ML19347D294

Rept on Results of Operation of San Diego Gas & Electric Co,Electric Dept,Test Yr 1981

ML19347D294
Person / Time
Site:	San Onofre
Issue date:	09/08/1980
From:	CALIFORNIA, STATE OF
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Text

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5. C.

O CALITORNIA PUBLIC UTILITIES CONGSSION Revenue Requiretents Divisics t

R D ORT ON THE RESULTS OF OPERATION

.W.,

SAN DIE 0 GAS & l!LECTRIC CCNPANY ELECTRIC DDARTMI!NT TEST YEAR 1981 Application No. 59788 l

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San Francisco, California September 8, 1980 l

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TABLE OF CONTEITS i

Chart Table Page No.

No.

Title No.

' APT!E 1 - INTRCDUCTICN CHAPERS 2 and 3 - HISTCRY AND PRESEIT CPIRATICNS CHAPTERS 4, 5, and 6 - BALANCF SHEETS, i

STATDENTS OF INCCHE, RETAINED EARNING A:D C1 EARING ACCOUNTS CHAPTER 7 - ELICTRIC CPIRATING PEm;UES l

7-A Revemos at Present Rates - - - - - - - - - - -

7-4 7-B Reverales at Proposed Rates 7-5 7-C Sales - - - - - - - - - - - - - - - - - - - - -

7-6 7-D Customers - - - - - - - - - - - - - - - - - - -

7-7 7-E Miscenaneess Revenues 7-8 7-A Tota,1 Residential Sales 1972-1981 7-9 4

i 7-B Residential Sales Per Customer 1972-1981 7-10 i

7-C Coomarcial Sales 1972-1981 7-H 7-D Indur, trial Sales 1972-1981 7-12 7-E other nectric Sales 1972-1981 - - - - - - - -

7-13 CHAPTER 8 - PRODUCTICN EXPE3SES 8-A Susanary of Production Expenses ?-1"d4ng IEAC -

8-5 8-B Production Ex;y nses 7-ind4ng ICAC - Steam Power Production -

8-6 8-C Production Expenses ExclnM "5 IEAC - Nuclear Power Production - - -

8-7 8-0 Production Expenses Excluding ICAC - Gas Turbine and Other Power Supply Expenses 8-8 8-E Nan-ECAC Puel Expenses - - - - - - - - - -

G-9 CHAPT!R 9 - UtANSHISSIQi EIPENSES 9-A Tran=4 asicut Expenses - - - - - - - - - - - - -

9-5 CHAPT!R 10 - DISTRIBUTICN ZIPENSES lo-A Distributican Expenses - - - - - - - - - - - - -

10-7 CHAPTER H - CUSICMER ACCOUNTS EIPDISES n-A Customer Accounts Expenses - nectric Department E-4 I

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TABLE OF CCNIENIS (Contimed)

Chart Table Page No.

No.

Title No.

CHLP M t 12 - CUST. S E 7 ICE AND l

INPCRMATIONAL EIPERSES 2

12-A Marketing Expenses - - - - - - - - - - - - - -

12-4 CHAPGt 13 - ADMINISULATI7E AND GDEAL EIPENSES 13-2 13-A WMatrative and General Expenses 4

CHAPMt 14 - CPIRATING TAIES 14-A Sg of Tax hpanes - - - - - - -

14-10 14-B Taxes Based on Income 11.-11 IM Deductions for Tax Calculations - - - - - - -

1A-12 CHAPMt 15 - EIEULIC PIANT 15-A Electric Plant 1980 15-3 15-4 15 4 Electric Plant 1981 CHAPTER 16 - DEPPEIATION EXPENSE 16 A Depreciati m M

CHAPMt 17 - RATE BASE 17-4 17-A Weighted Average Rate Base - - -

17 4 Working Cash Allowance Study - - - - - - - -

17-9 CHAPTER 18 - SUEAKI 0F ltARNTM@

18-A Samary of Zamings at Present Rates - 1981 - -

18-4 18-5 18-0 Sumary of Earnings at Proposed Rates - 1981 CHAPTER 19 - JURISDICTICNAL CCST AIECATICN

- Cost Allocation Sumary, Test Year 1981 19-A SDG6E Present Ratas - - - - - - - - - - - - -

19-2 19.B Cost Allocatim Samary, Test Year 1981 SDG&E Proposed Rates - - - - - - - - - - - -

19-3 19-4 19-C Staff Tax Nalmi ations - - - - -

CHAPMt 20 - RIC0teENDATICNS

MEMORANDUM This report was prepared by the Revenue Require:nents Division staff under the direction of Project Manager Francis S. Ferraro. Individual chapters were prepared by the following members of the staff:

Chapter Title Vitnesses l

1 Introduction Francis Ferraro 2 and 3 History and Present Operations See Company Report 4, 5 and 6 Balance Sheet, Statements of Income and Retained Earnings and Clearing l

Accounts Gilbert Infante 7

Operating Revenues Sandy Miller 8

Production Expenses Harold Rayburn 9

Transmission Expenses Harold Rayburn 10 Distribution Expenses Harold Rayburn 11 Customer Accounts Expenses Paul Chan 12 Cust. Service and Informational Expenses David Barnhardt 13 A&G Expenses Donald McCrea Pensions Sandy Miller R&D Ramesh Joshi i

14 Taxes - Ad Valorem and Payroll James Bondeson Income Greg Mulligan 15 Electric Plant Willem Van Lier 16 Depreciation Expense Kevin Couglan 17 Rate, Base _.

Willem Van Lier Working Cash Allowance Sung Han 18 Sununary of Earnings Francis Ferraro 19 Jurisdictional Cost Allocation Donald McCrea 20 Reconnaendations Francis Ferraro p7

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4' CHAPTER 1

[

INIRODUCTICN i

A - PURPOSE OF REPORT 1.

The purpose of this report is to provide infor: nation for the Commission and interested parties on the operations and earnings of San Diego Gas & Electric i

Company (SDG&E). This report is prepared in response to the utility's Application i

No. 59788, filed July 1,1980, for a general rate increase for the Electric l

Department of $126.6 million or 13.2%. The application requests an 11.44% rate or return and a 14.5% return on comanon equity in the test year.

l 2.

In Decision No. 90405, dated June 5,1979, in Application No. 58067 (applicant's last general rate proceeding), the utility was granted a rate of return of 10.59% aril a return on equity of 14.50% for test year 1979.

l B - SCOPE OF REPORT 3.

The report includes a sunnary of the utility's system electric operations for the test year 1981. Also included are chapters and analyses of operating l

revenues, expenses, taxes, utility plant and depreciation. Chapter 4, Chapter 5, and Chapter 6 on Balasce Sheet, Income Statement, and Clearing Accounts will be covered separately in the Report on the Results of F-4 nation of San Diego Gas &

Electric Company. - Chapter 18, Sumury of Earnings, contains a comparison of the 1

staff's an( stility's estimates at present rates and at utility proposed rates, of net revenues, rate base, and the rate of return for the test year 1981.

4.

Differences between the staff and the utility's estimates for test year 1981 are indicated in succeeding chapters of this twport. The report also explains the reasons for these differences.

5.

A comparison of the staff's and utility's estimated rates of return based on respective results of operation is as follows:

Rate of Return P

)

Present Rates : Proposed Rates :

Item 1981 1981 Utility 3.48%

11.44%

Staff 8.51%

14.86%

2 1-1 b

+

s+m,

1 - INTRODUCTION 6.

In connection with the staff's presentation in this proceeding, the Utilities Division will present reports covering electric rate design and conservation. 'Ihe Financial Analysis staff of the Revenue Requirements Division will also present reports on results of examination and rate of return.

7.

Both the utility and the staff have developed estimates assuming a 9.5% wage increase for the year 1980 and 13.5% for test

• year 1981. For expenses other than labor, the staff and utility have used a 107. inflation rate for 1980 and 1981. Explanation of the staff's wage adjust:nent is contained in the general report.

8.

Consistent with the Consnission's recent decisions in general rate proceedings, staff's revenues and expenses exclude all direct ECAC energy costs.

Also excluded are the variable portions of wheeling expenses and Depart:nent of Water Resources expenses which, in the OII-56 hearings, the staff has recomended be included in ECAC. The cogany's exhibit shows results both with and wittmut 5CAC revenues and expenses.

9.

Consistent with the Conmission's treat:nent of PG&E's Diablo Canyon reclear facility, this report has excluded all expenses and rate base associated with the company's construction of San Onofre Units Nos. 2 and 3 (SONGS 2 and 3).

It is anticipated that when these facilities are ready for operation, a separate proceeding will be instituted for the purpose of establishing rates.

10.

All of the accounting adjust:nents contained in the Financial Analysis staff's " Report on the Results of Examination of San Diego Gas & Electric Company" have been utilized in developing the estimates contained in this report.

1/ Decision No. 91107, dated December 19, 1979, in Application No. 58545.

1-2

l CHAPTER 2 HISTdRY 1.

The last previous detailed study of the Electric Depart:nent of the t

l San Diego Cas & Electric Company was prepared by the staff in connection with i

• ^

Application No. 58067. This study covered results of operations for the test l

year 1979.

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i CHAPTER 3 l

.PRESDIT OPERATIONS 1.

In the company's application is contained a description of corporate information. To the extant that the :natorial in the utility's application is l

adequate for the purpose, it has not been duplicated in this report.

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CHAPTER k - SALANCE SHEET ACCOUNTS CHAPTER 5 - INCCME STATME:1P ACCOUICS CHAPTER 6 - CLEARING ACCOUNTS FINANCIAL ANALYSIS AUDIT 1.

An independent audit by the professional staff accountants of the Revenue Requirements Division, Financial Analysis Group, was conducted in conjunction with this rate proceeding. The stafr accountants prepared a separate report on the results of this independent analysis of San Diego Gas & Electric Company and its subsidiary operations.

2.

The staff accountants coordinated the audit recomnendations discussed below with the staff engineers for consideration in the preparation of their test year estimates.

3 The " Report on the Results of Examination of San Diego Gas & Electric Company contains the following recommendations made by the staff accountants.

A.

Exclude $9,250,970 frem Account 105, Utility Plant Held for Future Use, relating to the two South 3ay gas turbines for rate-making purposes.

3.

Exclude $151,179 of excessive Allowance for Funds Used During Construction (AFUDC) charged to Work Order No. 5071000 during the period October 1976 through August 1978 on SDG&E's books of account in Account 107, Construction Work in Progress.

C.

Gains or losses resulting from the future sale of property in the amount of $5,36k,372 nov recorded in Account 121, Non-Utility Property, which was previously recorded in Account 105, Utility Plant Held for Future Use, should be recorded "above the line" in Account 411.6, Gains From Disposition of Utility Plant, or Account h117, Losses From Disposition of Utility Plant.

D.

SDG&E should not be allowed to recover through base rates

$596,755 representing the base rate component of lifeline refunds nquired due to the overcharging of lifeline customers in prior years.

h-1 3-1 6-1

l 4, 5 APO 6 - FINANCIAL ANALYSIS AUDIT i

E.

Recognition should be given to the effects the Gas Meter Antitrust Litigation Refund of $193,688 vill have on the 1981 test year accumulated provision for depreciation of Gas Utility Plant.

F.

Goodwill and Educational Tours' recorded amounts of $1,602 for 1978 and $715 for 1979 should be excluded fro = cperating i

expense for rate-=1 ring purposes.

G.

Dues, Donations and Contributions of $5,691 (gas) and $68,083 (electric) for 1978 and $20,452 (gas) and $106,748 (electric) for 1979 should be excluded from operating expense for rate-

= H ng purposes.

H.

Any effect on base rates resulting from the staff's investigation into the fuel oil exchange between SDG&E and thited Petroleun Distributors should be deferred until SDG&E's 1982 test year filing.

I.

Electric Credits given to Applied Energy, Inc. for fuel should be calculated at the average system cost per megawatt-hour for i

steam generation only.

J.

The Kaiparawits coal reserve of $4,009,920 on New Albion Resources Company's (NARCO) books should be amortized through i

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EEDA to ECAC. NARCO began amortizing the Kaiparawits coal i

reserve project costs July 1,1980.

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CHA?"ER 7 FI G UES 1.

The Electric tepartment revenues are derived prd-=*ily free the sales of electricity to its residential, nonresidential, and resale custccers. Minor amounts of revenue are generated from service connection fees, rents, and other miscellaneous categories.

