ML20112E937

Annual Rept,1984

ML20112E937
Person / Time
Site:	Fort Saint Vrain
Issue date:	12/31/1984
From:	Gahm J PUBLIC SERVICE CO. OF COLORADO
To:	Boyd R Office of Nuclear Reactor Regulation
References
P-85090, NUDOCS 8503270268
Download: ML20112E937 (53)

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1 Corp 3 rate Purpsse

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P ublic Service Company o I

the business of providing reliable elec-tric, natural gas and steam services to approximately 75% of the state's three million-plus people, including 1.9 million people in the Denver metropolitan area.

We are an investor-owned utility, subject to government regulation. Using sound manage-I ment principles, we seek the maximum value from all available assets. In this way, we can fulfill e

our three most fundamental objectives: a solid, competitive financial condition that results in market appreciation for our shareholders; quality utility services at a cost customers can afford in the prevailing economic environment; a stable working environment for our employees and op-portunities for their personal career development.

We are a leader in the utility industry because of the success in meeting responsibilities to shareholders, customers, employees and the

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community. We face the future with a commit-Mf ment to continue to develop as a dynamic organ-g i

ization adaptable to change and confident of i

even greater success in the years ahead.

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Financial and Op@ rations Highlights Financlat 1984 1983

% Change Earnings Per Share

$2.55 51.86 37.1 Dividends Paid Per Share

$ 1.90

$ 1.82 4.4 Return on Average Common Shareholder Equity 15.0 %

11.2 %

33.9 Common Shareholder Equity - % of Capitalization (year-end) 44.1 %

41.5 %

6.3 Operating Revenues (000)

$ 1,802,024 51,628,641 10.6 Operating Expenses (000)

$ 1,591,704

$ 1,449,146 9.8 Net income (000)

$ 145,247 5 106,379 36.5 Capital Expenditures (000)

$ 196,551 5 195,485 0.5 Gross Plant Investment (000) 53,281,869

$3,118,249 5.2 Number of Employees 6,894 6,857 0.5 Common Stock Shareholders 73,702 73,556 0.2 Common Stock Shares Outstanding (000) 51,632 49,182 5.0 Operations Electric Revenues (000)

$ 999,628 8 853,743 17.1 Kilowatt 4 tour Sales (Millions) 17,005 15,654 8.6 Electric Customers 919,267 892,569 3.0 Gas Revenues (000) 5 790,068 8 761,629 3.7 Mcf Deliveries (000) 198,474 177,585 11.8 Gas Customers 771,532 744,348 3.7 EEE EM ptet a e IRH. i i

Earnings &

Year End Stock PWe Customer Growth-Sales Growth-j Dividends Per Share

& Dividend Yleid Electric and Gas Electric and Gas 5 Earnings Per Share a Common Stock Market Price-Ps W Electric Customer Growth Rate 5 Electricity Sales Growth Rate-Kwh m Dividends Paid Per Share E Q)mmon Stock Dividend Yield-Yld 5 Natural Gas Customer Growth Rate E Natural Gas Sales Growth Rate-Mcf E

$ 2.50 820/I4%

6%

15%

S 2.25 18/13 5

10 8

10 74 H 81 82 83 84 74 80 81 82 83 84 74 80 81 82 83 84 74 80 81 82 83 84

Year in Retrospect Earnings Reach Record liigh dividends will be paid in cash. The 5% discount on E Earnings per share in 1984 climbed to $2.55, a 3"%

reinvested dividends, preferred dividend reinvestment w.

increase over 1983. This is the highest level in and the optional cash payment feature have been

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Company history. Several developments contributed to eliminated from the plan. These changes were made to this performance: the better-than-average increase in ensure the continuing availability of qualifying new

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g.t ; b implementation of higher rates; the recovery in the Non-Regulated Businesses In Growth Plans E

rate of growth of energy sales exceeded expectations.

E Limited investments into non-regulated businesses

.1 The earnings improvement brought the return on c ntinue to be a component of our long-range corpor-g. g..;

o iity to 15%.

ate strategy. Through our subsidiary, Fuel Resources

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Energy Sales Rebound From Depressed 1983 Development Co. (Fuelco), we are investing in natural M

5 Electricity sales jumped 8.6% and naturai gas gas and oil exploration properties in a six-state area in deliveries increased 11.8% after a weak performance the Rocky Mountain region. Fuelco's gross revenues in I p.'ff. '

in 1983 These increases surpassed our projections 1984 amounted to $10.3 million, compared to $10.2 1[?.

f]{A 1NL' because of the near-record cold winter weather in million in 1983. Net income was 31.2 milhon, l-1983-1984 and the improved economic situation in our compared with a $1.2 million loss in 1983. The natural service territory. The 17.1 % increase in electricity gas sales volume was 2,478,593 Mcf and crude oil sales Gjh[:-

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sales to the industrial sector alone is one of the volume totaled 86,465 barrels. Fuelco had a working strongest indications that our major industrial interest in 341 wells at year end; 270 of these wells are c

customers are recovering from the effects of the producing.

]Q recession on their operations.

Real Estate Subsidiary Unveils Long-Term Plan (Y

New Rates To Raise Annual Revenues $60.6 Million E Bannock Center Corp announced a comprehensive

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E We were permitted by the Colorado Public Utilities long-term potential land-use plan for the future Ac u.

1 Commission (CPUC) to increase rates 4.2%, which development of prime property near downtown f.f, 7

[h._ he should raise our annual revenues by $60.6 million. We Denver We have extensive holdings in utility-related requested in late 1983 a rate increase of $123.2 properties and these operations already involve us

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million. The CPUC allowed us in December 1983 to deeply in the life of the communities we serve. The 7k?

put $43 million of that request into effect on an investment in commercial real estate is a natural 3: > U:;

interim basis. In May, the CPUC authorized an increase extension of the real estate aspects of our business.

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a of an additional $156 million.

Bannock Center offers an opportunity to provide NE7 "N

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b '.,%y Nuclear Plant Outage Ralses Refund Issue efforts to enhance the quality of its downtown area.

4 ~b h@ k 5 We charged 5-'.2 million against 1984 pre-tax income in anticipation of possible requirements to Colorado Establishes A Consumer Counsel

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make refunds to customers because the Fort St. Vrain E The Colorado Office of Consumer Counsel was Nuclear Generating Station did not meet CPUC oper-established by the State Legislature effective July 1, ating standards in 1983 and 1984. A refund cf 1984. Supervised by the Attorney General, the new

$ 591,000 was made to customers in May. No addi-agency will represent consumers in proceedings con-(q g r tional refunds will be made pending the outcome of ducted by the CPUC. The agency is funded through an Qf{.g.,

legal and regulatory proceedings.

assessment on the regulated utility companies.

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Annual Dividend Rate Increased to $1.92 Lehr Named To CPUC Seat E In March 1984 the Board of Directors approved E Ronald L. Lehr was confirmed by the Colorado a 4.3% increase in the quarterly dividend rate to Senate in March 1984 to serve on the CPUC the 48 cents per share, or $1.92 per share annually. We remainmg 10 months of the term of Daniel Muse who believe a consistent pattern of annual increases, resigned on Jannry 31,1984. The term expired declared at the same time each year, is important January 1985, and Lehr has been re-confirmed by 2'

to strengthen our competitive position in the Colorado Senate to serve a six-year term. Lehr is a capital markets.

Denver lawyer who has worked for the state's energy mnsenaWn oh he oth mmmMoners are Changes Made In Dividend Reinvestment Edythe S. Miller, chairwoman, and Andra 1. Schmidt.

E Several modifications in the Automatic Dividend Reinvestment Plan became effective January 1,1985.

Shareholder Meetings Attract 1,200 Guests The reinvestment of dividends on common shares will E More than 1,200 shareholders and members of the be limited to an annual total of $1.400 per shareholder financial community met personally with management account. This is the maximum amount permitted by during the 1984 series of regional meetings held in the dividend exclusion provision of the Economic five cities. Meetings for 1985 are listed on the survey Recovery Tax Act of 1981. Once the limit is reached.

card attached to the last page of this Annual Report 3

Manag: ment Czmm:ntary f

he principles by which we have managed the Company to a f

much-improved financial condition and to a strong 1

performance in 1984 form the cornerstone of our business plan for the next five years.

We faced a critical challenge in 1979 to turn ourselves away from the disruptions caused by an energy malaise and a stinging inflation rate. At that time, we set ambitious goals that enabled us to pinpoint problem areas, determine the level of financial strength desired and formulate precise programs for improvement. These goals provided the framework for the decisions and actions that put us on the road to financial recovery. They have led us to a point where now we can plan the future with programs for increased profitability.

Because the business of running a utility has become more complex, the quality of management as a gauge for measuring the merits of our Company as an investment is more important than ever before. A well-defined and clearly communicated set of basic

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objectives enables investors to evaluate our performance by standards other than historical results and track our progress and potential from year to year.

Two equally important fundamental principles underlie our entire management philosophy and strategy. The first is to provide customers with adequate and reliable service at the lowest cost possible. The second is to reach a highly competitive level of financial strength and profitability.

Because customers generally use less energy as prices in-crease, it is difficult to satisfy both of these principles. However, we believe a workable balance can be reached in serving company and customer alike by minimizing the cost of services and maximizing the use of our production facilities.

Effective cost-control innovations are part and parcel of our efforts to reduce the price of electric and gas service. Comprehensive measures at every level of the Company have held the line on all costs, especially non-fuel and non-capital expenses. We are putting the latest managerial and technological concepts to work for us and we are confident that we will be successful in this effort.

Economic activity in our service territory and the state's population during the next five years are projected to increase at a healthy rate. This growth will provide some cushion against future economic changes that could have an adverse affect on our business.

It is difficult to formulate a precise energy supply strategy because customers' energy usage habits are changing. This is particularly true in the non-residential sector as the essence of our economy shifts from mining, manufacturing and agriculture to high technology and service industries. Our stature as a regulated monopoly does not shield us from the competition of an increasing array of developing energy

- ma options in this changing business environment.

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i su Our goals and programs for 1985 continue to reflect the y

principles of constant attention to customer needs and maintaining

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financial integrity and profitability. Listed are some major programs:

E Natural gas will be marketed with a new emphasis. We will seek the M

opportunities offered by a changing gas industry now characterized by y

surplus supply, market competition and declining gas prices.

ji E Electricity will be marketed in a manner that emphasizes managing

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and limiting growth of the maximum demand on our system. We will 97 continue to combine our generating capabilities with available purchased power to achieve the best balance of supply and cost.

jj E Engineering and design work will continue on the second unit at M

Pawnee based on an in-service target date of 1991. This will assure us C

of adequate generating capability in the 1990s. However, construction will not begin until we are confident it can be completed without as detriment to the best interests of shareholders and customers.

E We are committed to returning the Fort St. Vrain Nuclear Gener-D resident and chief 1

ating Station to operaticaal status as soon as possible. We will oppose

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the CPUC-initiated regulations imposed against the plant in 1984.

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E We will continue to be aggressive in protecting our rights to serve Chd#"""" "I d'e s ard p

R T Person confer aa our existing territory. We will carefully evaluate opportunities for

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expanding the service territory

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E We are taking the necessary steps to ensure the renewal of our bolders held throughout h franchise to serve the city and county of Denver.

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compensate our employees. Our commitment i.M @m.j t M W

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goals depends on the skills and motivation of 2.?;g?.Ny&.-64"?M :en,

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Chief Executive Officer

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Financial Pcrformance We reached ur financial condition was stronger in 1984 than at any time record high in many years. We are meeting many of the financial goals 4

essemial to wr comiming effort to meet broader corporate 3

earnings in 1984 objectives. We are now in a position to view the rest of this decade and we believe with increased optimism. We believe this strong position holds the the quality of our potential for increased profitability.

earnings to be It i:, important in evaluating this success and our expectations among the best for the future that we consider not only management's efforts and the in the utility resulting financial statistics, but the intangible factors that influence our g

industry.

business. Our performance in 1984 is a case in point.

Earnings per share in 1984 were $2.55, highest in the Com-pany history. Several developments combined to produce this notable result. Electricity and gas sales in the 1984 first quarter improved dramatically from depressed levels of late 1983 and continued strong through the rest of the year. Weather played a big hand in that first-A quarter surge as Denver's winter temperatures were the second coldest in history. About 75% of our customers are in the Denver area.

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With lower con-Electricity sales for the year increased 8.6% and gas deliveries 4

struction were up 11.8%, reflecting weather conditions and the economic j

spending and a recovery being experienced in our service territory. Industrial cus-y tomers emerged from the lethargy of the recession. Electric and gas

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higher cash flow, sales to that sector alone jumped 17.1% and 6.2%, respectively. Sales

'I we have also benefitted from the 3% rate of growth in our electric customer i

strengthened our base, and a 3.7% increase in gas customers.

I balance sheet We were authorized by the Colorado Public Utilities Commis-a and improved our sion (CPUC) to put $43 million of a $123.2 million rate increase request 1

capital structure.

Into effect on an interim basis in December 1983. In May, the CPUC al-

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I wed us an additional $17.6 million, bringing the total amount of the ji These improve-rate increase granted on an annual bass to s60.6 minion.

y ments give us the The 1984 earnings improvement resulted in an increased 4

flexibility to with-return on average equity to 15%. This is the highest level we've been k

stand future able to achieve in recent decades and it is our objective to remain in economic and the 14% range in 1985.

f financlai market We charged $7.2 million against pre-tax income contingent on upheavals.

possible refunds because the Fort St. Vrain Nuclear Generating Station g

did not meet operating standards established by the Colorado Public f

Utilities Commission. This amount includes $591,000 refunded to cus-p tomers in May because the plant did not operate in January and February 1983. Additional refunds related to the plant's operation from h

March 1983 to October 1984 are being considered by the CPUC.

1 In August, the CPUC issued an order requiring refunds based f

on revised operating standards beginning in November and continuing f

each month following that the plant does not meet these standards.

The refund for November and December amounts to $960,000.

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C orninunications that clearly define our objectit'es. phi-losophy and programs are essential in competing for int est-ment dollars in today's marketplace l' sing all appropriate media. tre prot ide our share-holders. thefinancial community an't cus-tomers trith timely.

contise and understand-able inJ'ormation. 7'his enables them to more fully et aluate our perfortnance and investment prospects

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Financial Performance 1

Ce serve a We requested and received in Denver District Court a stay of that order while the court reviews the case, but we are required to escrow gr0 Wing service the refund amounts.

territory and that Earnings in 1985 may not reach the record high of $2.55 per translates into share recorded in 1984. Winter temperatures may not be as severe as increased the record cold temperatures of a year ago. There will be further revenues and charges made against net income in connection with the operating dif-lnC0me.

ficulties at Fort St. Vrain.

The quality of our earnings is important in maintaining sound credit ratings. We are now rated a strong single A and our immediate objective is to move up to a double A. The double A rating will put us in a stronger position if we begin building a second unit at Pawnee.

