7.1 million gas revenue increase and a $0.8 million steam revenue increase. Concurrently, all of the Company's QF capacity costs, previously recovered through the ECA, became recoverable under the QFCCA. However, the recovery of costs under the QFCCA may be subject to an earnings test, which has not yet been defined by the CPUC (see Note 8. Commitments and Contingencies - Regulatory Matters in Item 8.


Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO PUBLIC SERVICE COMPANY OF COLORADO
We have audited the accompanying consolidated balance sheets of Public Service Company of Colorado (a Colorado corporation) and subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1994. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Public Service Company of Colorado and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
As more fully discussed in Note 2 to the consolidated financial statements, the adequacy of the Company's recorded liability for defueling and decommissioning its Fort St. Vrain Nuclear Generating Station (approximately $77.0 million at December 31, 1994) is primarily dependent on assurances that the dismantlement and decommissioning of the Fort St. Vrain Nuclear Generating Station can be accomplished at currently estimated costs and that the spent fuel storage and shipment issues are successfully resolved. The outcome of the above issues cannot be determined at this time. The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of these uncertainties.
As more fully discussed in Notes 10 and 12 to the consolidated financial statements, effective January 1, 1993, the Company changed its methods of accounting for postretirement benefits other than pensions and for income taxes and, effective January 1, 1994, the Company changed its method of accounting for postemployment benefits.
Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index of financial statements is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial
statements taken as a whole.
We have also audited, in accordance with generally accepted auditing standards, the consolidated balance sheets as of December 31, 1992, 1991 and 1990 and the related consolidated statements of income, shareholders' equity and cash flows for each of the two years in the period ended December 31, 1991, (none of which are presented herein) and have expressed an opinion, which makes reference to uncertainties related to the Company's Fort St. Vrain Nuclear Generating Station, on those financial statements. In our opinion, the information set forth in the selected financial data for each of the five years in the period ended December 31, 1994 appearing in Item 6 of this Form 10-K, other than the ratios and percentages therein, is fairly stated, in all material respects, in relation to the financial statements from which it has been derived.
Denver, Colorado ARTHUR ANDERSEN LLP February 10, 1995
The accompanying notes to consolidated financial statements are an integral part of these financial statements.
The accompanying notes to consolidated financial statements are an integral part of these financial statements.
The accompanying notes to consolidated financial statements are an integral part of these financial statements.
The accompanying notes to consolidated financial statements are an integral part of these financial statements.
The accompanying notes to consolidated financial statements are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF COLORADO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1994
1. Summary of Significant Accounting Policies
Business and regulation
The Company is an operating public utility engaged, together with its subsidiaries, principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transmission, distribution, sale and transportation of natural gas. The Company is subject to the jurisdiction of the CPUC with respect to its retail electric and gas operations and the FERC with respect to its wholesale electric operations and accounting policies and practices. Cheyenne and WGI are subject to the jurisdiction of the WPSC and the FERC, respectively.
Regulatory assets and liabilities
The Company and its regulated subsidiaries prepare their financial statements in accordance with the provisions of SFAS 71. In general, SFAS 71 recognizes that accounting for rate regulated enterprises should reflect the relationship of costs and revenues introduced by rate regulation. As a result, a regulated utility may defer recognition of a cost (a regulatory asset) or recognize an obligation (a regulatory liability) if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in revenues. To the extent the Company concludes that collection of such revenues (or payment of liabilities) is no longer probable, through changes in regulation and/or the Company's competitive position, the associated regulatory asset or liability will be reversed with a charge or credit to income.
The following regulatory assets are reflected in the Company's consolidated balance sheets:
Certain costs associated with the Company's DSM programs are deferred and recovered in rates over a seven-year period through the DSMCA, which was implemented July 1, 1993. Non-labor incremental expenses, carrying costs associated with deferred DSM costs and incentives associated with approved DSM programs are recovered on an annual basis.
Costs incurred to reacquire debt prior to scheduled maturity dates are deferred and amortized over the life of the debt issued to finance the reacquisition or as approved by the regulator.
Recoverable purchased gas and electric energy costs - net
The Company and Cheyenne tariffs contain clauses which allow recovery of certain purchased gas and electric energy costs in excess of the level of such costs included in base rates. These cost adjustment tariffs are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred. A substantial portion of this deferred amount represents the costs incurred to provide gas and electric energy which customers have used but for which they have not yet been billed. The cumulative effects are recognized as a current asset or liability until adjusted by refunds or collections through future billings to customers.
Other
Property, plant and equipment includes approximately $18.4 million and $25.4 million, respectively, for costs associated with the engineering design of the future Pawnee 2 generating station and certain water rights located in southeastern Colorado, also obtained for a future generating
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
station. Effective with the December 1, 1993 CPUC rate order, the Company is earning a return on these investments based on the Company's weighted average cost of debt and preferred stock.
Consolidation
The Company follows the practice of consolidating the accounts of its significant subsidiaries. All intercompany items and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to the current year's presentation.
Revenue recognition
The Company and Cheyenne accrue for estimated unbilled revenues for services provided after the meters were last read on a cycle billing basis through the end of each year.
Statements of cash flows
For purposes of the consolidated statements of cash flows, the Company and its subsidiaries consider all temporary cash investments to be cash equivalents. These temporary cash investments are securities having original maturities of three months or less or having longer maturities but with put dates of three months or less. Income taxes and interest (excluding amounts capitalized) paid:
Non-cash transactions:
Shares of common stock (334,223 in 1994, 329,220 in 1993 and 333,418 in 1992), valued at the market price on date of issuance (approximately $10.1 million in 1994, $9.4 million in 1993 and $8.7 million in 1992), were issued to the Employees' Savings and Stock Ownership Plan of Public Service Company of Colorado and Participating Subsidiary Companies. The estimated issuance values were recognized in other operating expenses during the respective preceding years. During 1994, 7,892 shares of common stock, valued at the market price on date of issuance (approximately $0.2 million), were issued to certain executives. These stock issuances were not cash transactions and are not reflected in the consolidated statement of cash flows.
A $16.8 million capital lease obligation was incurred in 1994 for computer equipment.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Changes in certain balance sheet accounts, resulting from the sale of WGG in 1994 and the Colorado-Ute acquisition in 1992, have been recognized as non-cash activity.
Property and depreciation
Replacements and betterments representing units of property are capitalized. Maintenance and repairs of property and replacements of items of property determined to be less than a unit of property are charged to operations as maintenance. The cost of units of property retired, together with cost or removal, less salvage, is charged against accumulated depreciation.
Provisions for depreciation of property for financial accounting purposes are based on straight-line composite rates applied to the various classes of depreciable property. Depreciation rates include provisions for disposal and removal costs of property, plant and equipment. Depreciation expense, expressed as a percentage of average depreciable property, approximated 2.6% for the year ended December 31, 1994 and 3.0% for the years ended December 31, 1993 and 1992. The average rate for 1994 reflects the effects of using a CPUC-approved longer estimated depreciable life for the Company's electric steam production facilities. For income tax purposes, the Company and its subsidiaries use accelerated depreciation and other elections provided by the tax laws.
Allowance for funds used during construction
AFDC, as defined in the system of accounts prescribed by the FERC and the CPUC, represents the net cost during the period of construction of borrowed funds used for construction purposes, and a reasonable rate on funds derived from other sources. AFDC does not represent current cash earnings. The Company capitalizes AFDC as a part of the cost of utility plant. The AFDC rates or ranges of rates used during 1994, 1993 and 1992 were 6.81%-8.75%, 10.21% and 8.95%-10.21%, respectively.