The following table ecuspares sta'f and utility base revenue esti=ates1/

2.

for test year 1981 at present rates and utility proposed rates.

Estimated Total Revenues

Utilit/ Exceeds Staff :

Item Staff

Utility Ancunt

Percent :

(Collars in Thousands)

Present Rates

$296,6k7 3

$262,943.o

$(13,704 3)

( G )5 Proposed Rates h31,135.6 ho9,573 0 (21,5o2 o)

(5.0)

Increase in Revenues 13h,488.3 126,630.o (7,55o.3)

(U)

(Red Firure) 3 A detail of these revenue esti=a:es is provided in Tables 7-A and 7-3.

h.

Underlying the differences in estimates are the sales forecasts for the individual sales categories. Table 7-C presents sales estimates by class of customer. Charts 7-A through 7-E are included at the rear of this chapter to illustrate the recorded sales and projected sales estimates by staff and utility for the residential, coccercial, industrial, and agricultural and street lighting customers.

M Revenues are shown on a ::ero fuel basis, i.e., ICAC-related revenues are excluded.

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7 - REVE:iUES Residential 5

The staff's esti= ate of residential sales in test year 1931 is 326.3 gigawatt-hours (owh) higher than the company's esti= ate of 3,968.23 owh.

3:th forecasts utilize econemetric models which estimate historical statistical relationships between sales and economic and noneconomic variables. After these relationships have been developed, sales are esti=ated into the test a

year based en assumptions about what the econo =ic and noneconomic variables are going to do.

6.

The staff has accepted as reasonable the utility's assu=ptions about the " independent" variables that were used by the staff in its forecasts.

7 A major difference between staff and utility exists in the structures of the models. The staff utilices quarterly data en total residential sales from 1966:1 through 1980:1 to develop its forecasting equation. The utility relies on quarterly data on residential sales per customer frc= 1960:1 through 1930:1 to develop its forecasti'ng equation. The staff decided to use total sales instead of sales per customer, because it is felt that total sales is a little less volatile than sales per customer and, therefore, could be predicted with more certainty.

l Cocusercial (General Service; General Power)

Industrial Other ( Agricultursl Puc: ing; Street Lid: ting) 8.

The sta.ff estimates higher sales (and therefore higher revenues) f in all of these categories compared to the company's estimates. 3cth forecasts use econometric models 'dcch attempt to esti= ate sales as a function of a variety of economic and 7.cneconomic variables. The types of variables l

each forecast is built on are different, however, in each model. An i=portant l'

difference between models is the estimated effect on sales caused by the price of electricity. Contrary to the findings of the utility, the staff price of electricity has ' et significantly affected has not found that tbr, f

l sales trends. Certainly, it can be stated that sales is deter =ined by =any factors including price, the general economic climate of a region, and the 7-2

r 7 - REVZmES ability by custecers to pass en their increased energy costs in the prices of their final products (e.g., the California energy utilities directly pass on their increased energy costs without risk to their rates ef return).

Unless the co=petitive charpeteristics of these cust0=ers can be de=costrated to be a function of the price of electricity, it is not a foregene conclusien that an increase in electricity prices vill result in a drop in electricity de=and. Therefore, the staff believes its esti=ates are =cre realistic than the utility's estimates.

Cust0=ers 9

The staff and utility forecasts of custo=ers are presented in Table 7-D.

The differences between staff and utility esti=ates are due te differing =ethodolegies. The staff bases its esti=ates en the recorded relationship between custe=ers and county pcpulation and the county pcpulatics projections by the State Depart =ent of Finance. The ec=pany ties its esti=stes to building permits which, in turn, rely en interest rate forecasts.

Miscellaneous Revenues 10.

Staff and utility esti=ates of these revenues are presented in Table 7-E.

Staff esti=ates for Accounts h51 and h5h are $53,000 and 592,000, respectively, higher than the utility esti stes. Account h51 revenues are higher because the staff uses a higher growth rate (which is the staff's growth rate in customers) than the gr vth rate the utility uses. Revenues frc= Account h54 are higher than utility revenues because the staff ec_ bines all revenues except Sundesert rent revenues and escalates these based en the aversge growth frc= 1975-1979 The ec=pany uses a five-year aversge. The staff accepts as ressenable the ce=pany's esti= ate of rental ince=e ($367,000) fr0= its Sundesert properties.

11.

The staff excludes the ec=pany's esti= ate of non-ECAC lifeline i

refunds frc= =iscellaneous revenues as recc== ended by the Finance Divisien.

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7A BLE 7-A 50GE--ELEC TRIC DEPT REVENUES AT PRESENT RATES TEST YEAR 1981 LN ACCT.

UTIL. EXCEEDS STAFF CO NO ITEM STAFF UTILITY AMOUNT PCT (A)

(8)

(C)

CD)

(THOUS ANDS OF DOLLARS) 1 RESIDENTIAL 3124497.3 $ 115374.0 3-9123.3

-7.3 2

GENERAL SERVICE 104272.6 101936.0

-2336.6

-2.2 3

GENERAL POWER 6496.7 6312.0

-184.7

-2. 8 4

INDUSTRIAL 44838.8 43917.0

-921.8

-2.1

' 5 AGRICULTURAL POWER 4379.5 3986.0

-393.5

-9.0 6

STREET LIGHTING 4033.4 3644.0

-389.4

-9.7 7

RESALE 682.0 682.0 0.0 0.0 8

OTHER SALES TO PUB AUTH 17.0 17 0 0.0 0.0 9

8ASE REV FROM CUST 289217.3 275868.0

-13349.3

-4.6 10 MISCELLANEOUS 7430.0 7075.0

-355 0

-4.8 11 REVENUES 296647.3 282943.0

-13704.3

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TA BL E 7-8 l

SOGE--ELEC TRIC OEPT REVENUES AT PROPOSED RATES TEST YEAR 1981 Lh ACCT.

UTIL. EXCEEDS STAFF NO NO ITEM STAFF UTILITY AMOUNT PCT (A)

(B)

(C)

(0)

(THOUSANDS OF DOLLARS) l 1

RESIDENTIAL, 8 179150.4 3 165421.0 3-13729.4

-T.7 2

GENERAL SERVICE 147677.4 144243.0

-3434.4

-2.3 3

GENERAL POWER 9207.4 8938.0

-269.4

-2.9 4

INDUSTRIAL 75527.8

~2827.0

-2700.8

-3.6 5

AGRICULTURAL POWER 6457.2 5865.0

-592.2

-9.2 6

STREET LIGHTING 4986.4 4505.0

-481.4

-9.7 7

RESALE 682.0 682.0 0.0 0.0 8

GTHER SALES 70 PUB AUTH 17.0 17.0 0.0

0. 0 9

TOTAL BASE REVENUE FROM CUS 423705.6 402498.0

-21207.6

-5.0 10 MISCELLANEQUS 7430.0 7075.0

-355.0

-4.8 11 REVENUES 431135.6 4i9573.0 21562.6

-5.0

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i TABLE 7-C San Diego Gas & Electric Cc=pany Total Sales - Electric Depart =ent (Millions of Kilowatt-heurs)

Test Year 1981

Utility Exceeds Staff :

Class of Serv'ee Staff

Utility : A=ount

Percent k,29.60 3,968.28 (326.32)

(7.6) h Residential General Service 3,h00.00 3,313.80 (86.20)

(2.5)

General Power 213.00 206.3h (6.66)

(3.1)

Industrial 2,hho.75 2,299.77 (1h0 93)

(5.8)

Agricultural Power 16h.31 148.60 (15.71)

(9.6)

Street lighting 74.66 67.63 (7.23)

(9 7)

Resale 5h.29 5h.29 0

0 Other Sales to Public Authority 275.57 275 57

.0 C

Total 10,917.38 10,33h.28 (583 10)

(5.3) 7-6 a

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TA21E 7-D j

San Diego Gas & Electric Cc=pany Electric Depart::mnt AVERAGE CUSTC.VIRS Test Year 19c1

Utility F.xceeds :

Staff Class of Service

Staff

Utility : A= cent : Fereent :

Re.sidential 714,3kk 715,736 1,392 c.2%

General Service 70,702 71,107 405

.6 General Pcwer 3,532 3,532 0

0 Industrial 275 275 o

o Agricultural Pcwer 3,275 3,275 o

o Street Li hting 916 916 0

0 6

- Resale 5

5 0

0 Other Sales to Public Authority 1

1 0

0 Total 793,050 794,ch7 1,797

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TABLE 7-E San Diego Gas & Electric Company Electric Department MISCELIANEOUS RE'F."._.

Test Year l"31 (00C) l

Line:

Utility Exceeds Staff :

l

No. Account:

Description

Staff Utility : Amount : Fercent :

1 h11.6 Gain en Disp. of Plant 2

451 Misc. Service Revenues

$3,052

$2,999 (53)

(1.7) 3 454 Rent 1,239 1,140 (99)

(8.0) 4 456 Other Electric Revenues 3,139 3,139 0

0 5

Non-ECAC Lifeline Refund 0

(203)

(203)

(>100.0) 6 TOTAL

$7,430

$7,'075 (355)

(k.8)

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o Chart 7-A Sin Diegs Gas and El:ctric Company Qu rterly Total ResidentJal Electric Sales Total S les Recorded and Estimated (cwit Th {ll' 3

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Chart 7"B San Dieg3 Ga3 and Electric Company Quarterly Residential Electric Sales / Customer Seies/custaner Her.orded and Estimated (kWh) f

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CFXfER 8 PRODUCTION EXPENSES 1. Electric production expenses include expenses incurred in the operatien and maintenance of the utility's stea=-electric, nuclear, and combustion turbine generating facilities, including such ite=s as syste= contrcl and lead dispatching, and purchased pover. 2. The staff's estimates were made using infor=ation gathered through discussions with the utility, field trips, and analysis of recorded data. Tables 8-A through 8-E compare the staff's and the utility's estimated expenses for the 1981 test year. Both shovings have excluded expenses associated with the Energy Cost Adjustment Clause (ECAC). A seey of the staff's and utility's esti=ates is shcvn belev: Production Iapense Estimates Utility Ite Staff Utility : Exceeds Staff: (Dollars in Chcusands) Non-fuel Related $h9,159 0 $h9,733 0 57h.0 Fuel Related 3,131.7 lh,031.7 10,000.0 Totals: 52,290 7 63,76L.7 ll,h7h.0 3 San Diego's generating system, as of Dece= der 1979, consisted of fcur stea=-electric generating plants (13 units - generating capacity cf 2,039 W ), a 2C% share of Southern California Edison's San Onofre Nuclear Plant (90 W), and 20 combustion turbines, for a total generating capacity of 2,h92 W. The utility also receives and exchanges energy and capacity with other utilities. h. Sixteen of the cocbustien turbines are used for peaking purposes and the remaining four are base loade:1 for cogeneration: Naval Station, Naval Training Center (NTC), North Island Unit 2, and Rchr Industries. North Island Unit 2 vent -into ecseneration service in October 1978, Naval Station beca:e operational in December 1978, and Rohr Industries began ecc:cercial cperation in February 1979 5 The majority of the utility's estimates ven based upon nine-year trends, 1971 through 1979 (11 months recorded,1 month estimated), cf histerie costs, adjusted to recove unusual or non-reocurries expenses. These forcasted figures 8-1

i 8 - PROUirTION DGINSIS vere then escalated to 1981 dellars - the labcr pcrtien by 9 5% (effective Feb:.:ary 1960) and 13 5% (effective. March 1981), and the ncn-laber pertion by 104 per year for 1960 and 1931. Atture years' ncn-trendable expenses were added to these projected costs. Exceptiens were as follows: the everhaul subacccunts, the lead dispatchi::g acccunt, and the rent ex;ense acecunt were zero base esti=ated; the nuclear expense esti=ates vere based upcc infc: :ation previded by SCZ; and the fuel-related non-ECAC expenses were esti=ated based upon anticipated expenditures in 1981. Stes:-Electric (Acccunts 5co-514) 6. he staff revieved the reasonableness cf the utility's trends cf the recorded / adjusted ecsts and found the estinates, excluding unusual expenses, fer all steam-electric non-fuel operation and rnintenance acccunts to be reascnable (Accounts 5c0, 5c2, 5ck, sc5, 510, 511, 512.1, 513 1, and sik). ':his was based upon aralysis of recent charges since Incina L51t 5 beca=e operational in November of 1978. 7 Ncc-trendable future year's additiens to the varicus acecunts were also analyzed. Differences between the staff's and the utility's estinates are discussed in the folleving paragraphs. Acecunt 500 (Air Envirc:r. ental Expenses) 8. he utility has included $75,000 in its 1961 as-expected year esehte for a=bient air quality =cnitcring in the Scuth County area. This expense is associated with the siting cf gas turbines in the 5cuth Say area. He staff has re=cved this cost frora the 1981 as-expected year esti:nate, to be consistent with the staff's treat =ent of the gas turbines in plant held for. future use. (Refer to Chapter 15 - Electric Plant.) 9 me staff's test y_ar adjus ent reflects a five-year a=crtizatica cf the expected air envirec= ental expenses for 1960 and 1981, censistent with the treatment given these expenses in Decisico No. 9CkO5 for SJG&I's 1979 test year Application No. 58067 Se staff's adjust =ent results in a test year estinate of $1h1,00C, which is $16k,500 lever than the utility's estimate. 8-2