Ce do not expect This stronger credit rating will enable us to withstand the effects of 13 seek financing possible adverse economic conditions on our business and maintain the access to capital markets needed to complete our construction for ConstruCil0n program without undue delay.

purposes during Two important measures of earnings quality are the effective the next Couple income tax rate and pre-tax coverage of interest expense. Our effective of years because income tax rate was up to 49% in 1984. The pre-tax coverage ratio Of Our str0ng was 4.35 times. Our objective over the long-term is to maintain a ratio Cash position.

of 3.5 times or higher.

Our capitalization ratios have improved steadily during our fi-nancial resurgence. Our level of debt as a percentage of capitalization is 44.4%. Our objective is to keep debt at 45% or less of capitalization.

Our common stock equity ratio was 44.1% at year end. Our objective is to reach about 45%. We review our capital structure objectives regularly in light of the most current economic and financial conditions. The current objectives should enable us to finance our construction without straining the financial integrity we have achieved.

The steady reduction since 1980 in spending for construction projects is a major reason for our strong financial condition. Spending in 1984 was $196.6 million. This amount represents 9.7% of capital-ization. Our objective is to hold spending on average to 12% of capitalization.

Our objective is to We 8enerated internally from our operations $168.1 million in 1984, or 90% of construction spending. We expect to stay well above m'intain a Con-our long-term objective of 50% in 1985. We do not anticipate the sistent pattern of need to seek financing for construction purposes in 1985 or 1986.

Increasing the consistency has been the key element with respect to our dividend every dividend policy. In March 1984 the Board of Directors increased the year.

annual dividend rate to $1.92 from $1.84. Our objective is a consistent pattern of increasing the dividend every year and intend to make the amount of the increase no less than that of the previous year.

f he tight controls

.A on construction expenditures during the past fit e years hat e strengthened ourfi-nancial condition. Yet, tre continue to meet the grotting energy needs of our customers by maxi-mizing the efficiency of our electric system gen-erating and transmis-sion facilities.

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i D PSCO Financial Charts O Industry Average Pretax Coverage of Return on Equity

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This is the measure that Interest Expenses tells common share-A measure of protection

,4 4,,

holders how well our or safety of the interest Company is doing with expenses paid to bond-3,,

' its shareholders' invest-holders by our Company for the money bor-ment. It is the primary 3

indicator of profitability rowed it is like a home-for shareholders and owner who must have 2.s measures the actual monthly income so average return earned many times his month!y 2.o=

for each of the years niortgage payments on indicated.

his home. Our objective is to have annual income 74 80 88 82 83 84 74 so si s2 s3 84 before taxes at least 3.5 times our annual interest payments.

Common Equity Ratto 45%

Internal Funds 90 %

The amount of share-Generation holder investment as a 42 The amount of funds 75 percent of the total 52 obtained from Company billion invested in our 39 operations available for 60 Company. Our objective spending on new or is to have about 45% of 36 existing utility plant.

45 total investment or capi-Our objective is for at talization in shareholder 33

~

least 50% of our annual 30 equity.

spending to come from 30 s operations. The higher Iss this percentage, the less financing we must do.

74 so at 82 53 84 74 80 et s2 83 84 Debt Ratio AFDC*-% of Earnings

6_o_s, 54 "

The proportion of The proportion of 50 52 earnings derived from borrowed funds as com-pared with the total $2 certain non-cash addi-billion invested in our tiens to income based 40 50 Company. Our objective on the composite cost of funds used to finance 30 is to hold debt to about 48 construction work in 45% of totalinvestment.

46 progress. The lower this 20 ratio the higher the qual-ity of reported earnings 10 %

44 %

per share.

' Allowance for Funds Used 74 80 st 82 83 84 During Construction 74 so st 82 s3 84

yg_b+M Q.Y. $ ' ~ :; b.). 65-. ~ l D.

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Tax Rate j

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taxes as a % of pretax electricity has been rela-y

-i, and State statutory rate l

years and is well below

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income. A full Federal 3,

I tively stable in recent

' [!l' (48.7%) more fully the average for the in-

7.. -

deferred taxes resulting reason is our low cost of

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20 recognizes current and l

dustry. The primary

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primarily from acceler.

coal and that it repre-ated depreciation of sents over 90% of the 1,i 8"

plant assets.

fuel we use.

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of Capitalization 14 liour Usage

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The portion of total in.

This measures the F -

W vestment (capitalization) 13 amount of electricity

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(.' s in our Company being used by our residential 4

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spent annually on new n2 customers every year.

6mo di;;l or existing utility plant.

Colorado's c!! mate t. ;

" 5.:

Our objective is not to reduces the need for air som

(

spend more than 12% of

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conditioning. Natural gas

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our current $2 billien nos U ;'

capitalization in one year.

is the primary heating 4mo fuel, further reducing

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residential electric use.

F Ml As a result, electric 74 so si s3 s4 b.;'ig'.

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.;o a i s2 s3 s4 consumption is below f4;,.

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The proportion of our Residential Electric 6"

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coal. Coal is abundant dential electric utility bill M?%

s..;

and the least expensive 70 is well below the na-

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fuel for our Company. It tional average. With Gn is also low in sulfur.

lower fuels and oper-3m

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believe utility bills will szm

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moderate from the rapid M.

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l Electric Operattns t

Long-term pur-dequate. Economical. Reliable. These words long have described our standards for providing electric energy.

ch: sed power J

Demand and usage of that energv is changing. A volatile contracts supple-economy breeds uncertainty about how electricity will be used in the ment Our Strong future. Nevertheless, our commitment to adequate, economical and electric gener-reliable electric energy not only remained steadfast in 1984 but is the allen p0Sillon and driving force behind corporate strategy for the future, give us the oppor-Adequate. Our supply position was excellent again in 1984.

tunity to further During the summer peak load periods, our Company's net generating strengthen our capacity was 3,035 megawatts. In addition, we had firm contracts to purchase 755 megawatts of capacity from other utilities. The maximum financial position demand on our system reached 2,968 megawatts on July 19, which is exactly the same as the 1983 peak which came in December 1983. Our taking the con-capability, including purchases, at the time of the 1984 peak was 3,790 StrucilOn Of 8 megawatts or 27.7% above the amount of electricity demanded. Based new generating on our installed generating capability, firm purchased power contracts unit.

with other utilities anel projected maximum demand, we expect a reserve margin in 1985 of about 28%.

Economical. We controlled costs to our customers in three significant ways in 1984. First, we substituted economically priced purchased power, when available, for power generated from our least-efficient generating units. The savings appeared in the Electric Cost Adjustment on our customers' bills which reflects the cost of power we pass on to them on a dollar-for-dollar basis.

Second, we continued to reap the benefits of using coal as a primary fuel in generating electricity. The supply of coal in our area is abundant. It is the least expensive fuel that we can purchase for generation. Coal costs in 1984 were $1.28 per million British Thermal Units (Btu). The utility industry on average pays $1.72 per million Btu.

Third, we continued to offer customers a broad range of information programs about using electricity in the most efficient and cost-effective ways.

Reliable. We combine several major strategies in developing energy sources that will strengthen aur system reliability. As part of our overall program to expand and maximize the output of existing facilities, we completed improvements to a unit at our Valmont Plant and brought the second unit at our Zuni Station in downtown Denver back into service in 1984. The newly activated capacity offset to some degree the unavailability of the Fort St. Vrain Nuclear Generating Station which was shut down for maintenance and repairs.

The system average generating unit availability factor in 1984 was 85.6%. Our four largest generating units alone, located at the Pawnee, Cherokee and Comanche plants, accounted for 52.9% of total system electric energy requirements and had a composite availability factor of 87.2%. Pawnee, the Company's largest generating unit, had a

RE

!!=i ur strategy to keep E

ahead of the

{

grou'th in demandfor E'

electric energy rests in U

the engineering and W

planningfunction. We K-are continually con-g sidering the needfor neu' distribution facil-W i";7(M,-

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Q; design and engineering

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ating unit at the site of

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El:ctric Op rati ns Our installed relatively trouble-free year in 1984. The plant was available at full generallng capacity nearly 96% of the time. This is an outstanding reliability rec rd for a facility of its size.

Capabilh and We continue to consider additional transmission lines to tap firm purchased potential pools of surplus power from nearby utilities. New lines, power Contracts together with the upgrading of existing lines, will enable us to transmit give us a pro-enough power through our system to meet all customer demands.

jected reserve Our objectives and approach to adequate, economical and margin Of ab0ut reliable electric service thrcughout the rest of the decade have taken n new dimensions. We have put more emphasis on assessing energy 28% in 1985.

trends that will determine consumption. We must identify the driving forces behind customer usage, isolate their effects and determine which factors are likely to be important. The more accurately we project demand, the better we can balance system supply and the needs of customers.

Our service territory is growing. Growth is important to our success because it enables us to utilize our facilities in a cost-effective manner, resulting in increased sales.

Electric customer growth is forecasted at an annual average E3 hav0 deferred rate f 3% through the 1980s. Electricity sales are anticipated to the comPletl0n Of increase at an annual rate of 3% to 4% during the same period. The a seCOnd 500 maximum demand on our system at any given time is the basis on megawatt unit at which we determine how much capability is needed. We estimate that Our Pawnee Plant maximum demand will increase on the average about 3% each year.

site until 1991. We Our strategy to keep ahead of this growth includes the pre-have already liminary planning of an additional generating unit. We have long-term Breements with neighboring utilities to purchase, at economical c:mpleted a large prices, enough electric energy to supplement our strong generating gg position. We are aware that the current power surplus is temporary.

engineering and For the time being, this surplus situation gives us the option of design w0rk and deferring another generating unit while our financial ability to support have Ordered such construction becomes stronger.

major equipment.

We have deferred the date of commercial operation of a second 500-megawatt unit at our Pawnee plant site until 1991. About 43% of the engineering and design work on the unit is completed and major equipment has been ordered. This activity will continue at an appropriate level so that we will have at least 50% of the engineering and design completed prior to the start of construction.

Emphasis throughout the 1980s will continue to be placed on maximizing the efficiency of present generating units, maintaining a high availability factor, load management, controlling costs through effective fuel management and taking advantage of economical pur-chased power. This will give us a competitive position that will encourage our customers to continue to choose electricity as a primary energy source.

T be relianility of our electric systern is greatly enhanced by the huge map board tchich enables our operators to monitor electric load patterns and pinpoint immediately areas u'here emergency out-ages occur. This so-phisticated system brings the entire electric distribution system into focus at a glance.

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Natural Gas Operati:ns I

I The per unit price he era of phased deregulation, legislated in 1978 and Of natural gas 10 Completed January 1,1985, is changing the environment in which we operate our natural gas business. Prior to 1978 the Our customers per unit price of natural gas to consumers was artificially low. Phased has decreased deregulation initially brought about sharp increases in the price of gas during the past and consumers responded by conserving more or switching to tWO V8ars be-alternate fuels. Phased deregulation also spurred a significant increase cause Of the in drilling and exploration activity. Consequently, the gas industry has industry's surplus been moving from an economy of scarcity to an economy of surplus.

supply situatiop, This surplus has brought about new market disciplines and a competitive situation that has enabled prices to decrease during the past two years. Our major supplier, Colorado Interstate Gas Co. (CIG),

cut its rates 3.1% in 1984 and a total of 14% since October 1982. CIG has capitalized on the surplus situation by renegotiating many of the contracts through which it buys gas from producers.

We also have taken advantage of the buyers' market by Natural gas is making short-term purchases at competitive prices. We believe that with the deregulation of gas prices now complete we will be able to Off0CllV8ly mar-pr vide our customers with some further modest cost savings in 1985.

katable as an We will shift marketing emphasis in 1985 to pursue opportun-On8rgy sOurC8 ities offered by the industry's new environment. Natural gas is effec-because it is high tively marketable as an energy source because it is high in energy value, in Snergy Value, reliable, efficient and clean-burning. With more stable prices, we be-F8ll8ble, Cl8an-lieve customers in our service territory will use more gas for heating burning and and other purposes during the next five years. Furthermore, we are in a Sfficient.

better position to compete for interruptible industrial customers who have been considering using cheaper alternative fuels and purchasing gas on the open m.trket.

The number of gas customers is expected to increase at an annual average rate of about 3% through the remainder of the 1980s.

Gas sales during this period are forecasted to increase about 2%. Our gas marketing effort will add impetus to this growth.

Our gas distribution systeir is extensive and capable of handling maximum customer demand. In 1984, we delivered 198.5 billion cubic feet of gas. That is 11.8% more than in 1983. We have the capability to store 11.7 billion cubic feet of gas at any given time, providing a more-than-adequate supply to meet a surge in demand caused by cold weather. This was evident during the record-setting winter of 1983-1984, when we were able to deliver all the gas needed by customers during an extended period of sub-zero temperatures.

16

H and-held meter reading computers E

trere implemented in n

I984 to improt'e the

=

ot'erall efficiency in reading both electric

=

and gas meters and pro-t'iding long-range cost sat ings to customers.

We are continually

)

et'aluating the latest

( ',

W technological det'elop-ments and other initi-

,q attt es in reaching our Y

i fundamental objectit'es of running our business f

as efficiently as possible W

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Natural Gas Operations Through our sub.

The strategies we develop in response to the evolving era in sidiary, WestGas, the natural gas industry encompasses our subsidiary company Western Gas Supply Co. (WestGas), the new name for Western Slope Gas Com-We Will con-pany. The company name was changed to reflect WestGas' expanding tinually search operations and to show that WestGas operates throughout Colorado the gas market and not only on the state's Western Slope.

for the most WestGas operates as a pipeline company that negotiates and economlCal buys gas at favorable prices from producers and transports it to Public prices.

Service Company and other large users. Nearly 70% of its sales are to Public Service Company. WestGas also maintains the large storage units that help to hold down costs and further increase the reliability of our service. WestGas' total revenucs in 1984 amounted to $209 million, 31 % of which were from customers other than Public Service Company.

During the last half of the 1980s, WestGas will expand its role in our gas supply operations. WestGas will search through the breadth of the market for gas that can be purchased at the most econo.nical prices. It is also studying the feasibility of bringing gas to new residential markets, carefully following industrial development and remaining alert to unusual opportunities for growth, such as wholesale gas sales to other utilities or to small towns.

With today's surplus condition, our emphasis will be on pro-We Will shift our viding gas to the customer at the lowest possible price. The surplus marketing empha-supply situation is expected to continue for the foreseeable future. The sis in 1985 and successful realization of our basic objectives in the coming year will the years ahead prepare us adequately to bring the advantages of natural gas to our

=

to focus on the customers and to further strengthen our position in this business.

advantages of natural gas as an efficient energy source and the fact that it is available at a competitive price.

18

b O ur subsidiary U"estern Gas Sup-f ply Company, renarned

[

u ~estGas this past year.

operates as an Intra-

[

state gas pipeline corn-f pany that purchases gas Jrom produt ers and f

transports it to Public M

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hert ice Company d*1d 1?!O?

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other.'arge userIs y

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of our extensive gas distribtllion system u'hich puts us in a strong posttion to shifl g

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our marketing emphasis

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Sharehdder Information The Company's common stock (55 par value) is listed A DRP statement, reflecting the transaction occurring for trading on the New York, Midwest and Pacific on each investment date, is mailed to the participants Stock Exchanges under the ticker symbol "PSR."

as soon as practicable after such investment date.