Income taxes
The Company and its subsidiaries file consolidated Federal and state income tax returns. Income taxes are allocated to the subsidiaries based on separate company computations of taxable income or loss. Investment tax credits have been deferred and are being amortized over the service lives of the related property. Deferred taxes are provided on temporary differences between the financial accounting and tax bases of assets and liabilities using the tax rates which are in effect at the balance sheet date (see Note 12).
Gas in underground storage
Gas in underground storage is accounted for under the last-in, first-out (LIFO) cost method. The estimated replacement cost of gas in
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
underground storage at December 31, 1994, exceeded the LIFO cost by approximately $12.5 million.
Cash surrender value of life insurance policies
The following amounts related to COLI contracts, issued by one major insurance company, are recorded as a component of Investments, at cost, on the consolidated balance sheets:
2. Fort St. Vrain
Overview
During 1994, the Company recognized additional expenses aggregating approximately $43.4 million ($26.7 million after-tax or 43 cents per share) associated with various Fort St. Vrain issues as described below, including the defueling and decommissioning of the facility.
During 1986, the Company entered into a Stipulation and Settlement Agreement with the CPUC, the OCC and the other parties involved in litigation and administrative proceedings related to Fort St. Vrain's history of limited operations. As a result, the Company's investment in Fort St. Vrain was removed from rate base and certain charges were recognized including the write-down of a substantial portion of such investment and the recognition of the then estimated future unrecoverable defueling and decommissioning expenses.
In 1989, the Company announced its decision to end nuclear operations at Fort St. Vrain. The decision was based on the financial impact of an anticipated lengthy outage necessary to repair the plant's steam generator system coupled with the plant's history of reduced levels of generation. The Company has completed defueling from the reactor to the ISFSI as discussed below in the section entitled "Defueling" and is currently decommissioning the facility as described below in the section entitled "Decommissioning."
The Company has been pursuing the repowering of Fort St. Vrain and, on July 1, 1994, the CPUC issued a decision granting the Company's application for a CPCN for Phase 1 and Phase 2. The decision approved, with certain modifications, a Stipulation and Settlement Agreement (the
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Settlement) among the Company, the OCC and various other parties regarding the CPCN.
Repowering
Fort St. Vrain will be repowered as a gas fired combined cycle steam plant consisting of two combustion turbines and two heat recovery steam generators totalling 471 Mw. The CPCN provides for the repowering of Fort St. Vrain in a phased approach as follows: Phase 1A - 130 Mw in 1996, Phase 1B - 102 Mw in 1998 and Phase 2 - 239 Mw in 1999. The phased repowering allows the Company flexibility in timing the addition of this generation supply to meet future load growth.
The Settlement provides for approximately $67.4 million of the then remaining $72.5 million investment in the existing Fort St. Vrain assets (comprised of approximately $60.1 million in plant assets and a $12.4 million regulatory asset associated with deferred income taxes) to be returned to rate base in future electric rate cases following the completion of each phase or phases of the repowering. The Settlement allows for the following assignment of existing assets: Phase 1A - $28.9 million, Phase 1B - $27.6 million and Phase 2 - $10.9 million. The approximately $5 million balance of the Company's remaining investment in Fort St. Vrain assets will not be returned to rate base pursuant to the Settlement. During 1994, the Company completed an evaluation of alternative uses of these assets and concluded that approximately $4.5 million of such assets will not be recovered; therefore, a $4.5 million impairment reserve has been established. Because of the receipt of the CPCN related to the repowering of Fort St. Vrain, the Company believes the recovery of the remaining investment in the facility is probable.
Additionally, a detailed assessment of inventory requirements necessary for the completion of decommissioning and repowering was completed during 1994. Such analysis identified that approximately $4.5 million of inventory costs will not be recovered and, therefore, a $4.5 million impairment reserve has also been established.
Decommissioning
The Company has been pursuing the early dismantlement/decommissioning of Fort St. Vrain following the 1991 CPUC approval of the recovery from customers of approximately $124.4 million (plus a 9% carrying cost) for such activities, as well as the 1992 NRC approval of the Company's early dismantlement/decommissioning plan. The decommissioning amount being recovered from customers, which began July 1, 1993 and extends over a twelve-year period, represents the inflation- adjusted estimated remaining cost of the early dismantlement/decommissioning activities not previously recognized as expense. At December 31, 1994, approximately $107.4 million of such amount remains to be collected from customers and, therefore, is reflected as a regulatory asset on the consolidated balance sheet. The annual
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
amount recovered from customers each year is approximately $13.9 million.
The Company has contracted with Westinghouse Electric Corporation and MK-Ferguson, a division of Morrison Knudsen Corporation, for the early dismantlement/decommissioning of Fort St. Vrain. Since defueling has been completed from the reactor to the ISFSI and the NRC decommissioning order has been received, the Company and the contractors have proceeded with decommissioning activities. At December 31, 1994, approximately 67% of the decommissioning process has been performed with final completion of such activities anticipated in the second quarter of 1996.
The decommissioning contract stipulates a fixed price, based on a defined work scope; however, such price has been and could be further modified due to changes in work scope or applicable regulations. In addition to the four substantive changes in work scope previously agreed to by the Company since the initiation of decommissioning activities, the decommissioning contractors notified the Company of several additional potential scope changes which were primarily related to the identification of higher radiation levels in the reactor core than originally anticipated and regulatory changes related to site release as discussed below.
On October 25, 1994, the Company and the decommissioning contractors reached an agreement resolving all issues and claims related to identified and certain possible future changes in scope of work covered by the contract, with certain exceptions. In order to complete all decommissioning activities related to such scope changes, the Company recognized an additional $15 million in decommissioning expense during 1994.
The significant exceptions to the agreement, which were also areas for potential changes in the defined work scope under the decommissioning contract, include changes in law, radioactive material created by activation in the lower portion of the reactor, as well as changes in the methodology requirements and guidance established by the NRC for final site release. On January 26, 1995, the Company received NRC approval of its Final Survey Plan for Site Release reducing the future uncertainty related to this issue. In the event additional costs are identified, which relate to an issue excepted from the agreement, the decommissioning contractors will perform all required activities on a cost basis.
While this agreement with the decommissioning contractors does not eliminate all future decommissioning risk, the Company believes it will serve to substantially reduce such risk. However, the Company can provide no assurance that recognition of additional costs will not be required if events or circumstances unknown to the Company today are identified in the future.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Defueling
Currently, six segments of Fort St. Vrain's spent nuclear fuel (segments 4-9) are stored in the ISFSI located at the plant site. While the Company has entered into two separate agreements with the DOE for (a) the temporary storage and processing of segments 1-8 at a DOE facility located in the State of Idaho (such contract includes an option to store/reprocess additional spent fuel segments at the DOE's discretion) and (b) the disposal of segment 9 at a Federal repository, resolution of all spent fuel reprocessing/disposal issues has been substantially delayed pending resolution of several lawsuits filed during 1991 by and among the Company, the DOE, the State of Idaho and the Shoshone - Bannock Indian Tribes. While the plant was operating and as part of routine refueling procedures, three spent fuel segments were transported to the Idaho facility. It is currently estimated that the Federal repository will not be available until 2010. The Company, however, intends to pursue with the DOE the storage/reprocessing of segment 9 at the Idaho facility in conjunction with the first eight segments.