8 - PRODUCTION EXPENSES Account 505 ('4ater Envircrrnental Expenses) 10. ne staff's test year treatment of water envirormental expenses is identical to the treatment given to air envircrrental expenses. The 1980 and 1981 as-expected year estimates were a=ortized over five years. This resulte in a test year estimate of $387,600, which is $331,700 lover than the utility's test year estimate. Accounis Slo, 551 (Materials and Maintenance Management Systems) 11. Increased expenditures to these accounts, beginning in 1980, are attributable to a new computerized system that will be used to manage the materials and labor involved in power plant maintenance. 12. The Materials Management System vill allow better control of materials. This will result in decreased delay ti=e in acquiring the =aterials necessary to perform maintenance, thereby minimizing equip =ent down time. Other benefits vill be increased worker productivity and increased generating unit availability. 13 The maintenance management program vill also increase worker productivity, reduce overt'ime, and increase availability of the units. This vill be accomplished by better planning, organization, and reporting of maintenance activities. Ideally, less time vill be spent on corrective maintenance and more ti=e vill be spent on preventive maintenance. 14. The staff reviewed the utility's estimate

• for the costs associated with these systems and found them to be reasonable.

j Account 510 (Maintenance Trainira Expenses) 15 The staff's estimate for maintenance training expenses reflects the utility's change in maintenance training practice. Beginning in 1981, the utility l vill only be training to replace people lost due to attrition. The impact of the staff's adjustment results in a test year estimate which is $42,800 lover than l' the utility's estimate. l l Nuclear Power Extenses 16. San Diego Gas & Electric's nuclear expenses are for a 20% share of the operation and maintenance costs for San onofre Nuclear Generating Station. only expenses related to SONGS Unit 1 are included in the rate case estimates. l 8-3 l L

8 - PRODUCTICN EXPDiSES 17 SDG&E's estimates for the non-fuel related nuclear accounts, excepting Account 525, were based on forecasts provided by Southern California Edison, with an adjustment to Account 517, Operation Supervision and Engineering. This adjust-ment was made to include expenses for the time spent by SDG&I's On Site Reviev Commaittee and Nuclear Audit Committee members on San Onofre related atters. The staff evaluated the utility's estimates and found them to be reasonante. 18. SDG&E made an independent estimate of the expenses for Account 525, Rents. The staff's test year estimate removes $15,000 worth of expenses associated with the SONGS Units 2 and 3 circulating water conduits. This adjust =wnt is consistent with the staff's treatment of expenses for SONGS Units ' and 3. The staff's test year estimate for the nuclear power accounts is $15,000 lower than the utility's, as shown in Table 8-C. Fuel Related Exrenses (DWR) 19. In 011-56, Investigation into Electric Utility Energy Cost Adjustment Clause, the staff reea-anded that the ECAC procedure be revised to incide all sales and fuel expenses related to the California Department of Vater Resources (DWR) contracts, incitw h g DWR sales in excess of purchases. 20. N also proposed that the ECAC proceeding be modified to include fuel expenses related to DWR sales. 21. In accordance with the positions taken by the staff and utility, the staff recomeends that all costs associated with DWR sales be removed from the general rate case. The inpact of the staff's adjustment is a test year estimate which is $10,900,000 lower than the utility's estimate. (Refer to Table S-E.) P 1 t

TA BLE 8-A SDGE--ELECTRIC DEPT

SUMMARY

OF PRODUCTION EXPENSES EXCLUDIhG ECAC TEST YEAR 1981 LN ACCT. UTIL. EXCEEDS STAFF NO NO ITEM STAFF UTILITY AMOUNT PCT (A) (B) (C) (D) (THOUSANDS OF DOLLARS) 1 OPERATION $30416.6 3 30947.8 $ 531. 2 1.7 2 MAINTENANCE 17915.5 17958.3 42.8

0. 2 3

MISCELLANEDUS 826.9 826.9 0.0 0.0 4 $UBTOTAL 49159.0 49733.0 574.0 1.2 5 FUEL UNDISTRIBUTED 3131.7 3131.7 0.0 0.0 t 6 FUEL COST-NON ECAC 0.0 10900.0 10900.0 0.0 7 TOTAL PRODUCTION EXPENSE 52290.7 63764.7 11474.0 21.9 8 WAGE ADJ. -334.8 0.0 334.8 -100.0 9 TOTAL AFTER WAGE ADJ 51955.9 63764.7 11808.8 22.7 l l 9 1 8-5 w

TA8LE 8-8 SOGE--ELECTRIC DEPT PRODUCTION EXPENSES EXCLUDING ECAC STEAM POWER PRODUCTION TEST YEAR 1981 'LN ACCT. UTIL. EXCEEDS STAFF NO NO ITEM STAFF UTILITY AHOUNT PCT (A) (B) (C) (0) (THOUSANDS OF DOLLARS) OPERATION 1 500.00 SUPERVISION & ENGINEERING $ 1525.0 $1525 0 $ 0.0 0.0 l 2 500.00 AIR ENVIRONMENTAL EXPENSES 141.0 325.5 184.5 130.9 l 3 502.00 STEAM EXPENSES 3104.7 3104.7 0.0 0.0 4 504.00 STEAM TRANSFERRED ~31.1 -31.1 0.0 0.0 5 505.00 ELECTRIC EXPENSES 2952.0 2952.0 0.0 0.0 6 505.00 WATER ENVIRONMENTAL STUDIES 387.6 719.3 331.7 85.6 7 506.00 / ART FALLOUT PROG AMORT 906.0 906.0 0.0 0.0 8 506 00 MEGMA GE0 THERMAL OEM 260.0 260.0 0.0 0.0 9 506.00 NILAND GEOTHERMAL AMORT 600.0 600.0 0.0 0.0 l 10 506.00 HEBER GE0 THERM PROG 6626.0 6626.0 0.0 0.0 l 11 506.00 EXPAND GE0 THERM PROG AMORT 471.6 471.6 0.0 0.0 l 12 506.00 MISC (NON-R10 EXPENSES) 1125.9 1125.9 0.0 0.0 l 13 507.00 RENTS-ENCINA 5 LEASE PMT 9302.0 9302.0 0.0 0.0 14 507.00 RENTS (OTHER THAN ENCINA 5) 90.4 90.4 0.0 0.0 15 $U8 TOTAL 27461.1 27977.3 516.2 1.9 l MAINTENANCE 16 510.00 SUPERVISION & ENGINEERING 1657.7 1700.5 42.8 2.6 17 511.00 STRUCTURES 2768.8 2768.8 0.0 0.0 18 512.00 80!LER PLANT 4864.7 4864.7 0.0

0. 0 19 513.00 ELECTRIC PLANT 4225.4 4225 4 0.0 0.0 20 514.00 MISCELLANEOUS EQUIPMENT 355.6 355.6 0.0 0.0 2:1 SUBTOTAL 13872.2 13915.0 42.8 0.3 22 TOTAL EX( ENSET 41333.3 41892.3 559.0 14 23 WAGE ADJ.

-245.0 0.0 245.0 -100.0 24 TOTAL AFTER WAGE ADJ 41088.3 41892.3 804.0 2.0 4 9 8-6 w w ,w -mw

TA BL E 8-C 50GE--ELEC TRIC DEPT PRODUCT *0h EXPENSES EXCLUDING ECAC NUCLEAR POWER PRODUCTION TEST YE AR 1981 LN ACCT. UTIL. EXCEEDS STAFF ,NO NO ITEN STAFF UTILITY AMOUNT PCT ~ (A) (B) (C) (0) (THOUSANDS OF 00LLARS) OPERATION 1 517.00 SUPERVISION 1 ENGINEERING $ 748.1 3 748.1 3 0.0 0.0 2 519.00 COOLANTS & WATER 135.6 135.6 0.0

0. 0 3

520.00 OPERATION OF REACTOR 536.2 536.2 0.0 0.0 4 523.00 ELECTRIC EXPENSES 58.4 58.4 0.0 0.0 5 524.00 MISCELLANEOUS EXPENSES 1076.2 1076.2 0.0 0.0 6 525.00 RENTS 22.2 37.2 15.0 67.6 7 SUBTOTAL 2576.7 2591.7 15.0 0.6 MAINTENANCE 8 528.00 SUPERVISION & ENGINEERING 471.2 471.2 0.0 0.0 l 9 529.00 STRUCTURES 97.5 97.5 0.0 0.0 10 530.00 REACTOR PLANT EQUIPMENT 573.9 573.9 0.0

0. 0 11 531.00 ELECTRIC PLANT 319.0 319.0 0.0 0.0 12 532.00 MISC NUCLEAR PLANT 68.c 68.9 0.0 0.0 13 SUBTOTAL 1530.5 1530.5 0.0 0.0 14 TOTAL EXPENSES 4107.2 4122.2 15.0 0.4 15 WAGE A0J.

-55.4 0.0 55.4 -100.0 16 TOTAL AFTER WAGE ADJ 4051.8 4122.2 70.4

1. 7 l

l I l l-I l l 8-7 l l l p

TA BLE 8-0 . -50GE--ELECTRIC DEPT PR000CII0h EXPENSES EXCLUDING ECAC G AS TUR91NE POWER PRODUCTION -AND OTHER POWER SUPPLf EXPENSES TEST YEAR 1981 LN ACCT. UTIL. EXCEEDS STAFF NO NO ITEM STAFF UTILITY AMOUNT PCT. (A) (B) (C) (0) (THOUS ANOS OF 00LLA RS) 0PERATION 1 546.00 SUPERVISION & ENGINEERING S 65.1 5 65.1 50.0 0.0 2 548.00 GENERATION 198.9 198.9 0.0

0. 0 3

549.00 MISCELLANEOUS EXPENSES 114.8 114.8 0.0 0.0 4 550.00 RENTS 0.0 0.0

0. 0

0. 0 5

SUBTOTAL 378.8 378.8 0.0 0.0 MAINTENANCE 6 551.00 SUPERVISION & ENGINEERING 256.3 256.3 0.0 0.0 7 552.00 STRUCTURES 58.6 58.6 0.0

0. 0 8

553.00 GENERATING EQUIP 2197.4 2197.4 0.0 0.0 9 554.00 MISC PLANT EQUIPMENT 0.5 0.5 0.0 0.0 10 SUBTOTAL 2512.8 2512.8 0.0 0.0 OTHER 11 556.00 SYSTEM AND LOAD CONTROL 824.2 824.2 0.0 0.0 12 557.00 MISC OTHER EXPENSES 2.7 2.7 0.0 0.0 13 SUBTOTAL 826.9 826.9 0.0 0.0 14 TOTAL ErPENSES 3718.5 3718.5 0.0

0. 0 15 WAGE ADJ.