Quotes may be obtained in daily newspapers where Effective January 1,1985 the DRP was modified,

=

the common stock is listed as "PSvCol" in the New eliminating the following. the 5% discount on York Stock Exchange listing tabic.

reinvested dividends; participation with preferred Year Total Volume Average Daily Volume dividends; and optional cash payments. In addition, the reinvestment of dividends on common stock has been limited to $1,500 per year. Complete details are I

1982 21,198,000 83,787 contained in the DRP prospectus.

A prospectus describing the DRP and enrollment Common Shares Shareholders information can be obtained from the Shareholder Year Outstanding Common Preferred Services Department by writing or by calling 1984 51,632,451 73,702 5,875 1983 49,182,153 73,556 6,009 Dividend Reinvestment Plan Statistics 1982 47,019,528 70,710 6,128 shareholder

% of shares

% of Three series of cumulative preferred stock are actively Year Participants Total Participating Total traded (see chart below). All other series are not 1984 35,092 48.0 18.898,244 37.1 actively traded and market prices are not published.

]3 y

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l 3

Series Where Listed Funds shares Average 4 % % ($100 par value)

American Stock Exchange Year Collected Issued rrtec 7.15% ($ 100 par value)

New York Stock Exchange 1984 841,044,000 2,450,298 816.75 8.40% ($25 par value)

New York S:ock Exchange 1983 832,869,000 1,990,151 816.51 g_j ?

1982 822,933,000 1,611,582 814.23 Where to Buy Stock E The Company's common and preferred stock may Open Market Plan

'2

Y' l be purchased through a brokerage firm. A shareholder E At current participation levels the Company's DRP dD of record holding the Company's common stock in does not have sufficient shares authorized but unissued MC his/her name may purchase common stock with no to complete 1985. Therefore, the Company wul con-

.Df service charge or commission through the Company's sider an open market dividend reinvestment plan to bN Automatic Dividend Reinvestment and Common Stock replace the current DRP when the authorized shares are exhausted.

Purchase Plan (the "DRP")(see section entitled

" Dividend Reinvestment Plan" for details).

The specifics of an open market type dividend re-investment plan have not yet been determined. liow-Where to Sell Stock ever, continuing with the Company's policy of keeping E The Company's common or preferred stock held in our shareholders informed, the operational procedms certificate form may be sold through a brokerage firm.

will be sent to all r,hareho'ders as quickly as the Shares held in the DRP by the Company for a information becomes available.

participant must be ordered out in certificate form by the participant and sold through a brokerage firm.

Transfer Agents E The Company is the principal transfer agent for its Dividend Reinvestment Plan common and preferred stock. Central Bank of Denver E The Company's DRP provides common share-is the principal registrar.

holders with an economical and convenient method For additional convenience in transferring stock, for purchasing additional shares of the Company's Morgan Guaranty Trust Company of New York is common stock without the payment of brokerage retained as co-transfer agent and co-registrar. Effective commissions or service charges.

March 1,1985 the services of Bank of America NTSA Dividends reinvested through the DRP are used to as co. transfer agent and co-registrar were discontinued.

purchase common stock at the average of the high and While Bank of America has served as co-transfer agent low sale prices of the common stock as reported on and co-registrar for many years, steadily declining the consolidated tape on each investment date. Com-volumes of certificates transferred on the West Coast mon shareholders whose shares are registered in make the continuation of services there uneconomical.

names other than their own may participate in the DRP flow to Transfer Stock for the reinvestment of dividends, provided the broker or fiduciary who holds such stock in nominee name is II A transfer of stock is required whenever the willing to participate in the DRP.

registration of a stock certificate is changed. A change in registration generally occurs when stock held in other than "ncmince or sueet name" is sold. Changes of 20

_. ~

name, co-owners, tenancy, etc. also require a transfer.

on its preferred stock on the first of March, June, A transfer can be accomplished by properly filling in September, and December of each year.

the stock assignment form on the reverse side of the Dividends paid on stock held in " street name" are stock certificate and endorsing the assignment form paid to the holder of record, generally a brokerage exactly as the registration is shown on the face of the firm or bank nominee. The dividends are then redistri-certificate. The signature (s) of the transferor must be buted to beneficial owners by the brokerage firm or guaranteed either by a commercial bank or a brokerage bank in accordance with the beneficial owners' firm that is a member of one of the major stock instructions.

exchanges. The certificate with the properly completed Shareholders of record receive dividends directly assignment can then be sent to the Company or to the from the Company unless such shareholder has elected co-agent for transfer. It is recommended that to reinvest dividends through the Company's DRP.

certificates be sent registered or certified mall.

Dividends Not Received Stock Registration 5 Dividend checks are mailed so as to reach 5 The purchaser has the choice of having the stock shareholders on the dividend payment date.

delivered or leaving it with the broker. Stock left with Shareholders who do not receive their dividend check the broker is generally held in the brokerage firm's on the appropriate dividend payment date should name and referred to as " street name" stock. The pur-contact the Shareholder Services Department.

chaser is generally referred to as the beneficial owner.

Ilowever, it is suggested that such contact be delayed A purchaser who elects to take physical possession about 7 days after the dividend payment date to allow of the stock receives a certificate (s) representing the for any delay in mail delivery.

number of shares purchased. The stock is registered on The accompanying tables show the ranges of closing the Company's books in the name of the purchaser c mmon and preferred st ek prices as shown on the who becomes a shareholder of record.

consolidated tape and divideads paid on common stock by Safckeeping of Certificates quarter for 1984 and 1983.

W When stock certificates are received, it is recommended that the certificates be safeguarded by common stock 4th 3rd 2nd not placing them in a secure place such as a bank safety 1984 deposit box. A separate certificate record should be liigh 19%

lH%

IH%

IH%

maintained including each certificate number, purchase

'{ rade th date, date of issue, amount paid and the exact regis-Div. Declared

.48

.48

.48

.4s tration. The Company dc>es not safe keep certificates Div. Paid

.48

.4s

.4s

.46 for shareholders.

19n3 liigh 19 IH%

17%

17%

Lost or Stolen Certificates low 17%

16%

16%

16%

E If a stock certificate is lost or stolen, notification I.ast Trade 18%

17%

17%

17%

should be sent immediately to the Company so a Div. Declared

.46

.46

.46

.46 niv. paid

.46

.46

.46

.44 "stop" can be placed on the missing certificate. The letter should contain as much information as possible 3*pd,,,c, 4,,

3,,

describing the certificate; in particular, certificate number, date issued, and registration. Once a "stop" 4 % 5"l 9g4 g g

g g

33 has been placed on the missing certificate, an affidavit low 31%

30%

30%

33 will be sent which must be completed, signed, 19831bgh 36 36 38 37%

notarized and returned before a replacement certificate low 32 32 34 33-can 1,e issued. An irrevocable indemnitv hond for the 7,35 g 3,,ie, lost stock certificate it also required. The cost is about 1984 liigh

$9 59%

59%

60 2% of the market value of the missing certificate, low 53%

52%

51%

55 calculated at time the indemnity bond is issued.

19H3 liigh 60 62 63%

62 Information regarding lost or stolen certificates low 54 57%

SH%

58%

should be sent to Shareholder Services Department, n.40% series (s25)

(Room 160B), P.O. Ilox H40, Denver, CO 80201.

19H4 Ifigh IM%

17%

17%

lH%

low 16%

16%

16%

16 %

Dividends 19H3 liigh 19%

1H%

19 %

19 %

B Dividends on common stock, as declared by the Low 17 16%

is 17%

Iloard of Directors, are generally payable on the first day of February, May, August and November of each year, The Company pays regular quarterly dividends 21

Financial & Statistical Data 1984 1983 1982 1981 1980 1979 1974 Total Assets (millions) 82,862 2,716 2,607 2 422 2,205 2,000

$ 1,235 Common Equity (millions)

$ 894 821 785 736 656 555

$ 332 Preferred Stock (millions):

Subject to mandatory redemption at par 8

87 88 89 89 89 64 5

64 Not subject to mandatory redemption

$ 140 140 140 140 140 140

$ 105 I,ong-Term Debt (millions)

$ 883 886 891 866 840 767 8 577 Short-Term Borrowings (millions)*

21 44 54 64 26 65 25 Total Capitalization (millions) 82,025 1,979 1,959 1,895 1,751 1,591 81,103 Capitalization Ratlos - Year End Common equity 44.1 %

41.5 40.1 38.9 37.5 34.9 30.1 %

Preferred stock (incl. due within 1 yr.)

11.3 %

11.6 11.7 12.1 13.1 12.9 15.4 %

Long-term debt (incl. due within 1 yr.)

44.4 %

45.9 45.6 45.8 48.9 48.3 52.3 %

Notes payable and commercial paper 0.2 %

l.0 2.6 3.2 0.5 3.9 2.2 %

Gross Construction Expenditures (millions)

$ 196.6 195.5 230.0 256.7 262.6 320.8

$ 151.9

% of Total Capitalization 9.7 %

9.9 11.7 13.5 15.0 20.2 13.8 %

Funds Generated Internally (millions) 8168.1 132.6 145.0 106.7 84.6 55.7 3 41.2

% of Net Construction Expenditures 90.0 %

71.0 64.9 46.8 36.2 18.5 28.7 %

Rates of Return Earned:

Total capitalintion (Oper, income) 10.4 %

9.2 9.9 7.8 7.1 5.9 6.1 %

Avg. common equity (Net to common) 15.0 %

11.2 13.1 12.1 11.6 7.9 9.1 %

Pretax Coverage of Interest Expenses 4.35x 3.42 3.67 3.24 2.86 2.50 2.21 x Effective Income Tax Rate 49 %

47 47 40 38 33 12 %

Payout Ratio on Dividends Paid 74.5 %

97.0 80.2 84.3 83.3 118.5 73.6 %

Dividend Yleid - Year End 9.9%

9.9 10.1 11.8 11.2 12.0 9.9 %

Mat te ' Price Per Share nigli

$ 19%

19 17%

15 15%

17 %

$ 17%

Low

$ 16%

16%

13%

12 %

11%

12%

$ 9%

Year Efid Close

$ 19%

18%

17%

14 %

14 %

13%

$ 12%

Book Value Per Share

$ 17.31 16.70 16.69 16.39 16.40 17.18

$ 16.94 Common Stock Volume:

Daily Average -(000) 133.1 130.0 84.4 52.1 51.5 37.9 10.1 Annual - (000) 33,670 32,910 21,198 13,204 13,034 9,587 2,565 Number of Employees - Year-End 6,894 6,857 6.794 6,424 6,145 6,310 5,590 Financial A statistical Data This section includes information for the period IWl984 and The information contained on the followhg three pages is most the year 1974. This enables investors and analysts to compute frequently sought by insestors and mem'.,crs of the financial compound growth rates for the last five year and ten year periods.

community. A more comprehensive act of pertinent historical.

financial and statistical information is e ontained in a supplemental

• Includes debt due within one year, notes payable and commercial pubhcation to the Annual Reimrt. Tb: publication is entitled paper. and preferred stock subject to mandatory redemption within Financial & Statistical Review (or Factbook) and is available upon one year.

request by completing the card atta(hed to the back of the Annual Report.

22

Operating Revenu@s, income and Earnings Data Year Ended December 31, 1984 1983 1982 1981 1980 1979 1974 Operating Revenues:

stillions of Dollars.

Electric

$ 999.6 853.7 843.4 742.1 640.7 507.6 5224.2

% Change 17.1 %

1.2 13.7 15.8 26.2 20.4 18.3 %

Gas 790.1 761.6 732.3 982.4 502.9 410.5 134.9

% Change 3.7%

4.0 25.7 15.8 22.5 35.3 15.4 %

Other 12.3 13.3 14.3 11.6 12.0 8.4 3.2 Total Revenues 1,802.0 1,628.6 1,590.0 1,336.1 1,155.6 926.5 362.3

% Change 10.6 %

2.4 19.0 15.6 24.7 27.0 17.4 %

Operating Expenses:

Fuel used in generation 188.9 172.8 184.4 170.1 182.6 175.9 54.9 Purchased power 161.9 99.0 101.7 113.2 91.4 29.4 2.1 Gas purchased for resale 606.6 611.3 587.2 462.3 388.9 310.1 78.3 Total Energy Costs 957.4 883.1 873.3 745.6 662.9 515.4 135.3

% Change 8.4 %

1.1 17.1 12.5 28.6 41.2 31.2 %

% of Revenues 53.1 %

54.2 54.9 55.8 57.4 55.6 37.3 %

Payroll charged to operating expenses 183.1 174.4 153.3 125.7 119.1 105.0 58.7

% Change 5.0%

13.8 22.0 5.5 13.4 11.3 13.1 %

% of Revenues 10.2 %

10.7 9.6 9.4 10.3 11.3 16.2 %

Other operating expenses (ex. payroll) 84.3 86.3 73.6 67.0 49.0 57.9 11.1 Maintenance 72.5 64.1 58.4 49.7 46.6 37.1 17.0 Depreciation 96.9 91.6 86.4 73.5 61.5 55.9 36.4 Taxes (o:her than income taxes) 60.0 55.8 53.6 64.0 40.4 38.0 32.8

_ income taxes 137.5 93.8 103.2 67.9 52.2 26.8 5.4 Total Operating Expenses 1,591.7 1,449.1 1,401.8 1,193.4 1,031.7 836.1 296.7

% Change 9.8%

3.4 17.5 15.7 23.4 31.4 19.6 %

% of Revenues 88.3 %

89.0 88.2 89.3 89.3 90.2 81.9 %

Operating Income 210.3 179.5 188.2 142.7 123.9 90.4 65.6

% Change 17.2 %

(4.6) 31.9 15.2 37.2 (3.2) 8.4 %

% of Revenues 11.7 %

11.0 11.8 10.7 10.7 9.7 18.1 %

Other Income and Deductions 15.3 5.8 5.7 21.8 20.2 12.5 8.9 Interest Charges 80.3 78.9 77.4 63.7 59.1 47.1 36.1 Net Incomo 145.3 106.4 116.5 100.8 85.0 55.8 38.4

% Change 36.5 %

(8.7) 15.6 18.6 52.3 (3.3)

(8.6)%

% of Revenu.:s 8.1 %

6.5 7.3 7.5 7.4 6.0 10.6 %

Preferred Divistend Requirements 16.7 16.7 16.7 16.7 15.0 13.5 9.6 Earnings Available for Common Stock

$ 128.6 89.7 99.8 84.1 70.0 42.3 8 28.8

% Change 43.4 %

(10.1) 18.7 20.1 65.5 (4.3)

(18.6)%

% of Revenues 7.1 %

5.5 6.3 6.3 6.1 4.6 8.0 %

Earnings Per Average Share 52.55 1.86 2.17 1.97 1.92 1.35

$ 1.63_

Dividends Per $b.re:

Paid

$ 1.90 1N 1.74 1.66 1.60 II)0

$ 1.20 Decised

$ 1.92 1.v '

l.76 1.68 1.60 1.60

$ 1.20 Common Stock Shares Outstanding (000):