Most recently, the DOE has required that an EIS be completed relative to, among other things, the receipt and storage of spent fuel at the Idaho facility. The DOE had issued a draft EIS and the Company has submitted comments. Modifications to the Idaho facility will be required to accommodate the new spent fuel shipping casks. These modifications would be completed subsequent to the issuance of the EIS. The time required for these modifications from the DOE has been estimated to be between 15-18 months. In addition, the DOE has stated that a facility readiness review will be required. Such review is standard DOE procedure required to validate the readiness of equipment following a shut-down period. Such review will also be conducted subsequent to the completion of the EIS.
As a result of increased uncertainties related to the ultimate disposal of Fort St. Vrain's spent nuclear fuel, the Company recognized during 1994 an additional $15 million defueling reserve, determined on a present value basis. This amount represents the estimated cost of operating and maintaining the ISFSI until 2020 (if required), the earliest date the Company believes a Federal repository will be available to accept the Company's spent nuclear fuel. These estimated expenditures have been escalated for inflation using an average rate of 3.5% and discounted to present value at a rate of 8%.
The estimated total cost of defueling and decommissioning Fort St. Vrain is approximately $361.8 million. At December 31, 1994, approximately $284.8 million has been spent for such activities with the remaining $77 million defueling and decommissioning liability reflected on the consolidated balance sheet ($25 million - defueling; $52 million - decommissioning). Because of the possibility of further changes in the decommissioning work scope, changes in applicable regulations and/or the uncertainties related to the final disposal of spent fuel, there can be no
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
assurance that the actual cost of defueling and decommissioning will not exceed the estimated liability. The Company could be required to revise the estimated cost of defueling and decommissioning as a result of any such matters.
Funding
Under NRC regulations, the Company is required to make filings with, and obtain the approval of, the NRC regarding certain aspects of the Company's decommissioning proposals, including funding. On January 27, 1992, the NRC accepted the Company's funding aspects of the decommissioning plan. The Company has also obtained an unsecured irrevocable letter of credit totaling $125 million that meets the NRC's stipulated funding guidelines including those proposed on August 21, 1991 that address decommissioning funding requirements for nuclear power reactors that have been prematurely shut down. In accordance with the NRC funding guidelines, the Company is allowed to reduce the balance of the letter of credit based upon milestone payments made under the fixed-price decommissioning contract. As a result of such payments, at December 31, 1994, the letter of credit had been reduced to $66 million.
The Company had previously set aside approximately $30 million in trust accounts for decommissioning the reactor. Since decommissioning activities have commenced, the Company completed withdrawing funds from the trust accounts during the second quarter of 1993. As previously discussed, on July 1, 1993, the Company began collection of the remaining decommissioning costs from customers.
In addition, the Company has established a separate decommissioning trust for the ISFSI which had funds of approximately $1.6 million at December 31, 1994. It is anticipated that this amount, together with the expected earnings on the funds, will be sufficient to decommission the ISFSI.
Costs for maintaining the ISFSI and removing fuel from the ISFSI, which the Company is not required to prefund, will be paid from a combination of operating funds of the Company and its subsidiaries and/or external financing.
Uranium Enrichment Facility Decommissioning Assessment
As part of the EPAct, the DOE Uranium Enrichment Enterprise Decontamination and Decommissioning Fund was established to provide for the decommissioning of DOE fuel enrichment facilities. The EPAct provides for a 15 year assessment of all domestic utilities that own nuclear generation facilities. The Company believed it would be excluded from the provisions of the EPAct as Fort St. Vrain was constructed under the Atomic Energy Demonstration Reactor Program. During 1994, the DOE advised the Company that it has not been exempted from the provisions of the EPAct. As a result, the Company recognized an approximate $4 million expense
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
associated with this assessment, determined on a present value basis (escalated for inflation at 4% and discounted at 8%). The Company, however, intends to further investigate the applicability of the EPAct as well as the recovery of such costs through the regulatory process. However, the Company is uncertain as to the ultimate resolution of this issue.
Nuclear Insurance
The Price Anderson Act, as amended, limits the public liability of a licensee for a single nuclear incident at its nuclear power plant to the amount of financial protection available through liability insurance and deferred premium assessment charges, currently approximately $7.8 billion, which includes a 5% surcharge. Financial protection for this exposure is provided by private insurance in an amount available from private insurers (currently $200 million). The Price Anderson Act also requires licensees to participate in an assessable excess liability program through an indemnity program with the NRC. Under the terms of this indemnity program, the Company could be liable for retrospective assessments of approximately $79 million per nuclear incident at any domestic nuclear power plant, indexed every five years for inflation, provided that not more than $10 million would be payable per incident in any one year. In consideration of the shutdown and defueled status of Fort St. Vrain, the Company requested an exemption from its indemnification obligations under the Price Anderson Act. On February 17, 1994, the NRC granted this request, exempting the Company from participation in this indemnity program and limiting the amount of private insurance required to $100 million.
In addition to the Company's liability insurance, Federal regulations require the Company to maintain $1.06 billion in nuclear property insurance. Effective February 1, 1991, however, the NRC granted the Company's exemption request to reduce the nuclear property insurance coverage from $1.06 billion to a minimum of $169 million. This lower limit would cover stabilization and decontamination expenses resulting from a worst case accident. The Company currently maintains $281 million in property damage and decontamination insurance. The additional insurance coverage above the required $169 million is necessary to provide coverage for the estimated depreciated replacement value of the plant assets that will be used in the repowering of Fort St. Vrain.
3. Divestiture of Nonutility Assets
As part of the Company's continuing strategy to focus its efforts on the core electric and gas businesses, the Company has divested certain nonutility investments.
WestGas Gathering, Inc.
During the third quarter of 1994, the Company sold all of its
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
outstanding common stock of WGG, its wholly-owned subsidiary, and certain related operating assets of the Company which are used by WGG for approximately $87 million. The Company recognized a pre-tax gain of approximately $34.5 million ($19.5 million after-tax or approximately 31 cents per share). In addition, pursuant to a Stipulation and Agreement dated November 17, 1992, approved by the CPUC by Order dated December 7, 1992, the regulatory treatment of a limited portion of this gain may be subject to a proceeding before the CPUC. The Company believes the resolution of this matter will not have a material impact on the Company's results of operations or financial position.
Fuel Resources Development Co.
In June 1993, the Company's Board of Directors approved pursuing the divestiture of Fuelco, a wholly-owned subsidiary primarily involved in the exploration and production of oil and natural gas. In 1993, the Company recorded the estimated effects of the disposition of all properties, including all costs expected to be incurred through the close of operations. All property sales have been completed, except the San Juan Coal Bed Methane properties. The Company is re-evaluating its alternatives related to the disposition of these properties. The net book value of the San Juan properties is approximately $21.7 million.
In December 1992, the Company terminated its involvement in Fuelco's Synhytech fuel conversion technology project. As a result, Fuelco recognized an expense of approximately $26.9 million ($16.8 million after- tax) associated with writing-off its entire investment in the Synhytech plant and recognizing certain additional costs which were incurred in connection with the termination of this project.
Bannock Center Corporation
In December 1992, BCC sold substantially all of its real estate properties located near downtown Denver for $6 million, resulting in a loss of approximately $11.4 million ($8.4 million after-tax).
4. Capital Stock
Common Stock
On December 7, 1992, the Company filed a registration statement with the SEC relating to the registration of 1,000,000 shares of common stock, $5 par value, and 1,000,000 common share purchase rights. These shares and rights are associated with the Company's Omnibus Incentive Plan discussed in Note 10.