-34.4 0.0 34.4 -100.0 16 TOTAL AFTER WAGE A0J 3684.1 3718.5 34.4 0.9 l I 9 8-8 w ---wr i

T,.A 8 L E, 6-E SDGE--ELECTRIC OEPT NON-ECAC FUEL EXPENSES TEST YEAR 1981 LN ACCT. UTIL. EXCEEDS STAFF ' NO NO ITEM STAFF UTILITY AMOUNT PCT (A) (8) (C) (D) (THOUSANDS OF DOLLARS) NON-ECAC FUEL HANDLING 1 501.20 FUEL DIL-STEAM 80!LER S 2847.5 3 2847.5 3 0.0 0.0 2 501.40 FUEL GAS-STEAM BOILER 8.6 8.6 0.0 0.0 3 547.20 OIESEL FUEL-COMBUSTION TUR8 275.6 275.6 0.0

0. 0 4

547.40 FUEL GAS-COMBUSTION TURSINE 0.0 0.0 0.0 0.0 5 $UST0TAL 3131.7 3131.7 0.0 0.0 NON-ECAC FUEL COST 6 501.10 FUEL DIL 0.0 7967.8 7967.8 0.0 7 501.30 FUEL GAS 0.0 1201.9 1201.9 0.0 8 518.00 NUCLEAR FUEL 0.0 438.0 438.0 0.0 9 547.10 DIESEL FUEL FOR GAS TUR8INE 0.0 93.0 93.0 0.0 10 547.30 FUEL GAS-COMBUSTION TUR8tNE 0.0 274.5 274.5 0.0 11 555.00 PURCHASED POWER CAPACITY 0.0 458.3 458.3 0.0 12 555.00 PURCHASE 0 POWER 0.0 428.5 428.5 0.0 13 557.30 NARCO FUEL SERVICE AGREE. 0.0 38.0 38.0 0.0 14 SU8 TOTAL 0.0 10900.0 10900.0 0.0 15 TOTAL 3131 7 14031.7 10900.0 348.1 16 WAGE A0J. 0.0 0.0 0.0 0.0 17 TOTAL AFTER WAGE ADJ 3131.7 14031.7 10900.0 348.1 k 8-9

CHAPfER 9 TRANSMISSION EXPEN3ES 1. Electric transmission expenses include the expenses incurred in the operation and maintenance of the utility's ove rhead and underground transmission lines with voltage levels of 69 kV and above, for such items as: supervision and engineering, load dispatching, rights-of-way, wheeling, and station equip =ent and structures operation and maintenance. 2. San Diego Gas & Electric Co=peny's service territory, 4,108 square miles, includes the majority of San Diego County and parts of I=perial and Orange Counties.' 'n*1 thin this region the utility had, as of Dece=ber 1979, 1,077 miles of trans=ission lines, including 116 miles of 230-k7 line, 232 =iles of 138-kV line, 727 miles of 69-kV line, and 24 =ajor substations with a total capacity of 5,982 M7A. 3 The staff's estimates were made using information rathered throneb discussions with the utility, data requests, field trips, and analysis of recorded data. The following is a summary of the staff's and utility's transmission expense esti=ates for the 1981 test year: Expense Esti=ates

Utility Exceeds:

Staff

Utility :

Staff (Coilcr: in I2ouscni:) $6,793 2 38,64S.7 31,655 5 Table 9-A co= pares the staff's and utility's esti=etes by secount f:r the 1981 test year. h. The majority of the utility's esti=ates were =ade by epplyin a nine-year historie growth rate to projected 1979 costs. The labor portion va.s then escalated to 1981 dollars by 9 5% and 13 5% for 1980 and 1981, respectively. l The non-labor portion was escalated by 10% per year for 1960 and 1981. The growth rates resulted from a least squares trend of 1971 through 1979 expenses, after adjusting for unusual or non-ceoccurring expenses. One of three types of rates was applied to each account, either growth of the individual account, the sum of transmission accounts, or a combinstion of two or ore related accounts. 9-1

9 - TRA!!SMIssIc:t Exysissa 5 The staff reviewed the reasonableness of the use of 1979 expenses as a base for estimatin6 future costs and found these levels to be reasonable for the accounts vbere no new projects, reorganizations, or unusual expenses were anticipated (Accounts 560, 562, 563, 56k, 569, 570 and 572). 6. For Account 571, Overhead Line Maintenance, the 1979 recorded level of expenses was adjusted upward to reflect a tor =alized insulator gressing year. 7 The staff's base level esti=ates for Account 566, Miscellaneous operation, and Account 573, Miscellaneous Plant Maintenance, were made by aversging normalized historic costs. This method was chosen because of the erratie behavior of hi_:oric charges. 8. The base levels for these 10 secounts were then eseslated to lo81 dollars by vege and material inflation factors. Analysis by individial accounts yielded no non-infistionary growth. This procedure resulted in differences between the staff's and utility's estimates for Accounts 560, 562, 553, 573, 571, and 572, as shown in Table 9-A. Accounts 561, 565, 567, and 568 will be discussed individually. Account 567 (Rents) 9 'Ibe staff reviewed the utility's esti= ate for this account and found it to be reasonable. Account 561 (Ioad Dispatching) 10. The increased level of expenditures to this account, beginning in 1981, is due to implementation of the utility's Energy Manage =ent syste= (EMS). This digital dispatching system vill update the currently outdated system. It will provide system security and economic dispatch of both on-and off-syste= c.wrgy. The system is expected to be operational in mid-1961. (Charges for 1981 test year case also appear in Electric Production Account 556.) 11. Charges applicable to this account include costs for increasee system operation's personnel to bandle energy transactions between utilities, and for additional personnel to maintain the new computer's hardware and software systems. 9-2

9 - TRANSMISSICU EXpr:SES 12. Analysis of the utility's esti=ates led to an adjustment for the existin6 personnel's labor charges. The 1979 labor charges were a:ijusted upwa-d to refleet the full-year equivalent charge for personnel hired during 19~9 Se staff did =ot include $30,0C0 vorth of labor increases, resulting fro: a redistribution of scheduling personnel's ti e, in the base letor fig.:re for existing personnel's ti=e. The effect of this secounting chan e ves to increase charges to Account 561 and to decrease cherges to other trsnsnission and distribution accounts. These costs, sithou;h additional charges to Account 561, sre not additional costs to be incurred by the utility. Since these costs have not teen specifically recoved fr0= the other accounts by the utility, they ere included in the historical costs and are, therefore, considered in the estimates for those accounts. Se utility's esti=ates for the non-SG, non-late.,r portion and for the SG portion appear reasonable. The staff's adjustment results in a test year estimate which is $76,000 lover than the utility's. Account 568 (Maintenance Suoervision and Engineering) 13 charges to this account in 1980 and 1981 vill te significently increased due to the for=ation of a new trans=ission =aintenance section. This section vill supervise the utility's plans for increased =aintenance on energized lines. It vill also pmvi:le input on the design and routing of new transmission lines, including SDG&I's proposed 500-kV eastern interconnection tie line with Arinona, so that " hot-line" =aintenance es: te perfo =ed. Increases to Account 568 for the 1981 test year are for related supervise:.: char 6es. i 14 The staff's estimate is based upon recent infustion provided by I the utility in response to a staff data request. The staff's adjust =ent re. oves 1 $100,000 from the utility's esti= ate, including 311,100 vorth of te=porary labor costs. This labor will te borrowed on an "as needed" tasis frc people currently working in the operati 6 districts. These charges are included in the r historical charges to other operation mui maintenance accounts and, therefore, should not be included in the test year esti= ate to Account 568. 2ese adjustments result in a test year esti:ste of $66,500, which is $100,000 lever then the utility's estinate. 9-3 L

9 - TPrisMrssIcn ExPr:sEs Account 565 (Traissission by Others) 15 This account contains the charges payable to others for the transmission of electricity to SDG&E over transmission facilities owned by others, known as wheeling charges. 16. The staff's esti= ate for this account reflects the staff's position in oII-56, Investigation into Electric Utility Energy Cost Adjustment Clause. The staff recommended that the ECAC procedure be revised to include wheeling charges that are: A. Variable-based on a dollar per kilevatt-hour basis. B. Directly associated with purchased pcuer recorded in Accour.t 555 C. Not recovered in genersi rates. Fixed costs based on contract payments for fixed blocks of energy would be included in the general rate increase. 17. According to these criteria, only Pacific Intertie costs vould be included in the test year esti=ste for the genersi rste case. The impact of the staff's adjustment is a test year estimete of 31,950,900, which is $1,512,800 lower thau the utility's estimate. 18. However, if the $1,512,800 amount is not allowed in the ECAC proceeding, it should be adjusted for the generel rate esse. The staff's edjustment re= oves the California Power Pool wheeling charges from the 1981 test year esti=ste. The utility's estisste was based upon a five-year average of past energy l receipts from the Califomia Power Pool. SDG&E, however, does not expect to receive any energy from the Power Pool in future years. Under the agreement, no charges are incurred when no energy is wheeled. The staff's adjustment results in a test year eseimate of $1,435,600, which is $77,200 lower than the utility's estimate. l 9u

O TA BLE 9-A SOGE--ELEC TRIC DEP T TRAhSMISSION EXPENSES TEST YEAR 1981 LN ACCT. UTIL. EXCEEDS STAFF 160 NO ITEM STAFF UTILITY ANGUNT PCT (A) (B) (C) (0) (THOUSANDS OF DOLLARS) 1 OPERATION 2 560.00 SUPERVISION & ENGINEERING S 436.8 3 429.7 3 -7.1 -1.6 3 561.00 LOAD DISPATCHING 1101.4 1177.4 76.0 6.9 4 562.00 STATION EXPENSES 340.1 365.3 25.2 7.4 5 563.00 OVERHEAD LINE EXPENSES 138.7 146.9 8.2 5.9 6 564.00 UNDERGROUND LINE EXPENSES 2.6 2.6 0.0 0.0 7 565.00 TRANSMISSION BY OTNERS 1950.9 3463.7 1512.8 77.5 8 566.00 MISCELLANEQUS. E XPENSE S 133.3 133.3 0.0 0.0 9 567.00 RENTS 149.6 169.6 0.0 0.0 10 TOTAL OPERATION EXPENSES 4253.4 5868.5 1615.1 38.0 11 MAINTENANCE 12 568.00 SUPERVISION & ENGINEERING 66.8 166.8 100.0 149.7 13 569.00 STRUCTURES 5.3 5.3 0.0 0.0 14 570.00 STATION EQUIPMENT 805.4 907.3 101.9 12.7 15 571.00 OVEl. HEAD LINES 1645.7 1677.8 32.1 2.0 16 572.00 UNDERGROUNO LINES 16.1 22.5 6.4 39.8 17 573.00 MISC. TRANSM!$5!0N PLANT 0.5 0.5 0.0 0.0 18 TOTAL MAINTENANCE EXPENSE 2539.8 2780.2 240.4 95 19 TOTAL TRANSMIS$!ON EXPENSES 6793.2 8648.7 1855.5 27.3 20 WAGE ADJ. -60.8 0.0 60.8 -100.0 ? ADJ. TRANSMISSION EXPENSES 6732.4 8668.7 1916.3 28.5 l 9-5

i CHAPTER 10 DISTRI5JIICN EXPE75ES 1. A summary of distribution expenses is shown below: Utility Exceeds Staff Si;aff Utility Amount Per:ent ~ (Dollars in Thousands) $22,557.k $25,101 3 $2,503 9 11.1% 2. Distribution expenses consist of the costs of operating and maintaining the utility's distribution system and include such items as supervision and en61neering, station expenses, overhead and underground lines, street lights and ( signal systems, meters and customer services. The staff conducted an engineering operational audit of the electrie distribution system and evaluated the reason-ableness' of the company estimated operational and maintenan e distribution expenses. The staff's estimates are based on data gathered on field trips, special studies and an analysis of recorded data fm m 1975 to 1979, by account, after adjustments for unusual and nonrecurring expenses. The utility's estimates are based primarily on nine-year trends of recorded data. Tsble 10-A compares the staff's and utility's estimates of the distribution system expenses for test year 1981. 3 The staff's estimates were different than those of the utility in l several accounts. An analysis of these differences is provided in the following paregraphs. 4. In Ac. 584, operational Undersround Line Expenses, the utility's estimate was derived by using a 19 76% historic annu'al Browth rate of the su= of the charges l to Aes. 584 and 594, excluding the underground preventive msintensnee prosra=. The expected growth was converted into a $39,000 per year growth excluding inflation. The staff's estimate consists of five-year (1975-1979) trends of labor and non-1sbor charges to Aes. 584 and 5%. The staff reviewed the cost per underground customer I and found the utility's estimates ior 1960 and 1981 are increasing. The following l is a summary of the staff study. 10-1

10 - DISTRIBUTICN EXPENSES Summary of Costs Per Underground Custo=er Study

Account Sc4: Account 5c4:

Cost per

Recorded

Expenses

Underground: Underground Year

Extenses

(19793)

Custo=ers : Customer (19793):