Average 50,440 48,135 45,948 42,728 36,412 31,225 17,657 51,632 49,182 47,020 44,896 39,990 32,326 19,607 Year-end Operating Revenues. Income and Earnings Data utilities and gas purchased for resale to customers are automatically Operating revenu s are derived from four basic sources: (1) cus-passed on to customers on a dollar for dollar basis, the increase or tomer growth, (2) customer consumption, (3) rate increases or decreaw in these costs are included in operating revenues. These decreases authorized by Federal and state regulatory authorities, and costs are subtotaled below in energy costs and can vary the growth (4) fuel cost adjustments. Desause incrcases or decreases in the costs rates of opcrating revenues from year to year.

for fuels used in electric generation, power purchased from other 23

Electric S:rvice Statistics 1984 1983 1982 1981 1980 1979 1974 Kilowatt-Hour Sales (millions) 17,005 15,654 15,433 15,473 15,194 14,659 10,602

% Change 8.6%

1.4 (0.3) 1.8 3.6 6.6 12.0 %

Customers (000) 919.3 892.6 865.0 846.1 820.5 794.5 640.8

% Change 3.0%

3.2 2.2 3.1 3.3 3.9 5.1 %

Avg. Annual Residential Kwh Usage 6,268 6,076 5,963 5,734 5,937 5,913 5,225

% Change 3.2 %

1.9 4.0 (3.4) 0.4 3.3 (2.9)%

Avg. Residential Revenue Per Kwh 6.95C 6.45 6.52 5.74 5.12 4.19 2.92 C

% Change 7.8 %

(1.1) 13.6 12.1 22.2 11.7 9.4 %

Average Annual Revenue Per Residential Customer 8 436 392 389 329 304 248 5 152

% Change 11.2 %

0.7 18.2 8.3 22.7 15.4 6.1 %

Net Effective Capability at Time of Peak-Megawatts 3,790 (s) 3,512 (w) 3,401 (s) 3,116 (s) 3,072 (s) 2,743 (s) 2,162 (w)

Net Firm System Peak Load (Mw) 2,968 2,968 2,892 2,820 2,776 2,642 1,924

% Change 2.6 2.6 1.6 5.1 3.2 9.2 %

Reserve Margin at Time of Peak 27.7 %

18.3 17.6 10.5 10.7 3.8 12.4 %

Generation Isy Class of Fuel:

Coal 97.9 %

93.4 94.0 85.3 76.1 79.2 61.2 %

Natural Gas 1.1%

0.9 1.4 8.4 17.8 17.6 36.1 %

Oil 0.1 %

0.4 0.3 0.3 0.8 1.8 2.7 %

Nuclear 0.9 %

5.3 4.3 6.0 5.3 1.4 Avg. Cost Per Unit of Fuel:

Coal - Ton

$23.81 23.87 22.95 21.84 18.81 16.60

$ 7.44 Natural Gas - Mcf

$ 3.62 4.07 3.81 3.12 2.68 2.00

$ 0.43 Oil - Barrel 532.63 27.35 38.01 39.96 26.37 17.19 513.40 Avg. Fuct Cost Per MMBTU S 1.30 1.23 1.23 1.22 1.29 1.08 3 0.47 (s) summer peak lud (w) winter peak load Natural Gas Service Statistics 1984 1983 1982 1981 1980 1979 1974 Bcf Gas Deliveries 198.5 177.6 189.8 176.1 203.3 713.3 205.4

% Char.ge 11.8 %

(6.4) 7.7 (13.4)

(4.7) 3.2 (5.6)%

Customers (000) 771.5 744.3 718.5 701.3 680.6 658.2 564.6

% Change 3.7 %

3.6 2.4 3.0 3.4 3.9 4.1 %

Average Annual Residential Mcf Usage 129.2 120.2 125.0 112.9 140.1 157.3 164.1

% Change 7.5 %

(3.8) 10.7 (19.4)

(10.9) 4.0 (12.7)%

Annual IIcating Degree Days 6,786 6,429 6,109 4,570 5,768 6,396 5,911

% Change 5.6 %

5.2 33.7 (20.8)

(9.8) 6.5 (3.3)%

Average Residential Revenue Per Mcf

$4.37 4.61 4.11 3.48 2.70 2.08

$0.82

% Change (5.2)%

12.2 18.1 28.9 29.8 26.6 20.8 %

Averagc Annual Revenue Per Residential Customer 5565 554 513 393 378 327 8135

% Change 2.0 %

8.0 30.7 3.9 15.4 31.7 5.5 %

Dally Availability -(MMcf) 1,464 1,459 1,462 1,457 1,425 1,371 1,221 Maximum Peak Day Sendout (MMcf) 1,284 1.356 1,302 1,278 1,246 1,143 1,068

% Change (5.3)%

4.1 1.9 2.6 9.0 (1.5) 3.0 %

24

Consolidated R: port of Management Financial Information Report of Management 25 The accompanying financial statements of Public Service Company of Colorado and subsidiaries have Management's Discussion and Analysis been prepared by Company personnel in conformity of Financial Condition and with generally accepted accounting principles Results of Operations 26 consistent with the Uniform System of Accounts of the Consolidated Balance Sheet 28 Federal Energy Regulatory Commission. The integrity and objectivity of the data in these financial statements Consolidated Statement of Income 30 are the responsibility of management. Financial information contained elsewher: in this Annual Report Consolidated Statement of Retained Earnings 31 is consistent with that in the financial statements.

Consolidated Statement of Source of Funds The Company maintains and enforces a system of For Plant Construction Expenditures 32 internal accounting controls, which is designed to pr vide reasonable assurance, on a cost effective basis, Notes to Consolidated Financial Statements 33 as to the integrity, objectivity and reliability of the Report of Certified Public Accountants 46 financial records. This system includes a program of internal audits to assure management that proper procedures and methods of operation are used to implement the plans, policies and directives of management.

The accounting and internal control procedures of the Company are reviewed by the Audit Committee of the Board of Directors. The Committee, which is composed of directors who are not employees of the Company, meets regularly with the Company's management, the internal audit staff and the independent accountants.

The accompanying financial statements have been examined by Arthur Young & Company, independent accountants, whose report is on page 46.

IL D. D. Hock Vice President and Chief Accounting Officer R% wa&

R. F. Walker President and Chief Executive Officer February 8,1985

Managem:nt's Discussion and Analysis of Financial

~

Condition and Results of Operations The following factors, which may not be indicative of future Fuel used in generation expense increased in 1984 due, in operations or earnings, have had a significant effect upon the part, to the effect of monthly adjustments to fuel expense results of operations during 1984 and 1983 which are made to match the total of certain fuel costs with the amounts currently recovered from customers through the Results of Operations ECA. Fuel used in generation was also charged in 1984 for Significantly higher electric revenues in 1984, as compared t potential customer refunds related to plant performance at 1983, are attributable to the impact of an increase in sales the Fort St. Vrain Nuclear Generating Station. (See Note 1I of volume, particularly to commercial and industrial customers, Notes to Consolidated Financial Statements.) A small decrease a 5.51% increase in base rates granted to the Company by in generation of energy in 1984 and an offsetting small the CPUC and the recovery of increased energy costs ncrease in the per unit cost of fuel resulted in only 51 through the Electric Cost Adjustment (ECA). While electric million of the increase in fuel used in generation expense. In revenues increased only slightly in 1983 due to nominal sales 1983 fuel used in generation expense decreased as a result of growth, in 1984 an improved economy, record cold temper-a decrease in generation along with relatively stable per unit atures and total customer growth of 3% all helped to bring costs of fuel, about an 8.6% increase in total electric sales. Commercial Purchased power expense was much higher in 1984 due to and industrial sales, which increased by only 2% in 1983, a large increase in the amount of energy purchased and, to a increased i1% in 1984.

lesser extent, increases in the per unit cost of energy Gas revenues increased in 1984 by approximately the same purchased. The Company purchased more power in 1984 amount as in 1983, although for different reasons. In 1983 than in 1983 to take advantage of the availability of low cost the recovery of the increased cost of gas purchased for resale power. Purchased power expense decreased in 1983 due to through the adjustment clause of the gas tariff more than lower per unit costs which outweighed the effect of an offset a decrease in sales volume. In 1984 gas revenues increase in the amount of energy purchased.

increased as a result of an 11.8% increase in total gas de-Gas purchased for resale expense decreased in 1984 even liveries and a 3.12% increase in base rates granted to the though the volume of gas purchased increased. The main Company by the CPCC. Gas revenues in 1984 would have reasons were lower per unit costs from the Company's sup-been higher had it not been for the decreased price of gas plier of natural gas and the impact of approximately $17.4 purchased and the impact of supplier refunds which are million in FERC mandated refunds from suppliers. In 1983 passed on to customers. The improved economy, record higher per unit costs from the Company's supplier of natural cold temperatures, lower gas prices and total customer gas caused gas purchased for resale to increase, despite a growth of more than 3% contributed to the increase in gas decrease in the volume of gas purchased.

deliveries in 1984.

Other operating and maintenance expenses have increased Electric and gas ope rating revenues reflect the effects of in 1983 and 1984 primarily as a result of higher payroll and rate increases and cost adjustment clauses on prices of units related expenses, the effects of general inflation on the prices sold. Operating revenues also reflect the volume changes in of materials and services, and increased expenses associated unit sales. The foregoing factors contributed to annual with regular system expansion. In 1984 an additional factor increases in revenues over revenues for the preceding year as contributing to the increase in maintenance expense was indicated in the following table:

increased maintenance at the Fort St. Vrain Nuclear 1984 1983 Generating Station. (See Note 11 of Notes to Consolidated Electric revenues:

(Millions of Doitars)

Financial Statements.) Depreciation expense has increased in B2se rate increases 8 38.3

$ 8.3 each year due to plant additions.

Electric cost adjustment M9 (12.8)

In 1984 a substantial increase in income taxes resulted Sales volume and other changes 68 3 14.8 from an increase in income before income taxes.

Net increase

$145 9 8 10.3 The significant increase in miscellaneous income and deductions-net in 1984 is due to an increase in the Company's temporary cash investments which increased B se rate in reases 8 19.1 5 5.1 interest income.

Gas cost adjustment (69 0) 92.7 Sales volume and other changes 78.3 (68.5)

Impact of Inflation and Changing Prices Net increase

$ 28 4 8 29.3 An analysis of the effects of inflation and changing prices is included in the Notes to Consolidated Financial Statements.

The increases (decreases) in operating expenses from the (See Note 13 of Notes to Consolidated Financial Statements.)

preceding year were as follows:

1984 1983 (Millions of Dollars)

Fuel used in generation 5 161

$(I1.6)

Purchased power 63 0 (2.7)

Gas purchased for resale

( 4 ~)

24.1 Other operating expenses 66 33.9 Ma!ntenance

8. 4 5.7 Depreciation 53 5.2 Taxes (other than income taxes) 42 2.2 Income taxes 4U (9 4)

Net increase

$142 6 8 47.4 26

I.lquidity and Capital Resources The construction estimates shown above are subject to At December 31,1984 the Company and its subsidiaries continuing review and adjustment. Actual expenditures may estimated the cost of their construction program, including vary from such estimates due to factors such as changes in AFDC and other capital requirements, in 1985,1986 and business conditions, environmental requirements, availability 1987 to be as follows:

and cost of labor and materials and other costs. In addition, unten it appears that the Company's objectives for the fi-1985 1986 1987 nancing of its construction expenditures in future years can N ^* " *")

["7 be attained without significant common equity dilution from substantial sales of common stock below book value, such Production 8 %,762 3 42,564 8110,394 Transmission 27,881 41,940 5,741 estimated construction expenditures will be reduced. Under Distribution 76.797 84,098 69,349 such circumstances, construction will be limited to commit-Gas 24,466 22,680 21,699 ments previously made, such as the installation of pollution General 31,877 32.798 29,530 control equipment required to bring the Company's facilities Subtotal 257,783 224,080 236,713 into compliance with various governmental standards, regul-Subsidiaries 43,262 43,834 29,458 ations or variances and to the maintenance of existing facilities.

Total construction 301,045 267,914 266,171 The Company's Indenture permits the issuance of addi-Less: AFDC 11,780 11,791 10,570 tional first mortgage bonds to the extent of 60% of the value Add: Sinking funds and of net 2dditions to the Company's utility property, provided debt maturities 70,857 78,019 40.895 net earnings before depreciation, taxes on income and interest expense for a recent twelve month period are at least Total capital requirements

$360,122 8334.142 8296.496 2.5 times annual interest requirements on all bonds to be outstanding. At December 31,1984 the amount of net addi-The Company's objectives for the financing of these capital tions would permit (and the net earnings test would not pro-requirements include internal generation of at least one-half hibit) the issuance of approximately $383,000,000 of addi-of the funds required, maintenance of a sound capitalization tional bonds at an assumed annual interest rate of 12.85%.

structure consisting of not less than 40% common equity, Coverage at December 31,1984 was 6.07.

not more than 45% lorig-term debt and the balance in pre-The Company's Restated Articles of Incorporation prohibit ferred stock, and the maintenance of high credit ratings for the issuance of additional preferred stock without preferred its securities.

shareholder approval, unless the gross income available for At December 31,1984 the Company and its subsidiaries the payment of interest charges for a recent twelve month estimated that their 1985-1987 capital requirements would be period is at least 1.5 times the total of (1) the annual interest ract with funds provided from the following sources:

requirements on all indebtedness to be outstanding for more than one year and (2) the annual dividend requirements on sources 1985 1986 1987 all preferred stock to be outstanding. At December 31,1984 gr ss 2

2 er se eme pe d Exte nal

$ 115,581 8

7 800 the Company to issue approximately $1,219,000,000 of addi-Net change in tional preferred stock at an assumed annual dividend rate of short-term borrowings and investments 73,814 68,781 (25,445)

I1.50%. Coverage at December 31,1984 was 3.91.

Internal 170,727 215,804 242.141 The Company's Restated Articles of incorporation prohibit, Total sources

$360,122 3334,142 5296 4 %

without preferred shareholder approval, the issuance or assumption of unsecured indebtedness, other than for re-At December 31,1984 the Company and its subsidiaries funding purposes, greater than 15% of the aggregate of(1) had $128.1 million invested in various short-term money the total principal amount of all bonds or other securities instruments. As indicated in the above table, the liquidation representing secured indebtedness of the Company, then out-of such investments is anticipated to be used in 1985 and standing, and (ii) the total of the capital and surplus of the 1986 to finance the Company's capital requirements. In 1987 Company, as then recorded on its books. At December 31, 1984 the Company had outstanding unsecured indebtedness, the Company's investments in short-term money instruments are anticipated to increase from 1986 levels.

including subsidiary indebtedness which is guaranteed by the For 1985, in addition to the use of short term invested Company, in the amount of $46,427,000. The maximum capital of $73.8 million, the Company and its subsidiaries amount permitted under this limitation was approximately anticipate raising external funds of approximately $14.5 3294,000,000 at December 31,1984.