During 1991, the Company's Board of Directors declared a dividend of one common share purchase right (right) on each outstanding share of the Company's common stock. All future common shares issued will contain this right. Each right stipulates an initial purchase price of $55 per share
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
and also prescribes a means whereby the resulting effect is such that, under the circumstances described below, shareholders would be entitled to purchase additional shares of common stock at 50% of the prevailing market price at the time of exercise. These rights are not currently exercisable, but would become exercisable if certain events occurred related to a person or group acquiring or attempting to acquire 20% or more of the outstanding shares of common stock of the Company.
In the event a takeover results in the Company being merged into an acquiror, the unexercised rights could be used to purchase shares in the acquiror at 50% of market price. Subject to certain conditions, if a person or group acquires 20%, but no more than 50% of the Company's common stock, the Company's Board of Directors may exchange each right held by shareholders other than the acquiring person or group for one share of common stock (or its equivalent).
If a person or group successfully acquires 80% of the Company's common stock for cash, after tendering for all of the common stock, and satisfies certain other conditions, the rights would not operate. The rights expire on March 22, 2001; however, each right may be redeemed by the Board of Directors for one cent at any time prior to the acquisition of 20% of the common stock by a potential acquiror.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Preferred Stock
The preferred stock may be redeemed at the option of the Company upon at least 30, but not more than 60, days notice in accordance with the following schedule of prices, plus an amount equal to the accrued dividends to the date fixed for redemption:
Cumulative preferred stock, not subject to mandatory redemption:
$100 par value, all series: $101 per share. $25 par value, 8.40% series: $25.25 per share.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Cumulative preferred stock, subject to mandatory redemption:
7.50% series: $102.25 per share on or prior to August 31, 1995, reducing each year thereafter by $0.25 per share until August 31, 2003, after which the redemption price is $100 per share; 8.40% series: $102.50 per share on or prior to July 31, 1995, and reducing each year thereafter by $0.25 per share until July 31, 2004, after which the redemption price is $100 per share.
In 1995 and in each year thereafter, the Company must offer to repurchase 12,000 shares of the 7.50% series subject to mandatory redemption at $100 per share, plus accrued dividends to the date set for repurchase, and 13,760 shares of the 8.40% series subject to mandatory redemption at $100 per share, plus accrued dividends to the date set for repurchase. Consequently, this preferred stock to be redeemed is classified as preferred stock subject to mandatory redemption within one year in the December 31, 1994 consolidated balance sheet. In 1994, 1993, and 1992, the Company repurchased 2,133 shares, 2,000 shares and 7,135 shares, respectively of the 8.40% cumulative preferred series subject to mandatory redemption. No other changes in preferred stock occurred in the three years ended December 31, 1994.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Substantially all properties of the Company and its subsidiaries, other than expressly excepted property, are subject to the liens securing the Company's First Mortgage Bonds and First Collateral Trust Bonds or the mortgage bonds and notes of subsidiaries. Additionally, there is a second lien on the Company's electric property securing the Company's First Collateral Trust Bonds. The Company's First Collateral Trust Bonds are additionally secured by an equal amount of First Mortgage Bonds which bear no interest.
The aggregate annual maturities and sinking fund requirements during the five years subsequent to December 31, 1994 are (in thousands of dollars):
The Company and Cheyenne expect to satisfy substantially all of their sinking fund obligations through the application of property additions.
6. Notes Payable and Commercial Paper
Information regarding notes payable and commercial paper for the years ended December 31, 1994 and 1993 is as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
7. Bank Lines of Credit and Compensating Bank Balances
Arrangements by the Company and its subsidiaries for committed lines of credit are maintained entirely by fee payments in lieu of compensating balances. Arrangements for uncommitted lines of credit have no fee or compensating balance requirements.
On November 22, 1994, the Company, PSCCC and certain subsidiaries extended a credit facility with several banks providing $300 million in committed bank lines of credit. The credit facility, which is used primarily to support the issuance of commercial paper by the Company and PSCCC, alternatively provides for direct borrowings thereunder. Under the current extension, Cheyenne, 1480 Welton, Inc., Fuelco and PSRI are provided access to the credit facility with direct borrowings guaranteed by the Company. The facility expires November 21, 1995.
Individual arrangements for uncommitted bank lines of credit totaled $75 million at December 31, 1994. The unused uncommitted bank lines of credit at December 31, 1994 was $9 million. The Company may borrow under uncommitted preapproved lines of credit upon request; however, the banks have no firm commitment to make such loans.
8. Commitments and Contingencies
Regulatory Matters
Electric and Gas Cost Adjustment Mechanisms
The Company's ECA mechanism was revised and a new QFCCA mechanism was implemented on December 1, 1993, along with the base rate changes resulting from the 1993 rate case. Under the revised ECA, fuel used for generation and purchased energy costs from utilities, QFs and IPPFs (excluding all purchased capacity costs) to serve retail customers, are recoverable. Purchased capacity costs are recovered as a component of base rates, except as described below. The ECA rate is revised annually on October 1. Recovered energy costs are compared with actual costs on a monthly basis and differences, including interest, are deferred. Under the QFCCA, all purchased capacity costs from new QF projects, not reflected in base rates, are recoverable similar to the ECA. While the CPUC approved the QFCCA, recovery of such costs may be subject to an earnings test, which has not yet been defined by the CPUC. The OCC has proposed an annual earnings test that may result in a reduction of QFCCA recoveries to the extent the Company's earnings are in excess of its 11% authorized rate of return on regulated common equity. Hearings regarding this matter are scheduled for April 1995.
The CPUC held a prehearing conference on May 24, 1994 for the purpose of establishing a schedule for reviewing the justness and reasonableness of GCA and ECA mechanisms used by gas and electric utilities within its jurisdiction resulting in the opening of an
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
investigatory docket. Open hearings were held in December 1994. The OCC and the CPUC staff are recommending the elimination of these cost adjustment mechanisms. The Company is in opposition to the elimination of these cost adjustment mechanisms and has filed initial comments, as well as responded to the comments filed by the other parties. On February 6-7, 1995, as part of an open hearing, the CPUC determined that proceeding with a generic ECA rulemaking docket was not appropriate. However, the Company is required to make an individual filing with the CPUC related to its ECA by September 1, 1995 to review whether the ECA should be maintained in its present form, altered or eliminated. Additionally, the CPUC preliminarily determined that the GCA will continue under current practices. The CPUC staff will hold informal roundtable discussions for the purpose of clarifying the review procedures for the GCA.
On June 8, 1994, the CPUC approved the recovery of certain "energy efficiency credits" from retail jurisdiction customers through the DSMCA with collection estimated to begin July 1, 1995. At December 31, 1994, the Company has recognized approximately $6.7 million of unbilled revenue related to these credits. On December 1, 1994, the OCC filed an appeal in Denver District Court of the CPUC's decision approving the collection of these credits. If the OCC is successful in its appeal, the Company could be required to reverse these unbilled revenues.
Incentive Regulation and Demand Side Management
The CPUC has opened a separate docket to investigate issues relating to the adoption and implementation of incentive regulation, which includes the concept of decoupling the Company's earnings from sales, and additional DSM incentives. On February 10, 1994, the parties to this docket filed a unanimous stipulation and settlement agreement with the CPUC. Provisions of the stipulation include, among other things, retaining the cost recovery component of the DSMCA through December 31, 1998, modifying slightly the DSM incentive mechanism for 1994 and 1995 and forming a technical working group to study and analyze various alternative annual revenue reconciliation mechanisms and incentive mechanisms for 1996 through 1998, which would replace existing DSM incentives until another mechanism or regulatory approach is approved by the CPUC. The stipulation agreement, which includes a procedural schedule to review the results of all studies and simulations over the next year, was approved by the CPUC on June 16, 1994. The technical working group will present to the CPUC a detailed analysis demonstrating the effect of the various proposed mechanisms by the end of the first quarter of 1995.