1975 $ 88,409 $120,500 163,200 30.74 1976 152,616 193,200 186,300 1.04 1977 165,383 135,200 216,600 c.90 1978 221,843 241,100 246,000 0 98 1979 340,937 3ko,900 275,200 1.24 Staff Estimate 1980 399,400 36h,8co 301,500 1.21 1981 h80,500 390,500 327,8co 1.19 Utility Estimate 1980 426,400 389, coo 300,700 1.29 1981 523,500 k'24,100 326,700 1 30 l 5 The st it's estimate considers the improvements in productivity in operation. For future cost savings, the coets per customer should te held near the level of previous years. The impact of the staff's adjustment is a test year estimate of $480,500, which is $43,000 1cuer than the utility's esti= ate. 6. Ac. 588 (Miscellansous Distribution Expenses) consists of general system records expenses, maps and records - overhead line expenses, caps and records - underground lines expenses and other s=all expense items. The utility l telieves that the present electric mapping system is inadequate and proposes a i five-year (1981-1984) program to convert it into a Distribution Facilities l Info mation System (DFIS). Based on a recent revision, the utility now estinates the cost of this program to be approximately $91,000 in 1980 and 31,159,000 in 1981. The utility originally requested $469,000 and $1,7h1,000 for the DFIS for 198o and ~ 1981, respectively. An amount of 3172,000 for additionni suto=atic dretting l equipment and three draftsmen is also included in the utility's esti=ste. Based on the implementation schedule of the DFIS program and the cost ravings thet should be realized, the staff has not included the edditienni expense Of 0172,C00. 10-2

10 - DISTRI3tJrIO t UPE; SIS The staff's estimate is based on a five-year trend of labor and non-labor expenses charged to Account 588, adjusted for labor cost escalation and =aterial cost inflation. The i= pact of the staff's adjust =ent is a test year estimate of $2,858,500,which is $1,162,200 lower than the utility's esti= ate. Among the $1,162,200, $582,000 is due to the revised estimate for the DFIS program, $172,000 for the disallowance of additional automatic drafting equip =ent and draftsmen, and $h08,200 due to different trending methods between the staff and the utility. 7. In Ac. 593, Maintenance of Overhead Lines, the staff considered the effects of the utility's overbend to underground conversion pro 6rar.s and the increase in new customers with underground service. The utility used a trend which included tree trimming expenses. The staff reviewed the utility's analysis of the historic tree trimming activities and tree related outages. The staff concluded that the historic tree tri= ming expenses did not correlate ~ to system growth. The following is a su=mery of the staff's study. Study of Cost of Tree Tri :=in; per Custor-r to Tree Related Cutages

Tree

.,er Customer : related : Year (19793)

Outages :

1975 32.72 99 1976 2 52 116 1977 3 02 150 l 1978 3 19 306 1979 3 86 18k l Staff's estimate 1981 2 95 Utility's estimate 1981 4.01 8. Ite staff used a five-year average of tree trimmin cost as a basis l for 1981 tree trimming expenses, adjusted for inflation. The utility estimated tree trimming cost to be approximately 30% of total Acecunt 593 The utility's j . estimate for tree tri:maing cost is $2,297,900 including Sk00,000 for additional tree trimming. The staff's tree trimming cost estimate is $1,688,5CO, excluding the requested $k00,000 for additional tree tri-:mi:5 10-3 l

f i l lo - DISTRIEtEICN EXPE:ISES l 9 In Ac. 594, Maintenance of Underground Lines, the staff's esti= ate reflects the utility's recorded experience with underground seintenance. The utility's estimate was derived by usf.ng e 19 76% bistoric annuti growth rate of the sun of the charges to Aes. 5F4 and 594, excluding the underground preventive maintenance program. The expected growth was converted into a $16k,000 per year growth excludirg inflation. The staff found no indiestion that the underground distribution system was growing at a rapid rate, on l the contrary, the percentage of increased underground cu.tomers is declining. The following is a summary of the staff's study. i Study of Underzround Customer Growth i

Numher of :

Underground : Numb er : Percent Year

Customers : Increase : Increase :

1917 216,600 30,300 16 3% i 1978 246,000 29,hoo 13.6 1979 275,200 29,200 11 9 1980 301,500 26,300 96 l 1981 ,327,800 26,300 S.7 l l lo. The staff also reviewed the cost per underground customer end found I this cost to be decreasing. ' The imple=entatice of the underground preventive =aintenance progrs= in 1979 improved the cost savings of unier;round =sintenance. The staff expects this trend to continue and has reflected it in its estinate. The following is a summary of the rtsff study: l l l 10-4 ~ k

lo - DIST? a m 0N EXPUS E Sur.ary of Costs Per Under:round Cust =er Study (Excluding UnderErcund Preventive.v.aintenance Progn:) 00st per :

Un:1erground :

Account 59h : Underground : Custoner Year (19793)

Customers (10793) 1975 31,307,100 163,200 35.01 1976 1,2k6,100 156,3co 6.69 1977 1,369,900 216,600 6.33 1978 1,629,900 246,0cc 6.63 1979 1,542,300 275,200 5.60 (Staff Istim te) 1980 1,6L1,sco 3o1,500 5.Eh 1981 1,748,300 327,500 5 33 (Utility Estimate) 1980 1,820,300 300,700 6.05 1981 2,o67,600 326,700 6 33 I

i i e 10-5 t L.

10 - DIS ~d2LCCN DGriSIS F 11. The utility estinated the u.derground preventive maintenaces program for 1960 to 1982 at $792,0Cu per yetr, excluding inflation. 2 e staff ~ has found this esti= ate -assenable and included $972,200 f0r the progra= in 1981. S e i_ pact of the staff's adjust =ent is a test year estimate of $3,119, loc, which is $hol,90o lover than the utility's esti=ste. 12. Ac. 597, Maintenance of Meters Expenses, includes the cost of labor, material used and expenses incurred in the =aintenance of neters and =eter testing equipment. Se staff observed an 1: prove:ent in pr ductivity since 1975 and anticipated further cost savings. Se i= pact of ste staff adjust:ent is a test year esti= ate of Sh86,50C, vhteh is Sik,200 lever then the utility's esti= ate. I e l l-l 1 l l i l 10-5 i l r 1 l L

+ TA8LE 10-A SOGE--ELEC TRIC DEP T DISTRIBUTION EXPENSES TEST YEAR 1981 LN ACCT. UTIL. EXCEEDS STAFF NO NO ITEM AFF UTILITY AMOUNT PCT sA) (B) (C) (0) (THOUSAN05 0F DOLLARS) 1 OPERATION 2 580.00 SUPV. & ENGINEERING S 1252.8 3 125'i,8 30.0 0.0 3 582.00 STATION EXPENSES 960.6 960.6 0.0

0. 0 4

583.00 OVERHEAD LINE EXPENSES 1147.9 1147.9 0.0 0.0 5 584.00 UNDERGROUND LINE EXPENSES 480.5 523.5 43.0 8.9 6 585.00 STREET LIGHT EXPENSES 341.1 341.1 0.0 0.0 7 586.00 METER EXPENSES 1813.0 1813.0 0.0 0.0 8 587.00 CUSTOMER INST. E XPENSES 1616.9 1616.9 0.0 0.0 9 588.00 MISC 0I579 EXPENSES 285d.5 4020.7 1162.2 40 7 to 589.00 RENTS 19.6 19.6 0.0 0.0 11 TOTAL O!STR. OPER. EXPENSE 10490.9 11696.1 1205.2 11 5 12 MAINTENANCE 13 590.00 SUPV. & ENGINEERING 322.3 322.3 0.0 0.0 14 591 00 STRUCTURES 28.6 28.6 0.0 0.0 15 592.00 STATION EQUIP. 789.5 785.5 0.0 0.0 1 16 593.00 OVERHEAD LINES 7050.2 7659.6 609.4 8.6 17 594.00 UNDERGROUND LINES 3119.1 3521.0 401.9 12.9 18 595.00 LINE TRANSFORMERS 389.4 389.4 0.0 00 l 19 596.00 ST. LIGHT.4 SIGNAL SYS. 145.1 145.1 0.0 0.0 20 597.00 METERS 486.5 500.7 14.2 2.9 l 21 598.00 MISC DIST PLANT 53.0 53.0 0.0 0.0 22 TOTAL DIST MAINT EXPENSE 12379.7 13405.2 1025.5 ag3 l 23 TOTAL DISTRIBUTION EXPENSE 22870.6 25101.3 2230.7 9.t l 24 WAGE ADJ. -273.2 0.0 273.2 -100.0 l 25 TOT AL O!STRI. EXP. A0J. 22597.4 25101.3 2503.9 11.1 e l l j 10-7 l l l

CHAPTIR H CUSIOMER ACCOUNTS GCTSES i 1 A sunnary of customer accounts expenses is shown below: Utility Exceeds Staff Staff 2.ility Amount Percent (Donars in nousands) $10,k69.k $n,259.6 $790.2 7 55 General 2. Se costs of customer accounts include the handling of customer inquiries, credit, conections, billing and bookkeeping da+. processing charges, postage, uncollectibles and supervision of these activities. Cost History and Esti ates 3 Costs per customer for the total of custocer accounts, gas and electric are: (1979$) Year Customer Accounts

1975 : 1976 : 1977 : 1978

1979 : 1961 :

Staff Estimate $13 33 $13.46 $12 78 $12.13 $n.91 $n.72 ' Utility Esti mte 13 33 13.h6 12.78 12.13 n.91 12.oh he decline in cost per customer is generally due to greater utilization of existing capacity. Estimating Methods k. All company estiantes, with the exception of Postage and Unconectibles, are based on the 12-month recorded cost as of December 31, 1979, increased by the j ratio of average customers' forecasts for 1981 to those recorded for 1979 These aucunts were then adjusted for a wage increase of 9 5% for 1980 and 13 55 .for 1981. No increase was taken into consideration for ncn-labor costs, other than the growth in number of customers. 5 The staff analyzed the history of cost per customer from 1975 through 1979 The trend of adjusted costa per custoner of most accounts is generany downward, due mostly to the spreading of fixed costs over the greater nunber of l customers. 11-1 i I h.C=

11 - CUSTOMER ACCOUNTS EXPH;SES Staff Analysis 6. In Ac. 901 (Supervision Expenses) the staff esti= ate is based en the history of the costs per customer. S e decline in adjusted cost in the labor portion shows improvement in productivity. Me staff expects the trand to continue and the 1981 test year estimte is adjusted for a wage increase. 7 Ac. 903 2 (credit Msnagement Expenses) includes the cost of establishing the company credit policy and collection of all monies owed the company. De promotion of better labor manage =ent has caused th: decrease in cost. 8. Ac. 903 3 (conections Expenses) includes investigation of custocer's credit, originating requests for refunding, preparation of delinquent notices, final meter reading of delinquent accounts, disconnection of services because of unpaid bills and collection on past-due accounts. The staff observed a decline in labor cost per customer from 1975 to 1979 and based its estimate on this trend. The staff used a five-year average of costs per customer as a basis for its non-labor estimate. 9 Ac. 903 5 (Billing and Bookkeeping Expensec) includes file maintenance, manual review and calculation of certain bills, meter deposits, taxes and microfilming. The co=pany ftiled to consider the i=portance of cost savings. l The staff anticipated further savings as the costs per customer centinue to decrease. i I I' l 11-2 , -, ~ - - - -,.

11 - CUSTOMER AOCOU!G IXPENSES 10. In Ac. 903 7 (Postage Expenses) the company's esti= ate allows for an increase from 13d to 184 for presort and fro: 15d to 20d A first class. The staff reconnends that the increase in postal rate not be incided until 1 the n;enersi rate increase is approved by the PosttJ. Rate Commission and the U.S. Congress, he impact of the staff's adjustment is a test year estimate of $961,k00, which is $354,200 lower than the utility's estimate. The s following is a schedule of postage increases and their i= pacts.