Arrangements for bank lines of credit totaled $65,000,000 million from the sale of common stock through the Com.

at December 31,1984 at which time $62,125,000 was pany's Automttic Dividend Reinvestment and Common Stock Purchase Plan,545.4 million from the sale of subsidiary available to the Company.

unsecured long-term debt and $5.7 million from pollution control revenue bond proceeds held in trust. The Company anticipates issuing 350,000,000 First Mortgage Bonds in 1985 in order to redeem its First Mortgage Bonds,15% Series due 1987, prior to maturity. The financing plans are subject to change depending on market and business conditions and changes, if any, in the construction plans of the Company and its subsidiaries. Plans for sales of securities beyond 1985 han not been formalized at this time.

l Conxildat:d Balance Sh:st December 31,1984 and 1983 Public Service Company of Colorado and Subsidiaries A sets 1984 1983 (Thousands of Dollars)

Property, Plant and Equipment, at cost:

Electric

$2,357,444 52,259,281 Gas 574,838 544,>37 Steam and other 52,337 50,307 Common to all departments 177,229 159,863 Construction in progress (Note 11) 55,850 57.109 3,217,698 3,071,097 Less accumulated provision for depreciation 926,705 831,949 2,290,993 2,239,148 Nuclear fuel 64,171 47,152 2,355,164 2,286,300 Investments, at cost 4,892 3,114 Current Assets:

Cash 11,302 10,234 Temporary cash investments 128,057 59,519 Accounts receivable, less provision for uncollectible accounts (1984-84,566; 1983-83,287) 170,253 150,102 Recoverable purchased gas and electric energy costs-net (Note 1) 28,993 67,575 Notes receivable 113 19 Fuel inventory, at average cost 61,169 54,248 Materials and supplies, at average cost 54,948 51,116 Gas in underground storage, at cost (LIFO) 14,980 15,901 Prepaid expenses 2.850 2,886 Total Current Assets 472,665 411.600 Deferred Charges:

Debt expense (being amortized) 8,315 8,996 Other 20,620 6,189 28,935 15,185 Total Assets

$2,861,656 52,716,199 see accompanying notes.

Capital and Liabilities 1984 1983 (Thousands of Dollars)

Common Equity:

Common stock (Note 2)

$ 693,160

$ 652,115 Retained carnings 200,573 169,299 893,733 821,414 Preferred Stock (Note 2):

Not subject to mandatory redemption 140,008 140,008 Subject to mandatory redemption at par 86,824 88,200 Long-Term Debt (Note 3) 883,188 885,810 2,003,753 1,935,432 Current Liabilities:

Notes payable and commercial paper (Note 4) 2,875 19,790 Long-term debt due within one year 15,957 22,219 Preferred stock subject to mandatory redemption within one year (Note 2) 2,576 1,200 Accounts payable 199,602 194,632 Dividends payable 28,949 26,789 Customers' deposits 7,908 7,194 Accrued taxes 71,444 66,121 Accrued interest 18,178 18,396 Amount subject to refund (Note 12) 31,460 25,766 Other 34,447 24,343 Total Current Liabilities 413,396 406,450 Deferred Credits:

Customers' advances for construction 62,553 46,367 Investment credit (being amortized over the productive lives of the related property) 160,425 148,927 Accumulated deferred income taxes (Note 8) 147,893 122,260 Funds from Settlement Agreement (Note Il) 68,501 52,901 Other 5,135 3,862 444,507 374,317 Commitments and Contingencies (Notes 6 and 11)

Total Capital and Liabilities

$2,861,656

$2,716,199

Consolidated Stat: ment of income Years ended December 31,1984,1983 and 1982 Public Service Company of Colorado and subsidiaries 1984 1983 1982 (Thousands of Dollars Except Per sharc Data)

Operating Revenues:

Electric

$ 999,628 8 853,743 5 843,436 Gas 790,068 761,629 732,334 Other 12.328 13,269 14,269 1,802.024 1,628,641 1,590,039 Operating Expenses:

Fuel used in generation 188,889 172,802 184,386 Purchased power 161,928 98,978 101,664 Gas purchased for resale 606,558 611,283 587,187 Other operating expenses 267,416 260,773 226,919 Maintenance 72,475 64,123 58,418 Depreciation 96,883 91,577 86,431 Taxes (other than income taxes) (Note 9) 60,051 55,847 53,631 income taxes (Note 8) 137,504 93,763 103,155 1,591,704 1,449,146 1,401,791 Operating Income 210.320 179,495 188,248 Other Income and Deductions:

Allowance for equity funds used during construction (Note 1) 6,042 5,158 2,029 Miscellaneous income and deductions-net 9.267 656 3,635 225,629 185,309 193,912 Interest Charges:

Interest on long-term debt 78,988 77,109 73,000 Amortization of debt discount and expense less premium 520 502 544 Other interest 4,513 4,866 8,422 Allowance for borrowed funds used during construction (Note 1)

(3,639)

(3,547)

(4,550) 80,382 78,930 77,416 nit Income 145,247 106,379 116,496 Dividend Requirements on Preferred Stock 16,661 16,661 16,661 Errnings Available for Common Stock 5 128,586 3 89,718 8 99,835 S5res of Common Stock Outstanding (thousands):

Year-end 51,632 49,182 47,020 Average 50,440 48,135 45,948 Errnings Per Average Share of Common Stock Outstanding

$2.55

$ 1.86 52,17 Dividends Per Share of Common Stock:

Paid

$ 1.90

$ 1.82

$ 1.74 Declared

$ 1.92 31.84

$ 1.76 see accompanying notes.

Consolidatcd Statement of Retained Earnings Years ended December 31,1984,1983 and 1982 Public service Company of Colorado and subsidianes l

1984 1983 1982 (Thousands of Dollars)

Retained Earnings at Beginning of Year

$ 169,299 3168,517

$ 150,166 Net Income 145,247 106,379 116,496 314.546 274,896 266,662 Dividends:

On cumulative preferred stock:

$100 par value:

4.20% series 420 420 420 4-1/4% series 744 744 744 4-1/2% series 293 293 293 4.64% series 742 742 742 4.90% series 735 735 735 4.90% 2nd series 735 735 735 7.15% series 1,787 1,787 1,787 7.50% series 2,250 2,250 2,250 8.40% series 2,890 2,890 2,890 12.50% series 3,125 3,125 3,125

$25 par value:

8.40% series 2.940 2,940 2,940 16,661 16,661 16,661 On cornmon stock:

51.92 per share in 1984, $1.84 per share in 1983 and $1.76 per share in 1982 97.324 88,916 81,225 113,985 105,577 97,886 Other Deductions (Additions) - Net (12) 20 259 113.973 105,597 98,145 R:tained Earnings at End of Year

$200.573 5169,299 5168,517 see accompanying notes.

31

Consolidat:d Statem:nt of Source of Funds For Plant Construction Expenditures Years ended December 31,1984,1983 and 1982 Public Service Cornpany of Colorado and Subsidiaries 1981 1983 1982 Source of Funds:

(Thousands of Douars)

Funds from Operations:

Net Income

$ 145,247

$106,379 5116,496 Non-cash Charges (Credits) Against Income Not Involving Working Capital in the Current Period:

Depreciation charged to operating expenses 96,883 91,577 86,431 Depreciation charged to clearing and other accounts 10,860 9,005 6,538 Allowance for funds used during construction (9,681)

(8,705)

(6,579)

Investment credit - net of amortization 11,498 10,403 10,615 Deferred income taxes 27,269 29,525 29,340 Funds from Operations 282,076 238,184 242,841 Dividends:

On preferred stock (16,661)

(16,661)

(16,661)

On common stock (97,324)

(88,916)

(81,225)

Funds Retained in the Business 168,091 132,607 144,955 Funds from Financing - Net Proceeds:

Proceeds from sale of common stock 41,041 35,719 30,222 Proceeds from sale of pollution control bonds 11,476 9,123 384 Proceeds from issue of long-term notes 8,124 8,782 27,661 Funds from Financing 60,641 53,624 58,267 Funds from Settlement Agreement (Note 11) 23,586 38,601 24,513 Reduction in Long-Term Debt (22,183)

(24,322)

(2,322)

Other Sources and Applications - Net 10,854 16,788 10,224 Total Funds Available 240,989 217,298 235,637 Increase in Working Capital 54,119 30,518 12,177 Nat Plant Construction Expenditures 186,870 186,780 223,460 Allowance for Funds Used During Construction 9,681 8,705 6,579 Gross Plant Construction Expenditures

$ 196,551

$195,485 8230,039 Ircrease (Decrease)In Components of Working Capital:

Current Assets:

Cash

$ 1,068 3

(232) 8 (9,827)

Temporary cash investments 68,538 50,016 5,001 Accounts and notes receivable 20,245 (20,587) 40,859 Recoverable purchased gas and electric energy costs - net (38,582) 8,207 18,480 Fuel inventory 6,921 (6,086)

(5,370)

Materials and supplies 3,832 2,255 2,554 Other (957) 2,004 223 61,065 35,577 51,920 Current Liabilities:

Notes payable and commercial paper (16,915)

(31,597)

(9,743)

Long-term debt due within one year (6,262) 19,930 (448)

Accounts payable 4,970 (340) 21,094 Accrued liabilities 5,105 (2,594) 20,906 Other 20,048 19,660 7,934 6,946 5,059 39,743 Increase in Working Capital

$ 54,119

$ 30,518 3 12,177 See accompanying notes

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies Investment tax credits are deferred and amortized to income over the productive lives of the related Consolidations property. The Economic Recovery Tax Act of 1981 The Company follows the practice of consolidating the enables the Company to claim an additional tax credit accounts of its significant subsidiaries.

for contributions to the Employee Stock Ownership Depreciation pol!cy:

Plan. Contributions, which are based on the annual The Company and its subsidiaries, except Fuel c mpensation of eligible employees, are made in cash Resources Devclopment Co. (Fuelco), use straight-line or the Company s common stock and, if cash, are depreciation for accounting purposes. Composite rates invested in the Company's common stock. These addi-are used for the various classes of depreciable assets.

tional tax credits for 1984 and 1983 are based on one-Depreciation rates include provisions for disposal half percent of the annual compensation of employees and removal costs of property, plant and equipment, c vend W tk plan.

including the nuclear plant. Total depreciation expense Amortization of deh: premium, discount and in 1984 approximates an annual rate of 3.55% on the expenses average cost of depreciable properties. Fuelco uses the Debt premium, discount and expense is being amor-unit-of-production depreciation method for accounting tized by charges to IOme over the respective original purposes. For income tax purposes, the Company and lives of the applicable issues.'

its subsidiaries use accelerated depreciation and other elections provided by the tax laws.

Allowance for funds ni$d during construction Pursuant to an order of the Public Utilities Commis, (AFDC):

N sion of the State of Colorado (CPUC), the composite AFDC, which does not (epresent current cash earnings, depreciation rates include a provision for the estimated is defined in the system of accounts prescribed by the cost of decommissioning the nuclear plant after its FERC and the CPUC as the net cost during the period service life. Funds equal to the provision for decom-of construction of borrowed funds used for construc-missioning costs are transferred to an independent tion purposes, and a reasonable rate on funds derived trustee and can be used only for the decommissioning from other sources. In accordance with such system of of the nuclear plant.

accounts, the Company capitalizes AFDC as a part of Replacements and betterments representing units of the cost of utility plant, with a credit to nonoperating property are capitalized. Items that represent less than income for the portion of AFDC attributable to equity units of property are charged to operations as main, funds and a reduction of interest charges for the tenance. The cost of units of property retired, together Portion of AFDC attributable to borrowed funds. The with cost of removal, less salvage, is charged in full capitalization of AFDC results in the inclusion of AFDC against the accumulated provision for depreciation.

In rate base and the recovery thereof through future billings to customers. In an order dated November, Income taxes:

1977, the CPUC directed that the Company is to The Company and its subsidiaries file consolidated capitalize AFDC at its authorized rate of return, but not state and federal income tax returns. Income taxes are to exceed the amount allowed by the formula pre-allocated to the subsidiaries based on separate scribed by the FERC. Accordingly, the rate used by the company computations of taxable income or loss.

Company in 1982 and 1983 was 10.75% For the first The Company and its regulated subsidiaries provide five months of 1984, the rate used was 10.75% and for for deferred income taxes to the extent allowed by the last seven months the rate used was 10.21%

regulatory agencies, including deferred taxes arising These rates represented the Company's authorized from the use of accelerated depreciation, accelerated rates of return at that time and did not exceed the cost recovery, qualifying accelerated amortization and amount allowed by the formula prescribed by the timing differences due to deferred gas and electric FERC.

costs. In addition, the Company provides for deferred taxes on book-tax timing differences arising from the Recoverable purchased gas and electric energy Fort St. Vrain Nuclear Generating Station contract costs - nets settlement, from customer refunds not meeting the The Company, Cheyenne IJght, Fuel and Power Com-economic performance test recently required by the pany (Cheyenne), and Western Gas Supply Company Tax Reform Act of 1984 and for all book tax timing (WestGas) recover certain purchased gas and electric differences included in Federal Energy Regulatory energy costs, in excess of amounts recovered through Commission (FERC) jurisdictional rates. In accordance base rates, from their retail customers through various with the requirements of the Financial Accounting gas and electric cost adjustment tariffs. These cost Standards Board (FASB),1480 Welton, Inc., Fuelco and adjustment tariffs, which include a provision for the Bannock Center Corporation provide for deferred collection of deferred purchased gas and electric taxes arising from all book-tax timing differences.

energy costs, are revised periodically as prescribed by

t N tes to C2nsolidated Financial Statements (continued) the appropriate regulatory agencies. The deferred costs tion expenditures, to reflect the substant ally current are the difference between actual costs incurred and nature of the recoverable purchased gas nd electric the amounts currently recovered from customers. A energy costs - net These reclassificaticns have been

, substantial portion of this deferred amount represents made for comparative purposes and have no effect on the costs incurred to provide gas and electric energy net income.

which customers have used but for which they have Revenues:

not been billed.