1993 Rate Case
On November 26, 1993, the CPUC issued its final written decision regarding the Company's 1993 rate case, lowering the Company's annual base rate revenue requirement by approximately $5.2 million (a $13.1 million electric revenue decrease partially offset by a $7.1 million gas revenue increase and a $0.8 million steam revenue increase) with new rates
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
effective December 1, 1993. The OCC has filed in Denver District Court an appeal of the CPUC's decision. The OCC has claimed that the accounting related to a specific income tax issue results in the overcollection of costs from ratepayers. The Company is in opposition to the appeal. The Company believes that the resolution of this appeal will not have a material effect on its financial position or results of operations.
On August 1, 1994, the Company filed its Phase II testimony. The Phase II proceedings will address cost allocation issues and specific rate changes for the various customer classes based on the results of the Phase I hearings and decision that became effective December 1, 1993. A final CPUC decision on the Phase II proceedings is expected in late 1995.
Environmental Issues
Environmental Site Cleanup
Under CERCLA, the EPA has identified, and a Phase II environmental assessment has revealed, low level, widespread contamination from hazardous substances at the Barter Metals Company properties located in central Denver. For an estimated 30 years, the Company sold scrap metal and electrical equipment to Barter for reprocessing. The Company, which is one of several PRPs, is involved in the cleanup of this site which began in November 1992 and is expected to be completed during the second quarter of 1995. The total project cost is currently estimated to be approximately $8.5 million. The Company believes it is probable that a significant portion of these cleanup costs will be recovered through claims made against the Company's insurance companies as monetary settlements with certain insurers have been achieved. Lawsuits against certain remaining insurance companies have been filed in the Denver District Court and a trial is scheduled to begin in late February 1995. To the extent such costs are not recovered by insurance or from other PRPs, the Company believes it is probable that such costs will be recovered through the rate regulatory process.
PCB presence has been identified in the basement of an historic office building located in downtown Denver. The Company was negotiating the future cleanup with the current owners; however, on October 5, 1993, the owners filed a civil action against the Company in the Denver District Court. The action alleged that the Company was responsible for the PCB releases and additionally claimed other damages in unspecified amounts. On August 8, 1994, the Denver District Court entered a judgment approving a $5.3 million settlement agreement between the Company and the building owners resolving all claims between the Company and the building owners. The Company believes it is probable that it will recover some portion of these costs through insurance claims. To the extent such costs are not recovered by insurance, the Company believes it is probable that such costs will be recovered through the rate regulatory process.
The Company is pursuing reoccupation of its former Headquarters
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Office Building, which contained asbestos. The asbestos abatement/removal at the site was recently completed at a cost of approximately $8.3 million. The Company plans to further remodel and reoccupy the facility during 1995 and 1996 and expects to recover all such costs through the rate regulatory process.
The Elitch Gardens Amusement Park site near downtown Denver has revealed low level, widespread contamination. The Company had used the site in the past as a manufactured gas plant site and is one of three PRPs. An agreement has been signed by Trillium Corporation, a PRP, Elitch Gardens Co. and the Company, releasing the Company from responsibility for the first $2 million of expenses related to contamination. Any contamination expenses incurred during construction or thereafter which exceed $2 million will be the responsibility of the Company; however, the Company could then pursue recovery of the incurred costs from Burlington Northern Railroad, the third PRP, and/or through insurance claims. Contamination expenses to date have not exceeded $2 million.
In addition to these sites, the Company has identified several sites where cleanup of hazardous substances may be required. While potential liability and settlement costs are still under investigation and negotiation, the Company believes that the resolution of these matters will not have a material effect on its financial position or results of operations. The Company fully intends to pursue the recovery of all significant costs incurred for such projects through insurance claims and/or the rate regulatory process. To the extent any costs are not recovered through the options listed above, the Company would be required to recognize an expense for such unrecoverable amounts.
Other Environmental Matters
Under the Clean Air Act Amendments of 1990, coal burning power plants are required to reduce SO 2 and NOx emissions to specified levels through a phased approach. The Company is currently meeting Phase I emission standards placed on SO2 through the use of low sulfur coal and the operation of pollution control equipment on certain generation facilities. The Company will be required to modify certain boilers by the year 2000 to reduce NOx emissions in order to comply with Phase II requirements at an estimated total future cost of approximately $21 million. The Company is studying its options to reduce SO 2 emissions and currently does not anticipate that these regulations will significantly impact its operations.
On August 18, 1993, a conservation organization filed a complaint in U.S. District Court for the District of Colorado, pursuant to Section 304 of the Federal Clean Air Act, against the Company and the other joint owners of the Hayden station. The plaintiff alleges that, on certain occasions, the station exceeded opacity limitations during the past several years. The complaint seeks, among other things, civil monetary
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
penalties. At this time the Company is not able to estimate the amount, if any, of its potential liability or whether additional particulate control equipment will be required. Discovery has been completed and a trial date has been set for August 1995.
The Company believes that, consistent with historical regulatory treatment, any costs to comply with pollution control regulations would be recovered from its customers. However, no assurance can be given that this practice will continue in the future.
Purchase requirements
Coal purchases and transportation
At December 31, 1994, the Company had in place long-term contracts for the purchase of coal through 2017. The minimum remaining quantities to be purchased under these contracts total 92 million tons. The coal purchase prices are subject to periodic adjustment for inflation and market conditions. Total estimated obligations, based on current prices, were approximately $820 million at December 31, 1994.
The Company has entered into long-term contracts for the transportation of coal by railroad in Company-owned or leased railcars to existing power plants. These agreements, expiring in 2000, provide for a minimum remaining transport quantity of 27 million tons. Coal transport contract prices are negotiated based on market conditions and are adjusted periodically for inflation and operating factors. Total estimated obligations, based on current prices, were approximately $93 million at December 31, 1994.
Natural gas purchases and transportation
The Company and Cheyenne have entered into long-term contracts for the purchase, firm transportation and storage of natural gas which expire on various dates through 1998. In compliance with the rules established by FERC Order 636, the Company renegotiated contracts during 1993 with its two primary gas pipeline suppliers and committed to continue purchasing gas for the next three years. The Company will not incur any gas supply realignment costs otherwise applicable under FERC Order 636. At December 31, 1994, the Company and Cheyenne have minimum obligations under such contracts of $222 million in 1995 declining thereafter for a total estimated commitment of $431 million.
Purchased power
The Company and Cheyenne have entered into agreements with utilities and QFs for purchased power to meet system load and energy requirements, to replace generation from Company-owned units under maintenance and outages, and to meet the Company's operating reserve obligation to the Pool.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company has various pay-for-performance contracts with QFs having expiration dates through the year 2026. In general, these contracts provide for capacity payments, subject to the QFs meeting certain contract obligations, and energy payments based on actual power taken under the contracts. The capacity and energy costs are recovered through base rates, the ECA and the QFCCA. Additionally, the Company and Cheyenne have long-term purchased power contracts with various regional utilities expiring through 2022. In general, these contracts provide for capacity and energy payments which approximate the cost of the sellers. These costs have historically been recoverable through the ECA; however, effective December 1, 1993, the Company's capacity costs were reflected in base rates. Total capacity and energy payments associated with such contracts were $427 million, $366 million and $332 million in 1994, 1993 and 1992, respectively.