Presort Postage : Percent Increase : htal Account 903 7 :

13d 0.00% $ 961,400 14 7.69 1,035, Loo 15 15 38 1,109,300 16 23 08 1,183,300 17 30.08 1,257,200 18 38.h6 1,331,200 19 h6.15 1,LOS,100 20 53.85 1,k79,100 11. Ac. 90k (Unco 11ectible Accounts Expenses) is an account charged with amounts sufficient to provide for losses from uncollectible utility revenues. i The staff adopta the utility's percentage of loss of 0.150% for test year 1981. However, the staff disagreed with the utility's approach in calculating the l uncollectible expenses. In the Electric Department, the staff removed miscellaneous and off-system sales revenues.from total revenues in its l t calculation. In the Gas Department, interdepartmental and miscellaneous l l revenues were taken out. 12. Based on staff reviews of the history of the costs and expected operations of all other accounts, the company's estimate appears to be reasonable l and is adopted for purposes of this proceeding. I i i u-3

TA BLE 11-A 50GE--ELECTRIC OEPT CUSTCHER ACCOUNTS EXPENSES ELECTRIC OEPARTMENT TEST YEAR 1961 LN ACCT. UTIL. EXCEEDS STAFF NO NO ITEM STAFF UTILITY AMOUNT PCT (A) (B) (C) (0) l (THOUSANDS OF OCL.LARS) 1 901.00 SUPERVISION $ 190.2 3 196.0 3 5.8 3.0 2 902.00 METER REA0!NG 2061.5 2061.5 0.0

0. 0 3

CUSTOMER RECOROS AND COL. 4 903.10 CUSTOMER SERVICE 3073.0 3073.0 0.0 0.0 5 903.20 CRE0!T MANAGEMENT 132.1 144.5 12.4 9.4 6 903.30 COLLECTIONS 974.2 1056.0 81.8 8.4 d 7 903.40 CUSTOMER PAYMENTS 628.0 628.0 0.0 0.0 8 903.50 BILLING & BOOKKEEPING 785.1 578.3 93.2 11.9 9 903.60 DATA PROCESSING 1330.3 1330.3 0.0

0. 0 10 903.70 POSTAGE 961.4 1315.6 354.2 36.8 11 TOTAL CUSTOMER REC. AND COL 788*.1 8425.7 541.6 6.9 12 904.00 UNCOLLECTIBLE ACCT.

432.8 546.8 114.0 26.3 13 905 00 MISC. CUST. ACCT. EXP. 29.6 29.6 0.0 0.0 14 $UBTOTAL CUST0aER ACCT 10595.2 11259.6 661.4 6.2 15 WAGE A0J. -128.8 0.0 128.8 -100.0 16 TOTAL CUSTOMER ACCT. EXP. 10467.4 11259.6 790.2 7.5 oooo* AT PROPOSED RATES 17 904.00 UNCOLLECTIBLE ACCT. 634.6 737.2 102.6 16.2 18 SUBTOTAL CUSTOMER ACCT 10800.0 11450.0 650.0 6.0 i 11 L

CHAPTER 12 MARKET SE/ ICE EXPE*GES - ELICTRIC DEPAR2C.'T (CONSERVATI0U) 1. Rese expenses include activities which encoursge ecmservation and load reduction. They are the supervision, labor and administr. tire (ancillary) expenses of central staff and field personnel. They plan te implement and moniter monitor the various progn ms. Also included are the expenses for advertising and related collateral material, such as bill stuffers, printing of pamphlets and publication and dissemination of various conservation related material. 2. The staff's Conservation Branch evaluated the reasonableness of SDG&E's programs. A sepa s te report published the staff's conclusions, recoccendations and adjustments. 3 Table 12-A is a co=parison of the utility's and staff's test year 1981 expense estimates, by the uniform system standard account number. L. A comparison of total expenses is: Test Year 1081 Item Staff Utility (Dollar in Ihousands) Total Expenses $9,268.1 $14,802.0 e 12-1 e

12 - fMFC SERVICE EXPE'ISES - ELEC'"Plc DEPA:CC;T (CONSERVATION) 5 In order that the Comission and interested parties can have a better understanding of how SDG&E's conservation estimates relate to other California utilities, the staff has prepared the following table. l COWARISDN OF 1981 TEST YEAR CONSERVATION EXPENSES INCLUDING LOAD MANAC gas Electric S/cust. c/ therm c/thern S/cust. c/kWh c/kWh over life-over l line lifeline So. Cal. Gas Staff 8.16 .34 .43 Utility 10.08 42 .53 So. Cal Ed. j Staff & Utility 12.12 .60 .71 l l SDG&E l Staff 7.26 47 .72 11.69 .85 1.08 Utility 8.70 .57 .86 18.66 1.36 1.73 M l PG&E 5.99 .23 .29 14.22 .78 .94 l l l M All estimates are from the staff Results of Opersuon reports. To be on a comparative basis, staff customers and sales estimates were used. ~ 1/ Test Year 1980 per Decision No. 91107. 12-2

12 - LEI SERVICE EXPLSES - II.ECRIO DEPA?TICr (CCUSERVATION) 6. The following table lists the utility's esti:nated advertising expenses which are included in the 1981 test year. In order to allocate betveen depart:aents, both the staff and utility have assigned approxt:nately 757. of the conservation expenses to electric and the remainder to gas. All load :nanage.unt expenses are assigned to the Electric Depart:nent. 1981 ESTIMATED AD'KRTISING EXPDISE Conservation Manazee.ent Total (1) Radio 367,000 13,000 380,000 (2) Television 330,000 47,000 377,000 (3) New;, aper 304,000 130,000 634,000 (4) Parphlets 1,780,500 15,000 1,795,500 (5) tiiscellaneous (includes :narketing, response envelopes. trade journals, magazine, transit, outdoor billboards, agency fee, development, etc.) 517,000 26,000 543,000 (6) Total 3,498,500 231,000 3,729,500 e i 12-3 l l l L

TA8LE 12-A 50GE--ELEC TRIC OEPT MARKETING EXPENSES TEST YEAR 1981 LN ACCT. UTIL. EXCEEDS STAFF NO NO ITEM STAFF UTILITY AMOUNT PCT (A) (B) (C) (0) (THOUSANDS OF DOLLARS) 1 907.00 3UPERV!$!ON 3 159.2 3 156.8 3 27.6 17.3 2 908.00 CUSTOMER ASSISTANCE 7952.1 12726s4 4774.3 60.0 3 909.00 INFO.INSTRU. EXP. 752.2 1484.2 732.0 97.3 4 910.00 MISC.CUST. SERV. 404.6 404 6 0.0 0.0 5 MARKETING EXPENSES 9268.1 14802.0 5533.9 59.7 6 WAGE A0J. 0.0 0.0 0.0 0.0 7 TOTAL CUSTOMER SERV.EXP.ADJ 9268.1 14802.0 5533.9 59.7 e 9 e 12 k

D CHAPIER 13 ADICTSTRATIVE AND GCERAL EGE:!SES - ELECTRIC 1. The staff's estinate of the Electric Departnent's administrative and general expenses is the result of evaluation of c:any general office departnents in the San Diego Gas & Electric Company. This evaluation included analysis of the trends of current departmental expelses and the engineering economics of customers and growth on administrative and general expenses. 2. The comparable figures for total electric administrative and general expenses excluding franchise for test year 1981 are as follows: Item

Staff : Utility :

(Dollars in Thousands) Total A3G Expense C36,369 $38,336 3 Table 13-Acompares the total direct and indirect, as estimated by staff and utility, administrative and general expenses for the Electric tepartment. Both the staff and the utility have included wage increases in their estimates relative to the administrative and general expense labor items. Staff's treat-ment of the 1981 estimated wage increase is stated in Chapter 1 of this report. Specific areas of differences between the staff and the utility regarding the indirect allocated amounts to the Electric Department are covered in the staff's General Report, Chapter 2. Differences between the staff and the utility estinates of direct electric expenses are due to different estimating methods and specific adjustments as explained in the General Report, Chapter 2. l l \\ l l I I 13-1

TA8LE 13-A 50GE--ELEC TRIC DEP T ADMINISTRATIVE AND GENERAL EXPENSES TEST YEAR 1981 LN ACCT. UTIL. EXCEEDS STAFF NO NO ITEM STAFF UTILITY AMOUNT PCT (A) (8) (C) (0) (TH005.NOS OF 00LLARS) 1 AT PRESENT RATES 2 920.00 ADMIN. AND GEN. SALARIES 5 12729.1 5 12732.6 5 3.5 0.0 3 921.00 0FFICE SUPPLIES & EXPENSES 7482.5 7482.8 0.3 0.0 4 922.00 A & G TRANS.- CRE0!T -9139.5 -8406.0 7e3.5 -8.5 l 5 923.00 QUT5!0E SERVICES EMPLOYE0 1068.9 1068.9 0.0 0.0 6 924.00 PROPERTY INSURANCE 2172.4 2350 5 178.1 8.2 7 925.00 INJUR!ES & OAMAGES 1268.4 1273.0 4.6 0.4 8 926.00 EMPLOY. PEN 5!ON & BENEFIT 5 13574.0 13850.0 276.0 2.0 9 927.00 FRANCHI3E REQUIREMENTS 5676.0 5414.0 -262.0 -4.6 10 928.00 REG. COMM. EXPENSES 324.2 324.2 0.0 0.0 11 929.00 OUPLICATE CHARGES-CREDIT -1310.3 -1310.3 0.0

0. 0 12 930.00 MISCELL GENERAL EXP 6501.2 6852.9 351.7 5.4 13 931.00 RENTS 827.2 890.1 62.9 7.6 j

to 932.00 MAINT. GEN. PLANT 1190.0 1227.3 37.3 3.1 15 5UB-TOTAL AEG EXP. 42314.1 43750.0 1435.9 3.4 16 WAGE A0J. -442.6 0.0 442.6 -100.0 j 17 A & G TOTAL AFTER WAGE A0J. 41871 5 43750.0 1875.5 45 00o0e AT PROPOSCO RATES..... l 18 927.00 FRANCHISE REQUIREMENTS 8298.0 7883.0 -415.0 -5 0 19 $US-TOTAL AEG EXP. 44936.1 46219.0 1252.9 2.9 l 13-2

5.- b C*:!Ar.r..'. ik -y- ,~. ,. C.. ...-3a.....,.. s.. ".".'. ' s s... * ,~.. s a..*. s *.*. s.s.". ' s. _,.-.a. '. -..'.'... - e *. ax ry e. ~ for :ste-=aking ;arpeses tesed upc: the tes year results Of 0;e-st10:s f: Se: Dieg: Ges & C e:tri: Co=ps y's Ce:tri: ey rt=e 2. . w" 2 h, *'. i s Comeis s '.....'.a s ..' a..- *~.~.s*.*..-*.*.*..."...-....'.*..-%.

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..... ' *..*.. ' ' ~.~ *.axa '. ' *. *..~~~. art ex,'._= '.. " *. differe :es tetwee: tte Oce;4:7's and staff's es-irates. ...e.es.... ~..,.. .e..s. w k. In ecisic: 50. TT975, dated Neve-ier 2h, '.9'O, in resp::s e t: Scutter Califer..ia Gas C --w's General 7. ate Applienti:: ';:. 515f"*, this 00 cissi:: stated: " te stafs use Of a yen end :::pesite 1: teres, este f:r .cey...a gu ...,._ e.a.,....,__a u . e...,.,.ae.. _.a..... e.. .. 3 v et. *.. e.-a. s. '. e.d.. ' ~. s.". ". e -*. '...'.s..* - " *.=. x a. s '. s = =. '.