The Company reads customers, meters on a cycle Reclassifications have been made in the 1983 con-basis, and renders bills each month. Revenues are solidated balance sheet and the 1983 and 1982 consoli-recorded when the customers are billed.

dated statements of source of funds for plant construc-

2. Capital Stock 1984 1983 Shares Amount Shares Amount (Thousands (Thousands of Dollars) of Dollars)

Cumulative preferred stock, $100 par value:

Authorized 3,000,000 3,000,000 Issued and outstanding:

Not subject to mandatory redemption:

4.20% series 100,000

$ 10,000 100,000

$ 10,000 4-% % series (includes $7,500 premium) 175,000 17,508 175,000 17,508 4-% % series 65,000 6,500 65,000 6,500 4.64% series 160,000 16,000 160,000 16,000 4.90% series 150,000 15,000 150,000 15,000 4.90% 2nd series 150,000 15,000 150,000 15,000 7,15% series 250.000 25,000 250,000 25,000 Total 1,050,000

$ 105,008 1,050,000

$ 105,008 Subject to mandatory redemption:

7.50% series 300,000 s 30,000 300,000

$ 30,000 8.40% series 344,000 34,400 344,000 34,400 12.50% series 250,000 25,000 250,000 25,000 894.000 89.400 894,000 89,400 Less: Preferred stock subject to mandatory redemption within one year (25,760)

(2,576)

(12,000)

(1,200)

Total 868.240

$ 86.824 882,000

$ 88,200 Cumulative preferred stock ($25), $25 par value:

Authorized 4,000.000 4,000,000 Issued and outstanding:

Not subject to mandatory redemption:

8.40% series 1,400.000

$ 35,000 1,400,000 5 35,000 Common stock, $5 par value:

Authorized 80.000,000 80,000,000 Issued and outstanding 51,652,451 5258,162 49,182,153 5245,911 Premium on common stock 434.998 406,204 Total 5693,160 5652,115

I Changes in common stock and premium on common Premium stock for the three years ended December 31,1984 are Price range Common on common as follows:

per share stock stock (Thousands of Dollars)

Balance, January 1,1982

$224,480

$361,344 1,611,582 shares sold under Dividend Reinvestment Plan

$13.00 to 16.00 8,058 14,875 504,264 shares sold under Employee Stock Ownership Plan

$13.81 to 15.38 2,521 4,952 7,743 shares sold to employees

$ 15.00 39 77 Balance, December 31,1982 235,098 381,248 1,990,151 shares sold under Dividend Reinvestment Plan

$15.79 to 18.25 9,951 22,918 172,474 shares sold under Employee Stock Ownership Plan

$16.69 to 17.69 862 2,038 Balance, December 31,1983 245,911 406,204 2.450,298 shares sold under Dividend Reinvestment Plan

$15.85 to 18.44 12,251 28,794 Balance, December 31,1984

$258,162

$434,998 During 1985 the Company must offer to repurchase

$ 100; 8.40% series: $105 on or prior to July 31,1985, 12,000 shares of the 7.50% cumulative preferred series and reducing each year thereafter by $.25 per share subject to mandatory redemption and 13,760 shares of untilJuly 31,2004, after which the redemption price is the 8.40% cumulative preferred series subject to

$ 100; 12.50% series: $105.21 on or prior to June 30, mandatory redemption at $100 per share plus accrued 1985, $104.17 on or prior to June 30,1986, $103.13 dividends to the date set for repurchase. Conse-on or prior to June 30,1987, $102.09 on or prior to quently, this preferred stock to be redeemed has been June 30,1988, and $101.05 on or prior toJune 30, classified as preferred stock subject to mandatory re-1989, after which the redemption price is $100.

demption within one year. During 1984 the Company In 1985 and in each year thereafter, the Company offered to repurchase 12,000 shares of the 7.50%

must offer to repurchase up to 12,000 shares of the cumulative preferred series subject to mandatory re-7.50% series at $100 per share, plus accrued dividends demption at $100 per share plus accrued dividends to to the date set for repurchase, and up to 13,760 shares the date set for repurchase, however, the offer was not of the 8.40% series at $100 per share, plus accrued accepted and the shares of the preferred stock were dividends to the date set for repurchase; starting in not repurchased. No other changes in preferred stock 1986 and in each year thereafter, the Company must occurred in the three years ended December 31,1984.

set aside in a sinking fuhd an :: mount sufficient for the The preferred stock may be redeemed at the option redemption of 50,000 shares of the 12.50% series at of the Company upon at least 30, but not more than

$100 per share, plus accrued dividends to the date set 60, days' notice in accordance with the following for redemption. The Company shall be entitled, at its schedule of prices plus an amount equal to the accrued option, on any one of the sinking fund redemption dividends to the date fixed for redemption:

dates, to redeem up to 50,000 shares of the 12.50%

series, in addition to the shares otherwise required to o subject to tandatory redemption:

be redeemed on such sinking fund redemption date, at 4.20% series: $101; 4 l/4% series: $101; 4 l/2%

$100 per share plus an amount equal to the accrued and unpaid dividends thereon to such sinking fund re-series: $101; 4.64% series: $101; 4.90% series: $101; 4.90% 2nd series: $101; 7.15% series: $102.50 prior dempti n date; provided, however, that the option of to March 1,1987, and $101 on and after that date.

the Company to so redeem up to 50,000 additional shares of the 12.50% series may be exercised only once.

S bject to mandatory redemptiom

$2 pa 7.50% series: $104.75 on or prior to August 31,1985,

,b ct to mandatory redemption:

reducing each year thereafter by $.25 per share until 8.40% series: $26.50 prior to December 1,1986, August 31,2003, after which the redemption price is

$25.75 thereafter but prior to December 1,1991, and

$25.25 on or after that date.

3

l N tes to C nsolidated Financial Statements (continued)

3. Long-Term Debt 1984 1983 (Thousands of Dollars)

Public Service Company of Colorado:

First mortgag aonds:

15% series, due March 1,1987 8 50,000

$ 50,000 4-3/8% series, due May 1,1987 30,000 30,000 4-5/8% series, due May 1,1989 20,000 20,000 4-1/2% series, due October 1,1991 30,000 30,000 4-5/8% series, due March 1,1992 8,800 8,800 4-1/2% series, due June 1,1994 35,000 35,000 5-3/8% series, due May 1,1996 35,000 35,000 5-7/8% series, ducJuly 1,1997 35,000 35,000 6-3/4% series, duc July 1,1998 25,000 25,0a0 8-3/4% series, due September 1,2000 35,000 35,000

-1/4% series, due February 1,2001 40,000 40,000 7-1/2% series, due August 1,2002 50,000 50,000 7-5/8% series, due June 1,2003 50,000 50,000 9-3/8% series, due October 1,2005 49,500 49,500 8-1/4% series, due November 1,2007 50,000 50,000 9-1/4% series, due October 1,2008 50,000 50,000 16-l/4% series, due December 1,2011 49,000 49,500 Pollution Control Series A,5-7/8%, due March 1,2004 24,000 24,000 Pollution Control Series B:

6-5/8%, due December 1,1985 10,500 7-1/8%, due December 1,1990 2,000 2,000 7-5/8%, due December 1,1995 2,500 2,500 8%, due December 1,2004 35,000 35,000 Pollution Control Series C:

7-1/4%, due October 1,2004 15,000 15,000 7-3/8%, due October 1,2005 1,960 1,960 7-3/8%, due October 1,2006 2,105 2,105 7-3/8%, due October 1,2007 2,260 2,260 7 3/8%, due October 1,2008 2,425 2,425 7-3/8%, due October 1,2009 26,250 26,250 Pollution Control Series D:

13 3/4%, duc November 1,2011 27,380 27,380 Less amounts held in construction fund (479)

(479)

Pollution Control Series E:

9-1/8%, due May 1,2013 42,000 42,000 Less amounts held in construction fund (19,715)

(31,192)

Unamortized premium 1,091 1,181 Unamortized discount (1,145)

(1,196)

Capital lease obligations, 10.88% 14.65%, due in installments through April 1,1995 4.331 809,263 804,494 Cheyenne IJght, Fuel and Power Company:

First mortgage bonds:

3 3/4% series, due May 1,1985 847 5 l/2% series, due April 1,1990 1.253 1,278 7-7/8% series, due April 1,2003 4,000 4,000 Unsecured notes, due Decembu 31,1988, interest rates are based on the certificate of deposit rates at Northern Trust Company 2,250 3,000 36

1984 1983 (Thousands of Dollars)

Western Gas Supply Company:

Unsecured promissory notes:

10%, due September 25,1986 1

2 7-3/4%, due December 1,1997 20,000 20,000 10.35%, due December 1,1999 9,333 10,000 1480 Welton, Inc.:

4-3/4% secured notes, payable in equal quarterly installments of

$168,388 toJune 1,1992 covering principal and interest 3,748 4,229 7-1/2% 12% mortgage notes, due in installments through 1987 135 270 12.50% secured promissory note, due March 1,1998 12,890 13,310 10% unsecured promissory notes, due in annual installments through October 3,1988 726 Fuel Resources Development Co.:

Unsecured note, due January 1,1986, interest rate fluctuates with the New York Federal Funds rate 3,600 10,000 llome Light and Power Company:

First mortgage bonds:

4% series, due February 1,1986 348 357 51/2% series, due September 1,1989 313 320 6% series, due April 1,1997 672 684 7-7/8% series, due December 1,2002 2,050 2,088 10-3/8% series, due January 1,2003 3,400 3,460 Bannock Center Corporation:

Unsecured note payable, due June 29,1986, interest rate fluctuates with the New York Federal Funds rate 6,950 51/8% 14% mortgage notes, due in installments through July 1.1992 2.256 7.471

$883.188

$ 885,810 Substantially all properties of the Company and its

$6,181,000 (1986), $85,918,000 (1987), S5,957,000 subsidiaries, other than expressly excepted property, (1988) and $25,806,000 (1989) for the Company; and are subject to the liens securing the Company's First

$5,080,000 (1985), $14,445,000 (1986), $3,630,000 Mortgage Bonds or the mortgage bonds and notes (1987), $3,684,000 (1988) and $2,525,000 (1989) for its of subsidiaries, subsidiaries. The Company may n:isfy its sinking fund The aggregate annual maturities and sinking fund obligations through the application ~of prcperty addi-requirements during the five years subsequent to tions, and Cheyenne may satisfy $60,000 of its sinking December 31,1984 are: $16.874,000 (1985),

fund obligation annually through the application of property additions.

4. Notes Payable and Commercial Paper Information regarding notes payable and commercial paper for the years ended December 31,1984 and 1983 is as follows:

1984 1983 (Thousands of Dollars)

Notes payable to banks (weighted average interest rate 9.55% at December 31,1984 and 10.48% at December 31,1983)

$ 2,875 8 6,350 Commercial paper (weighted average interest rate 9.75% at December 31,1983) 13,440

$ 2,875

$ 19,790 Maximum amount outstanding at any month end during the period

$ 5.850

$ 19,790 Weighted average amount (based on the daily outstanding balance) outstanding for the period (weighted average interest rate 11.03% for the year ended December 31,1984 and 9.63% for the year ended December 31, 1983)

$3.674

$ 10,63 l

Notes to Consolidated Financial Statements (continued)

5. Bank Lines of Credit and

7. Postretirement Benefits Compensating Bank Balances Total provision for pension expense under the Com-Arrangements for bank lines of credit totaled pany's noncontributory defined benefit retirement plan

$65,000,000 at December 31,1984, and were covering all eligible employees was $19,116,000 in maintained entirely by fee payments in lieu of 1984, $18,495,000 in 1983 and $15,636,000 in 1982.

compensating balances. These lines of credit were The Company's policy is to fund pension cost ac-reduced at the Company's request effective July 1, crued. A comparison of accumulated plan benefits and 1984, from $111,849,000 at December 31,1983, plan net assets as of the end of the plan's fiscal years, consisting of $17,549,000 maintained by compensating June 30,1984 and 1983, is presented below:

balances and $94,300,000 maintained by fee payments in lieu of balances. The compensating bank balance 1984 1983 arrangements provided that the Company maintain (Thousands of Dollars) average compensating balances in the amount of Actuarial present value of

$877,450 for the six-month period ending June 30 accumulated plan benefits:

1984, $877,450 for the six month period ending Vested

$ 138,200

$ 110,800 December 31,1983 and $1,806,200 for the six-month Nonvested 14.100 12,400 period ending June 30,1983. These bank lines of Total s152.300 3123.200 credit are also used to support the Company's issuance Mar e ue of of commercial paper. At the Company's request, ta;en 5220.233

$214.623 confirmed uncommitted bank lines of credit totalling

$53,000,000 at December 31,1983 were discontinued The weighted average assumed rate of return used in during 1984. The Company generally may borrow determining the actuarial present value of accumulated under uncommitted preapproved lines of credit upon plan benefits was 9% %. The actuarial present value of request, however, the banks have no firm commitment accumulated plan benefits is generally based on to make such loans.

employees' history of pay and service and other appropriate factors as of the benefit valuation date and

6. Commitments and Contingencies does not include anticipated future increases in em-Commitments made for the purchase of various items playee compensation. Evaluations of accumulated plan of plant and equipment aggregated apprceximately benefits as of December 31,1984 and 1983 were not

$ 127,000,000 at December 31,1984.

made, liowever, the market values of the net assets The Internal Revenue Service has completed an available for benefits at these dates were approximately examination of the federalincome tax returns of the

$252,106,000 and $220,992,000, respectively.

Company and its subsidiaries for the years 1970 In addition to providing pension benefits, the Com-through 1979. The audit results for 1970 through 1974 pany and its subsidiaries provide certain health care are in the !!tigation process while the periods 1975 and life insurance benefits for retired employees. Sub-through 1979 are in various stages of appeals within stantially all of the Company's employees become the Internal Revenue Service. The examiners propose eligible for these benefits if they reach either early or to include in income, contract refunds on the Fort St.

normal retirement age while working for the Com-Vrain Nuclear Generating Station which were recorded pany. The cost of providing health care and life insur-as a reduction of the plant cost and part of the ance benefits to active, retired and disabled employees, amounts received in the 1979 contract settlement for which is expensed as either claims or insurance this plant (see Note 11). The Company is resisting premiums are paid. amounted to $16,973,000 in 1984.

these proposals and bell:ves that the final outcome of The cost of providmg these benefits for the 1,539 these matters will not have a material effect on the retired employees is not separable from the cost of reported financial position or results of operations of providing benefits for the 7,013 active and disabled the Company.

employees.