At December 31, 1994, the estimated future payments for capacity that the Company and Cheyenne are obligated to purchase, subject to availability, are as follows:
Historically, all minimum coal, coal transportation, natural gas and purchased power requirements have been met.
Other purchases
Commitments made for the purchase of materials, plant and equipment additions, DSM expenditures and other various items aggregated approximately $405 million at December 31, 1994.
Employee Litigation
Several employee lawsuits have been filed against the Company involving alleged sexual/age discrimination. In addition, certain employees terminated as part of the Company's 1991/1992 organizational analysis asserted breach of contract and promissory estoppel with respect to job security and breach of the covenant of good faith and fair dealing. A jury recently awarded two of 21 plaintiffs approximately $500,000, which
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
the Company has accrued. The Company is considering an appeal of this decision. The remaining 19 claims were dismissed. The Company is actively contesting all outstanding lawsuits and believes the ultimate outcome will not have a material impact on the Company's results of operations or financial position.
Leasing program
The Company and its subsidiaries maintain operating leases for equipment and facilities used in the normal course of business. The majority of these operating leases are under a leasing program that has initial noncancelable terms of one year, while the remaining operating leases have various terms. These leases may be renewed or replaced. No material restrictions exist in these leasing agreements concerning dividends, additional debt, or further leasing. Rental expense for 1994, 1993 and 1992 was $29.7 million, $28.1 million, and $25.1 million, respectively. At December 31, 1994, estimated future minimum rental payments applicable to noncancelable operating leases were as follows:
The Company has in place a leasing program which includes a provision whereby the Company indemnifies the lessor for all liabilities which might arise from the acquisition, use, or disposition of the leased property.
Fort St. Vrain
See Note 2 for certain contingencies relating to Fort St. Vrain.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
9. Jointly-Owned Electric Utility Plants
The Company's investment in jointly-owned plants and its ownership percentages as of December 31, 1994 are:
These assets include approximately 331 Mw of net dependable generating capacity. The Company is responsible for its proportionate share of operating expenses (reflected in the consolidated statements of income) and construction expenditures.
10. Employee Benefits
Pensions
The Company and its subsidiaries (excluding Natural Fuels) maintain a noncontributory defined benefit pension plan covering substantially all employees.
The net pension expense in 1994, 1993 and 1992 was comprised of:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The pension plan was amended in 1994 (as discussed below) requiring the use of two sets of assumptions in the calculation of the 1994 net periodic pension cost. Significant assumptions used in determining net periodic pension cost were:
Variances between actual experience and assumptions for costs and returns on assets are amortized over the average remaining service lives of employees in the plan.
A comparison of the actuarially computed benefit obligations and plan assets at December 31, 1994 and 1993, is presented in the following table. Plan assets are stated at fair value and are comprised primarily of corporate debt and equity securities, a real estate fund and government securities held either directly or in commingled funds. The Company and its subsidiaries' funding policy is to contribute annually, at a minimum, the amount necessary to satisfy the IRS funding standards.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Significant assumptions used in determining the benefit obligations were:
On January 25, 1994, the Board of Directors approved an amendment to the Plan which offered an incentive for early retirement for employees age 55 or older with 20 years of service as well as a Severance Enhancement Program (SEP) option for these same eligible employees for the period February 4, 1994 to April 1, 1994. The Plan amendment generally provided for the following retirement enhancements: a) unreduced early retirement benefits, b) three years of additional credited service and c) a supplement of either a one-time payment equal to $400 for each full year of service to be paid from general corporate funds or a $250 social security supplement each month up to age 62 to be paid by the Plan.
The SEP provided for: a) a one-time severance ranging from $20,000 - $90,000, depending on an employee's organization level, b) a continuous years of service bonus (up to 30 years) and c) a cash benefit of $10,000.
Approximately 550 employees elected to participate in the early retirement/severance enhancement program, of which approximately 370 employees elected the early retirement benefit. The total cost of the program was approximately $39.7 million. These costs have been deferred and, effective April 1, 1994, are being amortized to expense over approximately 4.5 years in accordance with rate regulatory treatment. This amortization period represents the participants' average remaining years of service to their expected retirement date.
During 1993, the Board of Directors of the Company approved amendments that: 1) eliminated the minimum age of 21 for receiving credited service, 2) provided for an automatic increase in monthly payments to a retired plan member in the event the member's spouse or other contingent annuitant dies prior to the member and 3) provided for Average Final Compensation to be based on the highest average of three consecutive years compensation. These plan changes increased the projected benefit obligation by approximately $24.6 million.
Involuntary severance program
During 1994, in a continuing effort to lower operating costs, the Company implemented an involuntary severance program which reduced management and staff levels by approximately 550 employees. Approximately $10.7 million of involuntary severance costs were accrued, of which $8.7 million served to reduce pre-tax earnings.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Postretirement benefits other than pensions
The Company and its subsidiaries provide certain health care and life insurance benefits for retired employees. A significant portion of the employees become eligible for these benefits if they reach either early or normal retirement age while working for the Company or its subsidiaries. Historically, the Company has recorded the cost of these benefits on a pay-as-you-go basis, consistent with the regulatory treatment. Effective January 1, 1993, the Company and its subsidiaries adopted SFAS 106 which requires the accrual, during the years that an employee renders service to the Company, of the expected cost of providing postretirement benefits other than pensions to the employee and the employee's beneficiaries and covered dependents.
The Company is transitioning to full accrual accounting for OPEB costs between January 1, 1993 and December 31, 1997, consistent with the accounting requirements for rate regulated enterprises. All OPEB costs deferred during the transition period will be amortized on a straight line basis over the subsequent 15 years. Effective December 1, 1993, the Company began recovering such costs based on the level of expense determined in accordance with the CPUC approach in the Fort St. Vrain Supplemental Settlement Agreement. On January 13, 1995, the CPUC approved the 1994 revision to the Supplemental Settlement Agreement, which accelerated the recovery of OPEB costs as required under SFAS 106 and approved other changes to certain ratemaking principles. The change in recovery was retroactive to January 1, 1994, and accordingly, resulted in an increased OPEB expense.
The Company plans to file a FERC rate case in 1995 which will include a request for approval to recover all wholesale jurisdiction SFAS 106 costs. Effective January 1, 1993, Cheyenne began recovering SFAS 106 costs as approved by the WPSC. The Company and Cheyenne intend to fund this plan based on the amounts reflected in cost-of-service, consistent with the rate orders.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Significant assumptions used in determining net periodic postretirement benefit cost were:
The OPEB expense on a pay-as-you-go basis was $9.1 million for 1992.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
A comparison of the actuarially computed benefit obligations and plan assets at December 31, 1994 and 1993 is presented in the following table. Plan assets are stated at fair value and are comprised primarily of corporate debt and equity securities, a real estate fund, government securities and other short-term investments held either directly or in commingled funds.
Significant assumptions used in determining the accumulated postretirement benefit obligation were:
The assumed health care cost trend rate for 1994 is 11.5%, decreasing to 6.0% in 0.5% annual increments. A 1% increase in the assumed health care cost trend will increase the estimated total accumulated benefit obligation by $35.8 million, and the service and interest cost components of net periodic postretirement benefit costs by $4.6 million.
Postemployment benefits
The Company and its subsidiaries adopted SFAS 112 on January 1, 1994, the effective date of the statement. SFAS 112 establishes the accounting standards for employers who provide benefits to former or inactive employees after employment but before retirement (postemployment benefits). The Company has recorded a $21 million regulatory asset (see
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 1) and a corresponding liability on the consolidated balance sheet, assuming an 8% discount rate. The Company believes it is probable that it will receive regulatory approvals to recover these costs in future rates.