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tte : rrent is e case, tte staf"'s rste f re* :: vitress is ree:cmending the usage of as aversge Of the begin:in; a '

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114 - INCCE TAX 2S synchmnization, the average embedded debt cost as recon = ended by the r*.te of return witness has been multiplied by the aversge debt out' standing to arrive at the interest deduction for inco=e tax purposes. 6. The computed amount of interest expense has been apportioned by the staff between departments on the basis of each department's met plant balance to the total. The apportioned interest expense has then been.Mueed by the amount expected to be charged as A U)C on construction vork in progress in the test year. Tax 3 asis Depreciation 7 The tax depreciation has been computed using the shortest lives and fastest methods allowed by the Internal Revenue Code and California Corporation Franchise Tax Law. Removal Cost 8. Removal cosi, represents the current deduction of the costs of dismantling, demolishing or removing certain assets in the process of retire-ment. There is no difference between the staff and utility esti=stes. Ad- % istrative and General Costs, Payroll Taxes, Pension and Benefits Capitalized 9 For income tax purposes, certain pension and benefit, and ad=inistra-tive and general costs, which are capitalized for rate-making purposes as a part of constructed plant, can be deducted currently. 31s adjustment recognizes the amount estimated to be capitalized in the test year. De staff figure is ll, a summation of the staff payroll tax and pensien and benefit witness' estimates of the amount of these expenses which will be capitali:ed for rate-making purposes. 1h-2

1h - DICCMI TAXIS The staff estimate is ce=puted thusly: ) Administrative and General $3,LS6,900 i Pensien and Benefits 5,702,600 Capitali:ed Payroll Taxes h39,000 Total (Rounded) 9,629,000 Ad Valorem Tax Capitalized 10. That portico of ad valorem tax which is capitalized for ratedr4 purposes is claimed as a current year deduction for income tax purposes. This adjustment reflects the staff's ad valore= witness estimate of that a= cunt exclusive of that related to SOIiGS II and III. 11. The staff rececmends that the ad 7Grem tax en SC:IGS II and III, of $h,857,ooo, not be flowed through eu.vently but capitalized net of the inecme tax benefit, as is presently done with the interest pertien of AFUDC. This proposed treatnent is consistant with that adopted in D-89316, issued September 6,1978, in' response to PGE's general rate case A-572Sh. Use Tax Capitalized 12. This adjus.sent recognizes the estimated amcunt of used tax to be incurred which will be capitalized for rate-fixing purposes but expensed fer income tax purposes. There is no difference between staff and company estinates. Centributions for Service Fees (Service Cennection Fees) 13 Intemal Revenue Code Section 116, as revised by the Revenue Act of 1978, excludes frem taxable inecme all ecatributions in aid of censt:mtion, except service eccnection fees; the staff and eccpan/ esti=ates of the a: cunt taxable in t':e tcst year are the same. 1h-3 e

14 - INCCME TKC3 Repair Allowanee 14. The repair allovence is an annual election available to~ the taxpayer under Internal Revenue Service regulations. Under this election, certain expenditures for the repair, maintenance, rehabilitation or i=provement of property that have been capitalized for book purposes may be treated as I currently deductible repairs to the extent they do not exceed the repair allowance prescribed by the regulations. There is no difference between the staff and utility estimates. Preferred Dividend Deduction ~ 15. This is a special deduction for utilities and is deductitle for federal tax purposes only. It is based on a certain percentage of preferred dividends paid on preferred stock issued prior to 19h3 The company vill be able to claim $594,000 in 1981, which the staff apportioned on the sa=e basis as it did interest expense. Fiscal / Calendar Adjustment of Ad Valore: Taxes 16. A utility may, for income tax purposes, deduct in the current year the full amount of ad valorem taxes due on property held as of March 1, despite i the fact that one-half of the amount is not payable until the following year. l l For book and rste-making purposes., utilities record ad valore: taxes on s calendar year basis. The staff figure was leveloped fro: infor stion provided by the staff ad valores tax witness. I lk h l-l L L.

ik - INCOME TAXES Reseereh and tevelopment Costs 17 Decision No. 912"1, issued January 29, 1980, in response to Application No. 59260, authorized San Diego to treat as research, develop =ent and demonstration costs its share of the costs of the Heber geother=21 project. It addressed possible income tax consequences of the decision thusly: "The additional income tax liability of SDG&E, due to the project, is estimated at 43 million based on capitalizing $24 =illion of construction cost fcr income tax purposes and utilizing 90 percent ITC. Neither the staff nor SDG&E has =ade a full analysis of the proper treatment of such tax expense and the record is inadequate to decide the issue at this time. We, therefore, direct this matter to be fully explored in SDG&E's next general rate case. At this time, SDG&E will be permitted to recover no more than actual construction and demonstration expenses on a dollar-for-follar basis with no additional allowance for potential tax liability related to the Heber project." 18. It is the staff's opinion that were the company to take an aggressive position with the IRS that most, if not all, of the Heber expenses could be deducted as incurred. 19 If the company does not pursue an a5gressive position, or if the IRS is adamant that the plant costs =ust be capitalized, the company will reco5nize only a very sli5ht increase in its test year inec=e tax expense for the following reasons: A. Under IRS regulation 1.174-2(b)(k), the company will capitalize only: "... the costs of the _coctx,nent materials of the depreciable property, the costs of labor or other elements involved in its construction and installation, or costs attributeble to the acquisition or improvement of the property." 3. The company at the end of 1979 had a $14.7 million opersti 5 loss carry-over which can be used to offset future texable income and $39 7 million of unused invest =ent tax credits which can be used to offset 80% of the ec= pated income tax for 1960 and 1981 and 90% for 1982. 1h-5

Ik - INCCME TAES 20. Fer the foregoing reasons, the sta'r opposes any reimburse =ent for possible test year income tax liabilities related to the Heber geo~the. a1 project. Investment Tax Credit (ITC) 21. The Commission, in D-9Ch05, issued in respense to A-58067, et s1. on June 5,1979, adopted the same treatment as it did in D-89857, wherein it said: "By Decision No. 890h8 dated June 27, 1978, the Coenission granted limited rehearing as to the issue of proper treatment of incece taxes in Decision No. 88697 in Applications Hos. 55627, 55628, and 55629 to be consolidated with the hearings in Application No. 58067. Both the staff and SDGE offered testimony and exhibits as to the appropriate method for calculating investment tax credits to be used for rate-mahing purposes. SDGE's tax witness Miller testified that flow-through of Investment Tax Credit (ITC) earned under the 1971 Revenue Act at a rate greater than 50 percent violates IRS Code Sections k6f(2) and (8) and Temporary Regulation Section 9 1 thereby jeopardizing the additional investment tax credits available under the Tax Reduction Act of 1975 "The staff witness examined the IRS code provisions upon which SDGE relied to support its position and did not agree that the language therein clearly and convincingly demonstrated the interpretatien of law that SDGE set forth. Accordingly, for the purposes of this decision, ITC will be limited to 50 percent of the tax liability plus the rateable flow-through of the excess ITC generated by the 1975 Tax Reduction Act. Income tax expense computed with this limitation will be made subject to refund pending final resolution of this issue." 22. On September 18, 1978, the company requested a ruling from the IES, wherein it asked (among other things): "Whether the additional credit allowed by reason of the Tax Reduction Act of 1975 includes any additional credit allevable because of the increase in the limitation based on ta:: under Section h6(a)(7) (from 50% to, among other rates,100% for 1976 and 706 for 1979). To avoid possible misundert:tanding, your ruling is also requested en the increaseinthea=ountofthecreditunderSection46(a)(2)."M M Section h6(a)(2) increased the amount of credit fro: 75 to 105 (h1 to 105 for public utilities); Section h6(a)(7) increased the amount of federal income tax which could be offset by the ITC from SOP, to percentages which varied by year but which were greater than 50~,. 1k-6 1

14 - INCOME TAXIS 23 On January 17, 1980, the IRS responded thusly: "The additional ITC allowed by reason of the 1975 Act (which under the Company's 1975 election of ratable flow-through must be accounted for in the manner described in Section M(f)(2) of the Code) includes an amount of additional ITC earned for limited property, allowed by reason of the increase in the amount of ITC under Section M(a)(2) and the increase in the limritation based on tax under Section M(a)(7), that results from the computation described in Section 9.l(a)(3)(1) of the temporary regulations." ITC Currently Flowed Through 24. The staff recocimends flowing through the lesser of: A. fifty percent of the estimated test year tax liability; or d B. the average amount of ITC not covered by San Diego's option II election which is expected to be generated in the test year cad the year preceding, plus that portion of previous years' credit not covered by Ee cocrpany's option II election, but not flowed through, because of the previous 4 discussed 50% limitatien. (The staff's analysis of D-87639 and D-90h05 indicates that all previous years' ITC not covered by the company's option II election has been previously flowed thzr.xgh in lower rates.) I"'C Ratably Flowed Through 25 IRS regulation 1.M-6(g)(2) explains how to compute the amount of ITC which is to be flowed through under the company's option II (ratable flow through) election. It says, in part: "What is ' ratable' is detemined by considering the period of time actually used in cociputing the taxpayer's regulated' depreciation expense for the property for which a credit is allowed. ' Regulated depreciation e:: pense' is the depreciation expense for the property used by a regulatory body for purposes of establishing the taxpayer's cost of service for rate-making pruposes. Such period of time shall be expressed in units of years (or shorter periods). units of prcduc-tion, or machine hours and shall be determined b acordance with the L -individual useful life system or compost e (v ither group asset) account - system actually used in cociputine @; tr;pa;rcr's regula ed depreciation e:: pense." - 1h.7. y ,..~,.w g w

lh - INCOME TAXES The staff's interpretation of the phrase, "... actually used in computing the taxpayer's regulated depreciation expense", is that the ccrspany's option II ITC is to be flowed through over the rate-making service lines of every asset class which actually generates the credit. For example, if the company generates $1 million of credit from the instanation of new gas distribution mains, whier has a rate-making service life of 43 years, the company should flow through 1/43 of the credit in each of the h3 years. 26. The company contends that it does not generate the accounting informa-tion required to use this methodology. It proposes, instead, to flow through the credit over the average rate-making service lines of all properties put in service in each year. 27 The staff finds two faults with the company methodology: A. Because of the lack of strict adherence to the IRS regulations, San Diego is, to a limited degree, risking its eligibility to claim the ITC covered by its option II election. 3. Because different classes of property have different rate-making service lines, the staff's (and I2S's) methodology achieves a balance between the ratepayers paying for the property (through depreciation expense) and the company's flowing through the related ITC. The company's methodology, however, flows through a levelized amount of I'"C over the properties' average service lines. 1k-8 O L_

1 I Ik - INCDME TAXES 28. The staff recoc: mends that the Coc: mission order the company to implement accounting proceedings which per=it flowing through the' company's option II ITC in accordance with the staff's, and IPS's methodology for plant Placed in service in 1981 and years thereafter, and that the company's methodology be used for the option II ITC generated in years prior to 1981. Graduated Rate Benefit 29 The " Graduated Rate Benefit" recognizes the fact that the first $100,000 of corporate taxable income is taxed at various step rates which are less than the 16', rate which is applicable to taxable income in excess of $100,000. The staff apportioned the " benefit" on the sa=e basis as interest expense. e lk-9 e

TA BL E 14-A i 50GE--ELECTRIC OEPT

SUMMARY

OF TAX EXPENSES TEST YEAR 1981 LN ACCT. UTIL. EXCEEDS STAFF NO NO ITEM STAFF UTILITY AMOUNT PCT (A) (8) (C) (0) (THOUSANOS OF DOLLARS) 1 A0 VALORE" TAXES $ 10893.0 $ 11709.0 $ 816.0 7.5 OTHER TAXES 2 FEDERAL INSURANCE ACT (FICA 2821.0 2821.0 0.0 0.0 3 FEDERAL UNEMPLOYMENT (FUI) S5.0 85.0 0.0

0. 0 4

CALIF UNEMPLOYMENT (SUI) 340.0 340.0 0.0 0.0 5 MISCELLANEDUS 2.0 2.0 0.0 0.0 1 6 WAGE ADJ 0.0 0.0 00 0.0 7 $UBTOTAL 3248.0 3248.0 0.0 0.0 8 TOTAL NON-INCOME TAXES 14141.0 14957.0 816.0 5.8 AT PRESENT RATES 9 CALIF CORP FRANCHISE TAX 532.4 2180.0 1647.6 309.5 10 FEDERAL CORP INCOME TAX -633.2 9055.0 9688.2-1530.0 11 SU8 TOTAL-INCOME TAXES -100.8 11235.0 11335.8.****** 12 TOTAL TAXES AT PRES RATES 14040.2 26192.0 12151.8 86.6 AT PROPOSED RATES 13 CALIF CORP FR ANCHISE TAX 13172.2 93S6.0 -3756.2 -26.7 14 FEDERAL CORP INCOME TAX 51354.2 35941.0 -15413.2 -30.0 15 $UBTOTAL-INCOME TAXES 64526.4 45327.0 -19199.4 -29.8 16 TOTAL TAXES AT PROP. RATES 78667.4 60284.0 -18383.4 -23.4 14-10

i.,

e

T.A B L E 14-8 SOGE--ELECTRIC OEPT TAKES BASED ON INCOME TEST YEAR 1981 UTILITY LN PRESENT RATES PROPOSED RATES

NO.