3H

l i

8. Income Tax Expense Totalincome tax expense was different from the l

amount computed by applying the federal statutory rate to pre-tax accounting income. The reasons for this difference are as follows:

1984 1983 1982 (Thousands or Dollars)

Tax computed at statutory rate on pre tax accounting income

$ 130,064

$92,037

$ 100,956 Increase (decrease) in tax from:

Difference between tax and book depreciation 7,425 6,492 5,327 Allowance for funds used during construction (4,439)

(3,940)

(2,985)

Amortization of investment credit (6,233)

(5,666)

(5,026)

State income taxes, net of federal income tax benefit 6,383 3,829 3,885 Other - net 4,304 1,011 998 Total income tax expense

$ 137,504

$93,763

$ 103,155 income tax expense consists of the following:

Current income taxes:

Federal

$ 89,869

$48,418

$ 58,026 State 8,868 5,417 5,174 98.737 53,835 63,200 Deferred income taxes:

Fort St. Vrain contr1ct settlement (861) 28 777 Accelerated amortization 1,032 1,069 1,201 Accelerated depreciation 29,716 28,911 26,666 Intangible drilling costs 280 144 806 Lease and well impairments - net (308)

(1,749)

(294)

Capitalized interest 15 513 40 Other book tax timing differences (9) 609 144 Customer refunds (2,596) 27,269 29,525 29,340 Charge equivalent to reduction in income taxes due to deferred investment tax credit, net of amortization i1,498 10,403 10,615 Total income tax expense

$ 137,504

$93,763

$ 103.155 The Company has state investment tax credit carry-Deferred tax provisions are not recorded on certain overs totalling $3,554,000, expiring in 1989,1990 and book-tax timing differences. As of December 31,1984 1991, available to offset future state income taxes.

the cumulative net amount of such timing differences was $465,298,000. The tax effect of this amount is not recorded currently as regulatory commission pro-cedures will result in such costs being charged to cus-tomers when the timing differences reverse and the tax effects are paid.

f

NItes to CInsolid:ted Financial Statements (continued)

9. Taxes (Other Than Income Taxes) 1984 1983 1982 (Thousands of Dollars)

Real estate and personal property taxes

$36,460

$36,332

$35,057 Franchise taxes 1,062 952 1,111 Social security taxes 14,-'64 13,403 11,903 City and state use taxes 5,631 4,713 5,746 Miscellaneous taxes 5,699 3,628 2,360

$63,616

$ 59,028

$ 56,177 Charged:

Directly to income:

Operating expenses

$60,051

$ 55,847

$53,631 Other 542 160 170 To property, plant and equipment and various clearing accounts 3.023 3,021 2,376

$63,616

$ 59,028

$ 56,177

10. Segments of Bu?iness Segment information for the year ended December 31, 1984 is as follows:

Electric Gas Other Total (Thousands of Dollars)

Operating revenues S 999,628

$790,068

$ 12.328 $ 1,802,024 Operating expenses, excluding depreciation 644,025 708,467 4,825 1,357,317 Depreciation 76,368 18,898 1,617 96,883 Total operating expenses 720,393 727,365 6,442 1,454,200 Operating income'

$ 279,235

$ 62,704 8 5,886 8 347,824 Plant construction expenditures * *

$ 142,495 8 45,152

$ 8,904 8 196,551 Identifiable assets, December 31,1984:

Utility plant

$ 1,863,856

$414,346

$76,962 $ 2,355,164 Materials and supplies S

47,402 5 7,511 8

35 54,948 Fuel inventory 8

60,897 8

272 61,169 Gas in underground storage

$ 14,980 14,980 Other corporate assets 375,395

$ 2,861,656 Before income taxes

includes alkration of common utility property

d Segment information for the year ended December 31, 1983 is as follows:

Electric Gas Other Total (Thousands of Dollars)

Operating revenues S 853,743

$761,629

$ 13,269 $ 1,628,641 Operating expenses, excluding depreciation 544,488 711,756 7,562 1,263,806 Depreciation 72,355 17,485 1,737 91,577 Total operating expenses 616,843 729,241 9,299 1,355,383 Operating income' 8 236,900

$ 32,388 5 3,970 $ 273,258 Plant construction expenditures"

$ 142,536

$ 43,427

$ 9,522 $ 195,485 Identifiable assets, December 31,1983:

Utility plant"

$ 1,822,204

$394,047

$ 70,049 $2,286,300 Materials and supplies 43,475

$ 7,608 8

33 51,116 Fuel inventory 54,080 3

168 54,248 Gas in underground storage 8 15,901 15,901 Other corporate assets 308,634

$2,716,199 Segment information for the year ended December 31, 1982 is as follows:

Electric Gas Other Total (Thousands of Dollars)

Operating revenues

$ 843,436

$732,334 5 14,269 $ 1,590,039 Operating expenses, excluding depreciation 527,568 673,587 11,050 1,212,205 Depreciation 69,014 16.156 1,261 86,431 Total operating expenses 596,582 689,743 12,311 1,298,636 Operating income' 3 246,854

$ 42,591 3 1,958 $ 291,403 Plant construction expenditures"

$ 142,268 3 55,922

$ 31,849 $ 230,039 Identifiable assets, December 31,1982:

Utility plant'

$ 1,756,375

$377,891

$ 62,995 $ 2,197,261 Materials and supplies 41,117

$ 7,697 47 48,861 Fuel inventory 8

60,105 3

229 60,334 Gas in underground storage 8

$ 14,004 14,004 Other corporate assets 286,456 32,606,916 2

liefore income taxes

" Includes alk> cation of common utihty property

Notes to Consolidat:d Financial Statements (continued)

11. Fort St. Vrain Nuclear Generating Station Incentive plan:

Fort St. Vrain is included by the CPUC Iri the Com-Settlement agreement:

pany's rate base so that rates billed to customers for On June 27,1979, the Company and the prime con-energy delivered include amounts designed to cover tractor for the Fort St. Vrain Nuclear Generating costs associated with Fort St. Vrain. In response to Station (Fort St. Vrain), General Atomic Company Fort St. Vram's historically reduced levels of gener-(GAC), entered into a Settlement Agreement, a Services ation, on August 8,1984 the CPUC issued a decision Agreement anc a Fuel and Fabrication Agreement satis-requiring potential refunds through the Company s fying and settling all contracts and claims between the ECA for periods when the revenues collected under Company and GAC relative to Fort St. Vrain. Among base rates attributable to Fort St. Vrain exceed the other things, the terms of these Agreements include value of the energy produced by the plant during such the following: (a) GAC paid to the Company $60,000,000 period. Under this " incentive plan," such energy is as an adjustment of the plant cost for the reduction in valued at the same avoided cost rate as an equivalent the plant's capacity from 330 Mw at 80% capacity to amount of energy sold to the Company by a cogener-200 Mw at 60% capacity factor; and (b) GAC contri-ator or small power producer. For any period in which buted to the Company, between 1980 and 1984, Fort St. Vrain fails to produce sufficient energy valued

$97,050,427 for the cost of replacing the 130 Mw re-as set forth above, the Company would be required to duction in capacity at Fort St. Vrain with future refund the difference on a monthly basis through the electric generation facilities.

ECA. Accordingly, the refund calculation, which is Funds received from G AC per item (b) above and not intended to take the place of the replacement power yet expended for new plant construction at the end of penalty mechanism, will be applied to the period 1984 have been recorded as deferred redits on the subsequent to November 1,1984. The Company has consolidated balance sheet. Reclassifications have also filed an appeal with the District Court in and for the been made in the 1983 consolidated balance sheet and City and County of Denver, State of Colorado, for the the 1983 and 1982 consolidated statements of source of purp se of reversing the CPUC decision and has funds for plant construction expenditures to reflect net brained a stay pending appeal.

replacement capacity payments received previous to According to the calculation set forth in the CPUC's 1984 as deferred credits cather than as reductions to decision, the estimated refund for November,1984 the construction work in progress balance. These was approximately $320,000 and the monthly amounts reclassifications have been made for comparative will increase by inciements of approximately $320,000 purposes and have no effect on net income.

per month up to a maximum of approximately $3.8 C: placement power penalty million per month should the plant not operate for a The CPUC has authorized an ongoing examination of full year subsequent to November 1,1984. The actual purchased power costs as they relate to replacement amount to be refunded to customers through the ECA power deemed to be necessary when generation from is contingent upon the performance of Fort St. Vrain.

Fort St. Vrain falls below a specified level of produc-The calculation of the refund incorporates the perfor-tion. On March 6,1984 the CPUC ordered the Com-mance of Fort St. Vrain on a rolling 12-month basis or pany to refund $591,474, including interest, for the over the number of months in wnich the CPUC failure of Fort St. Vrain to generate at a specified level decision has been in effect if less than 12 months. The during the months of January and February,1983. The Company has recorded $959,833 as a charge against refund amount was determined in accordance with a earnings in 1984 to cover potential refunds for formula which sets the specific level of performance November and December.

equivalent to a 53.15% annual capacity factor based in January,1984 Fort St. Vrain was shut down in on a 200 Mw generation level.

order to initiate a scheduled refueling operation and IIcarings were held inJune,1984 regardmg the Com-associated modification / maintenance activities. On June pany's electric cost adjustment (ECA) filings for the 12,1984, following the completion of this work, elec-period March,1983 through September,1983. As in tric generation was supplied by Fort St. Vrain to the the hearings regarding the January and February,1983 Company's system. Power was being gradually in-ECA filings, the main issue in these hearings was the creased when a series of events occurred that caused purchased power costs incurred by the Company due Fort St. Vrain to be automatically shut down onJune to the alleged substandard Fort St. Vrain generation for 23,198 L During the automatic shut down process, six this time period. The hearings examiner has not yet control rod pairs failed to insert automatically.

issued a decision llearings for the time period subse-Following evaluation and investigation of this event by quent to September,1983 have not yet been sched-the Company and the Nuclear Regulatory Commission uled, however, the total estimated refund liability for (NRC), the Company has undertaken the refurbishing the time period March,1983 through October,1984 is of all of the 37 pairs of control rod drives and certain approximately $5.7 million, including interest, and that amount has been recorded to cover this contingency.

42

other engineering modifications and equipment

13. Effects of Changing Prices (Unaudited) replacements at the station.

The following supplementary Current Cost information The CPUC s August 8,1984 decision creates a potential refund exposure to the Company in view of is supplied in accordance with the requirements of the the fact that the Company believes that the refur-amended FASB Statement No. 33, " Financial Reporting bishing, modifications, and replacements at Fort St.

and Changing Prices," in order to provide certain

\\ rain cannot be completed until Spring,1985. In addi-Information about the effects of changes in specific prices on the historical cost financial data of the Com-tion, the Company must resolve issues raised by the pany. This supplementary information should be NRC as to the conouct of operations at Fort St. Vrain.

NRC approval will be required to restart the plant, and viewed as an estimate rather than as a precise measure.

Current Cost adjusted information is historical the Company cannot predict when this approval will be obtained. When the plant becomes operational, the f nancial data adjusted to reflect changes in the specific potential monthly refund exposure will decrease based prices of the Company's property, plant and equip-on the 12 month performance average in accordance ment from the date these assets were acquired to the with the CPUC decision, present. This estimated cost of replacing the produc-uve capacity of existing plant assets is primarily 1981-1982 Capacity factor test determined by indexing surviving property, plant and Intervenors have appealed a November 8,1983 CPUC equipment (including land, land rights, property held decision regarding the Fort St. Vrain capacity factor for future use, and construction work in progress) by test during 1981 and 1982 by filing an appeal on Jan-the Handy-Whitman Index of Public Utility Construc-uary 5,1984 in the District Court in and for the City tion Costs. Current Cost adjusted information indicates and County of Denver. On September 11,1984 the Dis-how the Company has been affected by the increased trict Court issued a decision overturning the CPUC's cost of maintaining its existing productive capacity, decision that Fort St. Vrain met the 50% capacity The specific prices of the Company's assets may have factor standard during the designated time period, the increased more or less than prices in general.

effect of which is a potential refund exposure to the While the rate-making process gives no recognition Company of $23 million. The Company has f!!ed an to the current cost of replacing property, plant and appeal with the Supreme Court of the State of Colorado.

equipment, based on past practices the Company believes it will be allowed to earn on the increased cost of its net investment when replacement of

12. Amount Subject to Refund facilities actually occurs.

WestGas is the defendent in lawsuits brought by two As shown in the following statement, income from gas producers who claim underpayment for gas continuing operations under the Current Cost method purchases under contracts containing " favored is lower than that determined under the historical cost nations" provisions. To protect WestGas in the event method used for the primary financial statements. Of of further claims under all contracts having similar the revenue and expense elements from which the provisions, the CPUC on September 7,1977 granted income figure is derived, only depreciation expense WestGas' application to increase rates subject to has been restated by applying the Company's deprect-refund. As of December 31,1984 and 1983 the amount ation rates to the indexed amounts of Current Cost at issue under all such contracts was approximately adjusted property, plant and equipment. All other

$30.7 million and $24.9 million, respectively, including income statement items are considered to have been interest, of which approximately $2.1 million had effectively transacted at average price levels for the accumulated prior to September 1977. In the event current year, and accordingly have not been restated.

that WestGas' position is not sustained and final Fuel inventories, the cost of fuel used in generation, settlement of these claims results in WestGas being and gas purchased for resale have not been restated responsible for additional costs for gas purchased prior from their historical cost in nominal dollars. Regulation to September 7,1977 WestGas will apply to the CPUC limits the recovery of fuel and purchased gas costs for rate relief to recover these costs.

through the operation of adjustment clauses or adjust-WestGas was also a defendant in a lawsuit brought ments in basic rate schedules to actual costs. For this by Amoco Production Company (Amoco) alleging under, reason fuel and gas inventories are effectively payment for gas purchases in accordance with the immetary assets.

natural gas purchase contract between the parties. The amount at issue at December 31,1984 and 1983 was estimated to be 86.5 million and $6.2 million, respec-tively, including interest, to Amoco and other parties having ownership interests in those wells. On February 5,1985 the United States Court of Appeals for the Tenth Circuit granted judgment in favor of WestGas.

43

Notes to Crnsolidat:d Financial Statements (continued)

As prescribed in FASB Statement No. 33, income been adjusted for inflation, is 93% using Current Cost taxes were not adjusted to reflect the effects of accounting for 1984, which exceeds the reported changing prices. This requirement is appropriate, since effective tax rate of 49% and the statutory rate of 49%

current income tax pohey ignores the effects of infla-for federal and state taxes.

tion in measuring taxable income and the higher All data reported "In Average 1984 Dollars" have depreciation expense experienced under Current Cost been restated to units of equivalent purchasing power accounting is not tax deductible. The Company's as measured by the average Consumer Price Index for effective income tax rate, when taxable income has All Urban Consumers for 1984.

Statement of Income from Continuing Operations Adjusted for Changing Prices For the year ended December 31,1984 Current As Reported /

Cost /

Illstorical Average Cost 1984 Dollars (Thousands of Dollars)

Operating revenues

$ 1,802,024

$ 1,802,024 Depreciation expense 96,883 230,994 Other operating expenses and other income and deductions 1,559,894 1,559,894 1,656,777 1,790.G88 Income from continuing operations

$ 145,247

$ 11,136 Effects of Changing Prices on Common Stockholders' Equity For the year ended December 31,1984 Current Cost / Avg.

1984 Dollars (Thousands of Dollars)

Current annual costs in excess of the historical cost of property, plant and equipment not recoverable in rates as depreciation expense under current regulatory policy:

Effects of cumulative inflation reported as an additional provision for depreciation expense

$134,111 Reported as an adjustment to net recoverable amount (Note A)

(45,422) 88,689 Excess of general price level changes ($185,437) in the current year over the specific price level changes ($ 182,039)*

3,398 Offsetting effect of debt financing (Note B)

(52,259)

Net erosion of common stockholders

• equity

$ 39,828

• At December 31,19H4, current cost of property, plant and equipment, net of accumulated depreciation, was 8 6,'29,H0 6, w hile historical cost (or riet cost recoverable through depreciation) was 82,355,164.

44

Note A. Adjustment to Net Recoverable Amount period of inflation, holders of monetary assets sustain a Under the CPUC and FERC rate-making provisions to loss of general purchasing power while holders of which the Company is subject, only the historical cost monetary liabilities experience a gain. The Company's of plant is recoverable in revenues as an amount equal

" Offsetting Effect of Debt Financing" is primarily at-to depreciation expense. Therefore, the portion of the tributable to the substantial amount of debt and pre-cost of plant stated in terms of Current Cost which ferred stock which has been used to finance property, differs from the historical cost of plant has been plant and equipment. (In calculating this gain, reflected as the " Adjustment to Net Recoverable preferred stock has been classified as a monetary item, Amount."

which is consistent with its treatment for rate-making purposes.) Such amount does not represent funds Nrte B. Offsetting Effect of Debt Financing (Gain available for distribution to shareholders.