Incentive compensation
The Omnibus Incentive Plan provides for annual and long-term incentive awards for officers and management employees. One million shares of common stock have been authorized for awards under the Plan as it allows for the issuance of stock options and/or restricted shares. The stock options are issued at the fair market value of the Company's common stock at the date of issue and vest over a three-year period. Cash and restricted stock awards were made under the Omnibus Incentive Plan for calendar years 1994 and 1993. Additionally, options were granted to eligible employees for these same years.
The Employee Incentive Plan provides for cash awards to all employees based on the achievement of corporate goals. Performance goals were met in 1994 and 1993.
The expenses accrued under both incentive plans totaled approximately $6.0 million in 1994 and $5.2 million in 1993.
11. Financial Instruments
Fair value of financial instruments
The following table presents the carrying amounts and fair values of the Company's significant financial instruments at December 31, 1994 and 1993. The carrying amount of all other financial instruments approximates fair value. SFAS 107 defines the fair value of a financial instrument as the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale.
The fair value of the debt and equity securities included in Investments, at cost is estimated based on quoted market prices for the same or similar investments and are classified as held-to-maturity. The unrealized holding gains and losses for these debt and equity securities are not significant.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The estimated fair values of preferred stock subject to mandatory redemption and long-term debt are based on quoted market prices of the same or similar instruments. Since the Company and Cheyenne are subject to regulation, any gains or losses related to the difference between the carrying amount and the fair value of these financial instruments would not be realized by the Company's shareholders.
Off-balance-sheet financial instrument
In accordance with NRC decommissioning funding requirements for nuclear power reactors, the Company has obtained a $66 million irrevocable letter of credit which bears a market interest rate. The NRC is the beneficiary of this letter of credit. At December 31, 1994 and 1993, no amounts were outstanding under this letter of credit. In general, such letter of credit may be exercised by the NRC in the event the Company is in default of its performance obligations under the decommissioning plan.
Concentration of credit risk - accounts receivable
No individual customer or group of customers engaged in similar activities represents a material concentration of credit risk to the Company and its subsidiaries.
12. Income Tax Expense
The provisions for income tax for the years ended December 31, 1994, 1993 and 1992 consist of the following:
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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
normalization method of accounting for income taxes as provided for in a recent rate order from the CPUC.
A reconciliation of the statutory U.S. income tax rates to the effective tax rates is as follows:
The Company and its subsidiaries adopted SFAS 109 on January 1, 1993. The impact of adoption was not material to the consolidated results of operations and, therefore, has not been reflected as the cumulative effect of a change in accounting principle.
The Company and its regulated subsidiaries have historically provided for deferred income taxes to the extent allowed by their regulatory agencies whereby deferred taxes were not provided on all differences between financial statement and taxable income (the flow- through method). To give effect to temporary differences for which deferred taxes were not previously required to be provided, a regulatory asset was recognized. The regulatory asset represents temporary differences primarily associated with prior flow-through amounts and the equity component of allowance for funds used during construction, net of temporary differences related to unamortized investment tax credits and excess deferred income taxes that have resulted from historical reductions in tax rates (see Note 1). During 1993, the Federal statutory income tax rate was raised from 34% to 35%, retroactive to January 1, 1993. The impact of this tax rate change on the Company was to increase the net deferred income tax liability by $16.8 million, of which $16.7 million increased the regulatory asset related to income taxes.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Effective December 1, 1993, pursuant to a CPUC order, the Company adopted full income tax normalization for rate regulatory purposes with the regulatory tax asset being recovered over a thirteen year period. Effective January 1, 1993, Cheyenne began recovering SFAS 109 costs as approved by the WPSC.
The tax effects of significant temporary differences representing deferred tax liabilities and assets as of December 31, 1994 and 1993 are as follows:
As of December 31, 1994 the Company has cumulative AMT carryforwards of approximately $12.7 million. A valuation allowance has not been recorded as the Company expects that all deferred income tax assets will be realized in the future.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
13. Segments of Business
Segment information for the year ended December 31, 1994 is as follows:
Segment information for the year ended December 31, 1993 is as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Segment information for the year ended December 31, 1992 is as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Concluded)
14. Quarterly Financial Data (Unaudited)
The following summarized quarterly information for 1994 and 1993 is unaudited, but includes all adjustments (consisting only of normal recurring accruals) which the Company considers necessary for a fair presentation of the results for the periods. Information for any one quarterly period is not necessarily indicative of the results which may be expected for a twelve month period due to seasonal and other factors.
Item 9.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Does not apply.
PART III
Item 10.



Item 10. Directors and Executive Officers of the Registrant
Information concerning the directors of the registrant is contained under ELECTION OF DIRECTORS in the registrant's 1995 Proxy Statement, which information is incorporated herein by reference.
Executive Officers (at December 31, 1994 except as noted):
Each of the above executive officers, except Mr. Brunetti and Ms. Smith, has been employed by the Company and/or its subsidiaries for more than five years in executive or management positions. Prior to election to the positions shown above and since January 1, 1990:
Mr. Hock has been Chief Operating Officer and President;
Mr. Brunetti has been President and Chief Executive Officer of Management Systems International from June 1991 through July 1994 and Executive Vice President of Florida Power & Light Company from 1987 through May 1991;
Mr. Kelly has been Vice President, Financial Services, Principal Accounting Officer and Senior Vice President, Finance and Administration;
Ms. Smith has been Vice President and General Counsel for South Carolina Electric and Gas Company from May 1992 through December 1994 and Vice President, Regulatory Affairs and Purchasing from 1988 through May 1992;
Mr. Crawford has been Vice President, Nuclear Operations and Vice President, Electric Production;
Mr. King has been Manager, Denver Metro Region; Vice President, Regional Customer Operations and Vice President, Metropolitan Customer Operations;
Mr. McLaughlin has been Vice President, Marketing, Customer Services and Support Services;
Mr. Sargent has been Executive Assistant to Chairman, President and Chief Executive Officer and Vice President, Finance, Planning and Communication and Treasurer;
Mr. Shaffer has been President, Cheyenne Light, Fuel and Power Company and Vice President, Division Customer Operations;
Ms. Taylor has been Vice President, Human Resources and Vice President Administrative Services.
There are no family relationships between executive officers or directors of the Company. There are no arrangements or understandings between the executive officers individually and any other person with reference to their being selected as officers. All executive officers are elected annually by the Board of Directors.
Item 11.

Item 11. Executive Compensation
Information concerning executive compensation is contained under COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS in the registrant's 1995 Proxy Statement, which information is incorporated herein by reference.
Item 12.

Item 12. Security Ownership of Certain Beneficial Owners and Management
Information concerning the security ownership of the directors and officers of the registrant is contained under ELECTION OF DIRECTORS in the registrant's 1995 Proxy Statement, which information is incorporated herein by reference.
Item 13.

Item 13. Certain Relationships and Related Transactions
Information concerning relationships and related transactions of the directors and officers of the registrant is contained under CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS in the registrant's 1995 Proxy Statement, which information is incorporated herein by reference.
PART IV
Item 14.