From Decline in Purchasing Power of Net Amounts Owed)

To properly reflect the economics of rate regulation, This memorandum caption shows the net effect of the " Adjustment to Net Recoverable Amount" and the inflationary value changes on those Company assets

" Offsetting Effect of Debt Financing" should both be in-and liabilities carried on the balance sheet at fixed or cluded in the calculation of income from continuing determinable monetary settlement amounts. Du-ing a operations.

Five-Year Comparison of Selected Financial Data Adjusted for Effects of Changing Prices In Average 1984 Dollars (except "As reported" amounts)

Year Ended December 31, 1984 1983 1982 1981 1980 (Thousands of Dollars Except Per sharc Data)

Operating Revenues:

As reported

$ 1,802,024 51,628,641 81,590,039 81,336,171 81,155,644 Adjusted to average 1984 dollars 1,802,024 1,697,933 1,708,633 1,525,372 1,457,198 Income (loss) from continuing operations:

As reported 145,247 106,379 116,496 100,755 85,027 Adjusted to current cost i1,136 (22,234)

(11,944)

(18,961)

(20,654)

Income (loss) per common share (after dividend requirements on preferred stock):

As reported 2.55 1.86 2.17 1.97 1.92 Adjusted to current cost

(.11)

(.82)

(.65)

(.90)

(1.08)

Excess (deficiency) of increase in specific prices over changes in the general price level after adjustment to net recoverable amount 42,024 43,171 17,620 (73,241) (142,719)

Gain from decline in purchasing power of net amounts owed 52,259 51,326 69,404 123,455 167,903 Net assets at year-end at net recoverable amount 879,044 840,592 823,591 806,239 787,990 Cash dividends declared per common share:

As reported 1.92 1.84 1.76 1,68 1.60 Adjusted to average 1984 dollars 1.92 1.92 1.89 1.91 2.02 M:rket price per common share at year-end:

As reported 19.38 18.50 17.38 14.25 14.25 Adjusted to average 1984 dollars 19.06 18.93 18.23 15.61 17.13 Average consumer price index (nase year 1967 - 100.o) 311.2 298.5 289.6 272.6 246.8

N tes to CInsolidated Financial Statements (continued)

14. Quarterly Financial Data (Unaudited)

Summarized quarterly data (dollars in thousands except for per share amounts) for 1984 and 1983 are as follows:

1984 Three months ended March 31 June 30 September 30 December 31 Operating revenues

$ 587,067

$417,708

$ 348,786

$448,463 Operating income

$ 68,235

$ 43,631

$ 43,392 5 55,062 Net income

$ 52,210

$ 27,507

$ 27,499

$ 38,031 Earnings available for common stock'

$ 48,045

$ 23,342

$ 23,334 5 33,866 Average common shares outstanding (thousands) 49,538 50,129 50,736 51,359 Earnings per average common share *

$0.97

$0.47

$0.46

$0.66 1983 Three months ended March 31 June 30 September 30 December 31 Operating revenues

$ 525,132

$ 409,505

$302,424

$391,580 Operating income

$ 52,025 5 43,511 5 39,499 5 44,460 Net income

$ 34,080

$ 24,988

$ 21,484

$ 25,827 Earnings available for common stock *

$ 29,915

$ 20,823

$ 17,319

$ 21,662 Average common shares outstanding (thousands) 47,310 47,797 48,426 49,007 Earnings per average common share'

$0.63

$0.44

$0.36

$0.44

• Due to rounding. quarterly figures do not add to annual total.

Report of Certified Public Accountants The ik)ard of Directors and Shareholders Public Service Company of Colorado We have examined the accompanying consolidated in our opinion, the statements mentioned above balance sheets of Public Service Company of Colorado present fairly the consolidated financial position of and subsidiaries at December 31,1984 and 1983, and Public Service Company of Colorado and subsidiaries the related consolidated statements of income, retained at December 31,1984 and 1983, and the consolidated earnings and source of funds for plant construction results of operations and source of funds for plant expenditures for each of the three years in the period construction expenditures for each of the three years ended December 31,1984. Our examinations were in the period ended December 31,1984, in conformity made in accordance with generally accepted auditing with generally accepted accounting principles applied standards and, accordingly, included such tests of the on a consistent basis during the period.

accounting records and such other auditing procedutes as we considered necessary in the circumstances.

M/g f(

Arthur Young & Company Denver, Colorado February 8,1985 46

Bo:rd of DirectIrs and Officers Board of C. Keith Millen Executive J. Kenneth Fuller Directors Denver, CO (1969)

Committee Vice President, Electric Senior Vice President, Engineering and Robert T. Person Oper ions "E

Robert T. Person ge g (36)

Denver, CO (1957) 8 Richard F. Walker Chairman of the Board Will F. Nicholson,Jr.

George B. McKinley John M. Hassoldt Age 70 Denver, CO (1981)

Will F. Nicholson, Jr.

Vice Picsident, Gas Richard F. Walker President Nicholas R. Petry Operations Colorado National Age 55 (34)

Denver, CO (1976)

President and Chief Bankshares, Inc.

Audit Committee Delwin D. Hoc *4 Executive Officer Age 55 Vice President.

Age 60 Bryant O'Donnell Doris M. Drury Accounting and

• Fa ey Secretary Ullliam T. Blackburn Den er, CO 1972) p9 Denver, CO (1965) and General Counsel Resident Partner Executive Officers Oscar R. Lee,Jr.

Vaughey, Vaughey &

Age 59 Vice President, Electric Blackburn (Independent Nicholas R. Petry Robert T. Person Production Oil Producers)

Denver, CO (1961)

Chairman of the Board Age 58 (34)

Age 68 Chairman of the Board Age 70 (47)

Robert T. Person,Jr.

Keith L. Brown Petry-Vappi Vice President, Public Denver CO (1984)

Construction Company Richard F. Walker Affairs President Managing Partner of President and Chief Age 42 (13)

Brown Investment N. G. Petty Construction Executive Officer Corporation Company Age 60 (35)

James II. Hanniger A e 66 Vice President, Rates 8

Bryant O,Donnell Age 59 and Regulations Doris M. Dru#Y' PhD J. Michael Powers Executive Vice President Age 48 (26)

Denver, CO (1975)

Cheyenne, WY (1978) and General Counsel President Age 59 (34)

( ) Denotes years of service University of Denver with the Company through Professor of Economics Powers Builders, Supply C. Keith Millen December.1984 Chairman, Center for Age 42 Senior Vice President, A es a of December 31,1984 E

Business and Economic Jack W. Rouse Operations Forecasting Denver, CO (1982)

Age 62 (38)

Age 58 Senior Vice President.

Jack W. Rouse Thomas T. Farley Utility Services Senior Vice President, Pueblo, CO (1983)

Age 64 Utility Services Attorney at Law

( ) Year ciected to the Board

^b

}

Petersen & Fonda of Directors James N. Bumpus Professional Corp.

Ages a of December 31,19H4 Vice President, Finance Age 50 and Treasurer George B. McKinley Age 50 (20)

Denver, CO (1976)

Ronald E. Donovan President and Chief Vice President, Division Executive Officer Support Services Central llancorpor-Age 57 (30) 3 ef7 Clark B. Ewald Vice President, Employee Relations Age 50 (25)

Board of Direct:rs and Officers (continued)

Other Officers

Managers, N. James Temple,Jr.

Legal Counsel Western Geographic Dan McNellis Divisions Manager, Westem Kelly, Stansfleid &

Region O'Donnell Assistant Vice President ABC (38I Denver, Colorado Governmental Affairs N. Keith Coombe Age 56 (32) liigh Plains Robert J. Vidick Age 56 (32)

Northwest Metropolitan Auditors Richard R. Midwinter Age 57 (29)

Controller and Assistant Robert J. Fairchild Arthur Young &

Secretary Front Range

Managers, Company Age 59 (35)

Age 63 (45)

Subsidiary 70717th St., Suite 3800 Dale V. Fetchenhler Ronald L. French Companies Denver, Colorado Assistant Secretary Pueblo Age 51 (27)

Manager, Southern James N. Bumpus Transfer Agents

'8 "

President and Registrars for Richard C. Kelly Age 57 (32)

Bannock Center Corp.

All Issues of Assistant Secretary Age 38 (17)

Roas C. King,Jr.

Age 50 (20)

Capital Stock CUVCf M I*P II 8" Clark B. Ewald Steven R. Loeshelle

^8 43 (I9)

President Principal Transfer Agent, Issistant Secretary and Assistant Treasurer Douglas C. Lockhart 1480 Welton Dividend Paying Agent, Mountain Age 50 (25)

Dividend Reinvestment Age 35 (3' Plan Agent Age 42 (20)

Michael J. Gelle Public Service John E. Martin Assistant Secretary Robert E. Moninger Vice President and Company of Colorado Age 61 (36)

Northern General Manager Denver, Colorado Age 64 (37) llome Light & Power Glenn M. Steepleton Company Registrar M. Gordon Parker Age 42 (20)

Central Bank Assistant Secretary Age 61 (10)

Southeast Metropolitan Age 62 (35)

John M. Ilassoldt of Denver Richard L. Ilunt President Denver, Colorado Lawrence F. Petrini Assistant Treasurer Western Gas Supply Northeast Metropolitan Company Co-Transfer Agents and Age 42 (18)

A 54 (29)

Age 55 (34)

Co-Registrars Susan G. Pollack Wallace K. Reed rgan Guaranty Assistant Treasurer James L. Illgday Trust Company of Boulder Age 40 (13)

President

• • YU' Manager, Foothills Cheyenne Light, Fuel Douglas S. Robertson Region New York, New York Assistant Treasurer Age 60 (38)

1. hohe Bank of America e

National Trust and Age 42 (6) llarold L. Rust Region Savings Association llomer R. Sessions Platte Valley Age 62 (34)

San Francisco, California Assistant Treasurer Age 49 (29)

Robert F.Jonas

. services as Co-Transfer Agent Age 59 (7)

George A. Senkus President and Co Registrar terminated San Luis Valley Fuel Resources effective March 1,19H$

Age 48 (17)

Development Co.

^N Louis W. Supancic Southwest Metropolitan

( ) Denotes years of wrvice Age 62 (33) with the Company through December,19H4 Ages as of December 31,19H4 48

Please take a few minutes to complue and return the concerns our upcoming regional shareholder meetings postage-paid, self-addressed cards below. The top card is and how to get additional information about the Com-a brief survey which will help us make our communica-pany or your investment.

tions with you as effective as possible. The bottom card Shareholder Communications Survey 1

1984 Annual Report Quarterly Reports

1. flow much of PSco's 1984 Annual Report did you read?

5. Ilow much of PSCo's Quarterly Reports do you read?

O all O % to %

0 all O less than %

0 % or more O tess than %

O more than %

O none O % to %

O none

6. liow would you describe the Quarterly Reports reada-

2. Is the 1984 Annual Report easy to read and understand?

bility?

O very readable O somewhat difficult O very readable O somewhat difficult O somewhat readable O very difficult O somewhat readable O very difficult

3. Please circle the number which represents your feelings

7. Please rate the PSCo 1984 Quarterly Reports by circling about the quality of information, presentation, and reada-the number below which best describes your overallim-bility of the following:

pression:

Outstanding Poor Outstanding Poor Corporate Purpose 1 2 3 4 5 6 7 8 9 10 overall, I felt the 1984 1984 in Retrospect i 2 3 4 5 6 7 8 9 10 Quarterly Reports were - 1 2 3 4 5 67 8 9 10 Management Commentary 1 2 3 4 567 8 9 10 Financial Performance 1 2 3 4 567 8 9 10 Financial Charts 1 2 3 4 567 8 9 10 Corninunications Progratns Electric operations 1 2 3 4 56 7 8 9 10 Natural Gas operations 1 2 3 4 5 6 7 8 9 10

8. Ilow would you describe PSCo's shareholder and shareholder Information 1 2 3 4 5 6 7 8 9 to investor relations programs?

operating & Financial Data 1 2 3 4 5 67 8 9 i O very good O adequate

4. Please rate the overall PSCo 1984 Annual Report by O good O inadequate circling the number below which best describes your over-

9. Do you feel you are being adequately informed about all impression:

PSCo activities?

overall, I feel the 1984 0 yes O mostly O notemkely 0 no Annual Report is -

1 2 3 4 5 6 7 8 9 10

10. What is your Zip Code?

Regional Shareholder Meetings Public Service Company of Colorado will continue to Additional Infortnation and Duplicate Mallings hold regional shareholder meetings and participate in Shareholders interested in receiving the publications or Investors Fairs through the National Association of additional information listed below, or those who re-Investment Clubs in 1985. Invitations to attend these meetings will be sent to shareholders who own Pubhc ceive duplicate mailings of the Annual Report, are asked Service Company stock in their name and who live to check the appropriate box, Fill in account number, within a 50-mile radius of the cities listed below.

name and address and mail this postage paid card.

O Statt tical Review 1974-1984 Shareholders are welcome to bring guests to the meetings. If you wish to attend a meeting and do not O Dividend Reinvestment Plan Information receive an invitation, please complete and return this O Currently receive more than one copy of Annual card indicating the meeting (s) you wish to attend. We Report. Please climinate report mailings for (fill in account will send you the materials necessary for admittance.

number (s) from Annual Report mailing label):

Regional shareholder meetings will be held in the following areas on the indicated dates:

O Morristown, NJ. -June 18 O New York City -June 19 0 llartford - september Ph's Prtim O lloston - september O san Francisco - November Name O Phoenix - November National Association of Investment Clubs Investors Fairs Street and Number will be held as indicated below:

O Milwaukee - March 30 City C Kansas City - May 11 O omaha -June i State Zip l

.~.

0 NO POSTAGE NECESSARY IF MAILED IN THE UNITEDSTATES BUSINESS REPLY Mall FIRST CLASS PL".MIT NO. 265, DENVER CO r

1 POSTAGE WILL BE PAID BY ADDRESSEE Public Service Company of Colorado i

Investor Relations, Room 1040 P.O. Box 840 Denver, CO 80201-9958 m

I NO POSTAGE NECESSARY IF MAILED IN THE I

UNITED STATES

.+

BUSINESS REPLY MAIL FIRST CLASS PERMIT NO. 265, DENVER CO l

M POSTAGE WILL BE PAID BY ADDRESSEE Public Service Company of Colorado m

l Investor Relations, Room 1040 P.O. Box 840 i

N Denver, CO 80201-9958 M

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publi$ Service Company FOdas6e 16805 WCR 19 1/2, Platteville, Colorado 80651 March 18, 1985 Fort St. Vrain Unit #1 P-85090 Director of Nuclear Reactur Regulation Division of Project Management U.S. Nuclear Regulatory Commission Washington, D.C.

20555 ATTN: Mr. Roger S. Boyd, Director Docket No. 50-267

SUBJECT:

Public Service Company of Colorado 1984 Annual Report

Dear Mr. Boyd:

Enclosed are eight copies of the 1984 Public Service Company of Colorado Annual Report which are being submitted for your information and use per Regulatory Guide 10.1 and Title 10, Code of Federal Regulations, Part 50.

I Sincerely,

/

s J. W. Gahm Manager, Nuclear Production Fort St. Vrain Nuclear Generating Station JWG:dr Enclosures y(.'4