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) Financial Statements, Financial Statement Schedules, and Exhibits. Page 1. Financial Statements: Report of Independent Public Accountants . . . . . . . . . . . . . . 32
Consolidated Balance Sheets, December 31, 1994 and 1993 . . . . . . 33
Consolidated Statements of Income for each of the three years in the period ended December 31, 1994 . . . . . . . . . 35
Consolidated Statements of Shareholders' Equity for each of the three years in the period ended December 31, 1994 . . . 36
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 1994 . . . . . . . . . 37
Notes to Consolidated Financial Statements . . . . . . . . . . . . . 38
2. Financial Statement Schedules: II Valuation and Qualifying Accounts and Reserves (Consolidated) for each of the three years in the period ended December 31, 1994 . . . . . . . . . . . . . . . . . . . 66
All other schedules have been omitted since the required information is not present or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or the notes thereto.
Financial statements of several unconsolidated majority-owned subsidiaries are omitted since such subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary.
3. Exhibits: Exhibits are listed in the Exhibit Index . . . . . . . . . . . . . 77
The Exhibits include the management contracts and compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601 (10) (iii) of Regulation S-K.
(b) Reports on Form 8-K:
A report on Form 8-K, dated October 25, 1994, was filed on October 27, 1994. The items reported were Item 5. Other Events - Fort St. Vrain and Income Taxes and Item 7. Financial Statements and Exhibits, which presented information regarding third quarter earnings.
EXPERTS
The consolidated balance sheets of the Company and its subsidiaries as of December 31, 1994 and 1993, the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1994, and the related financial statement schedule, appearing in this Annual Report on Form 10-K, have been audited by Arthur Andersen LLP, independent public accountants, and the selected financial data for each of the five years in the period ended December 31, 1994, appearing in Item 6 of this Annual Report on Form 10-K, other than the ratios and percentages therein, have been derived from the consolidated financial statements audited by Arthur Andersen LLP, as set forth in their report appearing elsewhere herein. Reference is made to said report which includes an explanatory paragraph that describes uncertainties discussed in Note 2 to the consolidated financial statements relating to the Company's Fort St. Vrain Nuclear Generating Station. The consolidated financial statements, the related financial statement schedule and the selected financial data appearing in Item 6 other than the ratios and percentages therein, which are included in this Annual Report on Form 10-K, are included herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said reports.
EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by reference of our report included in this Form 10-K, into the Company's previously filed Registration Statement (Form S-3, File No. 33-42442) pertaining to the Automatic Dividend Reinvestment and Common Stock Purchase Plan; the Company's Registration Statement (Form S-3, File No. 33-37431), as amended on December 4, 1990, pertaining to the shelf registration of the Company's First Mortgage Bonds; the Company's Registration Statement (Form S-8, File No. 33-55432) pertaining to the Omnibus Incentive Plan; the Company's Registration Statement (Form S-3, File No. 33-51167) pertaining to the shelf registration of the Company's First Collateral Trust Bonds and the Company's Registration Statement (Form S-3, File No. 33-54877) pertaining to the shelf registration of the Company's First Collateral Trust Bonds and Cumulative Preferred Stock and to all references to our Firm included in this Form 10-K.
ARTHUR ANDERSEN LLP
Denver, Colorado February 27, 1995
EXHIBIT 24 POWER OF ATTORNEY
Each director and/or officer of Public Service Company of Colorado whose signature appears herein hereby appoints D. D. Hock and R. C. Kelly, and each of them severally, as his or her attorney-in-fact to sign in his or her name and behalf, in any and all capacities stated herein, and to file with the Securities and Exchange Commission, any and all amendments to this Annual Report on Form 10-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Public Service Company of Colorado has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 28th day of February, 1995.
PUBLIC SERVICE COMPANY OF COLORADO
By /s/R.C. Kelly _________________________________ R. C. KELLY Senior Vice President, Finance, Treasurer and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Public Service Company of Colorado and in the capacities and on the date indicated.
EXHIBIT INDEX
3(a)* Restated Articles of Incorporation of the Registrant dated July 9, 1990 (10-K, 1990 - Exhibit 3(a)).
3(b)* By-laws dated November 30, 1992 (10-K, 1993 - Exhibit 3(b)).
4(a)(1)* Indenture, dated as of December 1, 1939, providing for the issuance of First Mortgage Bonds (Form 10 for 1946 Exhibit (B-1)).
4(a)(2)* Indentures supplemental to Indenture dated as of December 1, 1939:
4(b)(1)* Indenture, dated as of October 1, 1993, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, September 30, 1993 - Exhibit 4(a)).
4(b)(2)* Indenture supplemental to Indenture dated as of October 1, 1993:
4(c)* Rights Agreement dated as of February 26, 1991, between the Registrant and Mellon Bank, N.A. (Form 8-A, filed on March 1, 1991 - Exhibit 1).
10(a)(1)* Contract dated July 1, 1965 between the Registrant, United States Atomic Energy Commission and General Dynamics Corporation (Form S-7, File No. 2-24772 - Exhibit 4(g)).
10(a)(2)* Settlement Agreement dated June 27, 1979 between the Registrant and General Atomic Company (Form S-7, File No. 2- 66484 - Exhibit 5(a)(1)).
10(a)(3)* Services Agreement executed June 27, 1979 and effective as of January 1, 1979 between the Registrant and General Atomic Company (Form S-7, File No. 2-66484 - Exhibit 5(a)(3)).
10(b)* Agreement for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste dated June 24, 1983 between the Registrant and the United States Department of Energy (10-K, 1983 - Exhibit 10(b)(2)).
10(c)(1)* Amended and Restated Coal Supply Agreement entered into October 1, 1984 but made effective as of January 1, 1976 between the Registrant and Amax Inc. on behalf of its division, Amax Coal Company (10-K, 1984 - Exhibit 10(c)(1)).
10(c)(2)* First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective January 1, 1988 between the Registrant and Amax Coal Company (10-K, 1988 - Exhibit 10(c)(2).**
10(e)(2)*+ Supplemental Executive Retirement Plan for Key Management Employees, as amended and restated March 26, 1991 (10-K, 1991 - Exhibit 10(e)(2)).
10(e)(3)*+ Omnibus Incentive Plan (1992 Proxy Statement - Exhibit A).
10(e)(5)*+ Executive Savings Plan (10-K, 1991 - Exhibit 10(e)(5)).
10(e)(6)*+ Form of Key Executive Severance Agreement (10-K, 1991 - Exhibit 10(e)(6)).
10(f)(1)*+ Form of Director's Agreement (10-K, 1987 - Exhibit 10(f)(1)).
10(f)(2)*+ Form of Officer's Agreement (10-K, 1987 - Exhibit 10(f)(2)).
10(g)(1)*+ Employment Agreement dated April 8, 1994 between the Company and Mr. Delwin D. Hock (10-Q, March 31, 1994 - Exhibit 10).
10(g)(2)*+ Employment Agreement dated July 18, 1994 between the Company and Mr. Wayne H. Brunetti (10-Q, September 30, 1994 - Exhibit 10).
10(g)(3)+ Employment Agreement dated December 5, 1994 between the Company and Ms. Patricia T. Smith.
12(a) Computation of Ratio of Consolidated Earnings to Consolidated Fixed Charges is set forth at page 67 herein.
12(b) Computation of Ratio of Consolidated Earnings to Consolidated Combined Fixed Charges and Preferred Stock Dividends is set forth at page 68 herein.
21 Subsidiaries
23 The Consent of Arthur Andersen LLP is set forth at page 74 herein.
24 Power of Attorney is set forth at page 74 herein.
27 Financial Data Schedule UT _________________ * Previously filed as indicated and incorporated herein by reference. ** Confidential Treatment. + Management contracts of compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(10)(iii) of Regulation S-K.