ITEM CCFT FIT CCFT FIT (A) (B) (C) (0) (THOUSANDS OF DOLLARS) 1 OPERATING REVENUES $ 296647.3 8 296647.3 8 431135.6 431135.6 l 2 0

• M EXPENSES 142894.7 142894.7 145718.5 145718.5 3

TAXES OTHER THAN INCOME 14141.0 14141.0 14141.0 14141.0 4 CCFT 0.0 532.4 0.0 13172.2 5 SUBTOTAL 157035.7 157568.1 159859.5 173031.7 6 DEDUCTIONS FROM TAXABLE INCOME 7 TAX DEPRECIATION 51712.0 55700.0 '51712.0 55700.0 8 INTEREST CHARGES 55977.0 55977.0 55977.0 55977.0 9 BENEFITS CAPITALIZED 9629.0 9629.0 9629.0 9629.0 10 AD-VALOREM TAXES 329.0 329.0 329.0 329.0 11 REMOVAL COST 3951.0 3951.0 3951.0 3951.0 12 REPAIR ALL0 HANCE 6097.0 6097.0 6097.0 6097.0 13 PREFERRED DIV CREDIT 0.0 530.0

0. 0 530.0 14 USE TAX 1125.0 1125.0 1125.0 1125.0 15 NUCLEAR FUEL 4655.0 4655.0 4655 0 4655.0 16 TAXABLE CIAC

-480.0 -480.0 -480.0 -480.0 17 RESEARCH & DEV COST 0.0 0.0 0.0 0.0 18 FISCAL / CALENDAR ADJ. 703.0 703.0 703.0 703.0 19 OTHER DEOUCTIONS 368.0 368.0 368.0 368.0 20 SUBTOTAL DEDUCTIONS 134066.0 138584.0 134066.0 138584.0 21 NET TAXA 8LE INCOME FOR CCFT 5545.6 137210.1 22 CCFT 532.4 13172.2 23 TOTAL CCFT 532.4 13172.2 24 NET TAXABLE INCOME FOR FIT 495.2 119519.9 25 FEDERAL INCOME TAX 227.8 54979.2 26 DEFERRED TAXES-0EPR. =58.0 -58.0 27 GRADUATED RATE BENEFIT -17.0 -17.0 28 ITC NORMALIZED -786.0 -786 0 29 FE0 INCOME TAX 8EFORE ADJ. -633.2 54118.2 l l 30 -ITC FLOWTHROUGH 0.0 -2764.0 ( ' 31 TOTAL FIT -633.2 51354.2 l 14-11 I

T.A.B L E lo-C 50GE--ELECTRIC DEPT DEDUCTIONS FOR TAX CALCULATIONS TEST YEAR 1981 LN ACCT. UTIL. EXCEEDS STAFF '.N O NO ITEM STAFF UTILITY AMOUNT PCT (A) (B) (C) (D) (THOUSANDS OF DOLLARS) i TAX DEPRECIATION 1 STATE 8 51712.0 3 52217.0 8 505.0 1.0 2 FEDERAL 55700.0 55807.0 107.0 0.2 3 INTEREST CHARGES 55977.0 54547.0 -1430.0 -2.6 4 8ENEFITS CAPITALIZED 9629.0 7448.0 -2181.0 -22.7 5 AD-VALOREM TAXES 329.0 3703.0 3374.0 1025.5 6 REMOVAL COST 3951.0 3951.0 0.0 0.0 7 REPAIR ALLOWANCE 6097.0 6097.0 0.0 0.0 8 PREFERRED DIV CREDIT 530.0 319.0 -211.0 -39.8 9 USE TAX 1125.0 1125.0

0. 0 0.0 10 NUCLEAR FUEL 4655.0 4655.0 0.0 0.0 11 TAXABLE CIAC

-480.0 -480.0 0.0 0.0 12 RESEARCH & DEVELCPMENT 0.0 -6777.0 -6777.0

0. 0 13 FISCAL / CALENDAR A0J.

703.0 0.0 -703.0 -100.0 14 OTHER DEDUCTIONS 368.0 368.0 0.0 0.0 INVESTNENT TAX CREDIT 15 FLOWTHROUGH -2764.0 -2764.0 0.0 0.0 i 16 NORMALIZED -786.0 -98.0 688.0 -87.5 l 17 OEFERRED T. AXES-0EPR. -58.0 -58.0 0.0 0.0 18 GRAOUATED RATE BENEFIT -17.0 0.0 17.0 -100.0 I l l 1L-12 e -mw r -w

s CHAPTER 15 E1ZCTRIC PLANT 1. This chapter contains the development of the staff estimates of total weighted average electric plant for San Diego Gas and'Electrie l Company for test year 1981. Tables 15-A and 15-B compare the staff and utility electric plant estimates for test year 1981. A summarization of the total weighted everage plant as estimated by the staff and utility is as follows: Test Year 1981 Table 15-B (Dollars in Thousands) Staff Utility Electric Plant $1,255,381 $1,260,082 2 The staff estimates are based on the results of field inspections of the utility's facilities, discussions with utility personnel responsible for construction budgets for the year 1980 and 1981. 3. The staff's estimates of plant in service reflect the recorded . plant in service at the beginning of year 1980, the staff's estimated plant additions for year 1980, and the staff's weighted average plant additions for test year 1981. 4 Utility's electric plant includes: electric production, electric transmission and electric distribution facilities. The major additions were in the area of transmission and distribution. 5. Much of the expenditures are due to, compliance with regulations for safe operation, additions to existing facilities to accommodate growth, j and promote efficient operation. Other significant additions are due to blanket projects. 6. Staff reviewed the additions and gave consideration to past expenditure levels and future requirements and concluded that the utility's estimates, except for the following differences, are reasonable. 7. Staff excluded $1,000,000 for estimated year 1980, which vus intended for San Onofre I seismic study, but was rescheduled to a co pletion date of December 30,.1982 Crable 15-A). 15-1

15 - ELECTRIC PLAST i 8. Staff is lower than the utility by $3,965,000 (Table 15-B), for estimated year 1981 and is the result of the weighted average net plant additions in rate base. 9. Retirement differences are the result of the adoption of different plant additions by the staff and the utility. Overhead to Undergrennd Conversion 10. Rule 20.A and the franchise of the City of San Diego requires, systematically, the undergrounding of overhead electric facilities. Through the years the utility has accumulated unspent amounts due to underspending the Commission in rates authorized amounts. The primary causes for the utility's failure to expend the authorized amounts for the projects were delays by the City of San Diego in converting street lights, attached to power poles, to free segnding units and delays for approval in related street improvements projects, which receive, funding from the State and the Federal Government. 11. The utility's budgeted estimates, as filed with the Commission, for 1980 and 1981 reflect amounts based on a previous adopted formula, l vhich is a requirement of the franchise with the City of San Diego. This formula is causing a rapid growth in the allocation of funds for undergrounding. As a result, the utility has approached the City of San Diego for another formula. Pending approval, the 1980 allocation was set at about the 1979 suthorized level and the 1981 sub=itted budget is set at $11,5h8,000, which is based on city plans as known by.the utility. 12. Included in both years' estimates are $1,600,000 per year for conversion of city-owned street lights from mercury vapor to more efficient high press (,2e sodium. 15-2 e e g p g,--v, w -ew-e o e m-

Table 15-A SAN DIEGO GAS & ELECTRIC CNPANY Electric Plant 1980 1981 Test Year Utility

Line :

Exceeds Staff

No.

Ites

Staff Utility : Amount Percent j

(a) (b) (c) (d) (Dollars in Thousands) 1 January 1, 1980 $1,023,666 $1,023,666 j 2 Additions 108,467 109,467 1,000 0.9 % 3 Retirements 6,480 6,540 (60) 4 Adjustments (R.F.S. Auto 's, P.O.E. l Transfers, etc.) 5,299 5,299 l 5 December 31, 1980 $1,130,952 $1,131.,892 $ 940 0.1 % 6 Common Plant Allocation $ 21,423 21,423 t 7 Total 1980 Planc $1,152,375 $1,153,315 $ 940 0.1 % l l 15-3

Table 15-B SAN DIEGO GAS 6 ELECTRIC COMPANY Electric Plant (1981) 1981 Test Year l l Utility

Line :

Exceeds Staff

No. :

Ites Staff Utility Amount Percent (a) (b) (c) (d) (Dollars in Thousands) 1 January 1, 1981 $1,130,961 $1,131,901 $ 940 0.1% l 2 Additions 106,475 110,440 3,965 3.7 3 Retirements 5,463 5,667 204 3.7 4 Adjustments (R.F.S. Auto's, P.O.E. Transfers, etc.) 53 53 5 December 31, 1981 $1,232,026 $1,236,727 $4,701 0.4% 6 Co m a Plant Allocation S 23,355 23,355 7 Total 1981 Plant $1,255,381 $1,260,082 $4,701 0.4% 15-4 n. i G w ,3 -,m w w* w ,.,.--y- = - * -,,

• w

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.g-+a y-y,e e-

,,vy-w -y y- --r

CHAP"IR 16 DEPRECIA':' ION EXICSI AND RESER7E 1. The staff offers no objection to the depreciatica rates used by San Diego Gas & Electric Ccepany for its nectric Depavent. PEdifferences between staff soi utility for the estinates of depreciatica expense and reserve for electric plant are explained by the lover plant esti=stes =ade by the staff 4 in Chapter 15. 2. The staff has reviewed the utility's esti= ate for deccc=dsioni g its share of San Onofre Nuclear Generating Station No. 1. The staff addressed the issue of whether the recovery of decoc=issioning costs should be retained by the utility in Southern California Edison's rate case (A-59351). 3 No additional information has been fortheming to dissuade the staff from its conclusion in the Edison rate case that esti=ated decer-issioning costs snould be recovered in the depreciation expense. 4 The staff, therefore, has the fo11cving recccrendations: 1. The accumulation of the esti=ated net deez nissioning costs should be recovered through the depreciation rates and retained by the utility, and should not be held in a separate escrow account. 2. SDG&E should file, with its next General rate applicatics, an exhibit assessing any changes in the cost of decct=issioning and its i= pact on the ff nancial integrity of the cc=pany. Such an exhibit should also be filed for any rate base offset procedure for San Onofre Nuclear Generati=g Station Units 2 and 3 16-2 i e

l TA BLE 16-A l 50GE--ELEC TRIC DEPT l OEPRECIATION AND AMORTIZATION EXPENSE TEST YEAR 1981 ~ LN ACCT. UTIL. EXCEEDS STAFF NO NO ITEM STAFF UTILITY AMOUNT PCT (A) (B) (C) (0) (THOUSANDS OF DOLLARS) 1 DEPRECIATION EXPENSE $ 49950.0 $ 50076.0 3 126.0 0.3 2 TOTAL DEPRECIATION EXPENSE 49950.0 50076.0 126.0 0.3 { l l l l l 16-2 9 w v

1 I CHAPTER 17 RATE BASE 1. This chapter contains the development of the staff's, estimate of the total weighted average rate base of SDG&E's for test yscr 1981. The following tabulation compares the staff and utility test year 1981 rate base as shown in Table 17-A. Test Year 1981 l Staff Utility Item (Dollars in Thousands) Electric Rate Base $1,055,h01 $1,129,302 Weighted Average Utility Plant 2. Weighted average utility plant is developed in Chapter 15 and carried forward. Nuclear Fuel 3. The nuclear fuel represents the nuclear fuel owned by the utility. The utility switched froe direct ownership to lease arrangement; there fore, no addition to nuclear fuel is anticipated. Plant in Service 4 Staff is lower than the utility by $1,126,000 of which $940,000 is discussed in Chapter 15 and $186,000 reflects the difference in amounts of the application and the utility's submitted workpapers. Plant Held for Future Use 5. Staff is lower than the utility by $9,618,900. Part of the amount I above is due to the difference of Commission authorized cancelled Sundesert site related costs as reflected in Decision No. 90405, and the utility's submitted enount in plant held for future use, tehich differenced to $367,900. l 6 The other part of the amount which totalled $9,251,000 is due to the staff's deletion of the two South Bay gas turbines originally purchased to be installed in 1974 at the utility's South Bay facility to provide 128 MW of peaking espacity. For various reasons, this initial project was cancelled and for the test year 1976 rate case the company had deferred the project to the year 1979. The staff learned that during 1979, the company attempted to sell the gas turbines, but withdrew apparently when the sale price was too low. 17-1 L

I 17 - RATE BASE Presently, there is no definite and specific engineering plans available for the application of the gas turbines. The company has attempted to identify possible uses for the two gas turbines in 11 uncertain future projects. Since the gas turbines do not provide useful service to customers and presently no definite and specific engineering application with a target date is available, the staff has excicded them from rate base. The staff auditors have likewise taken exception to this ites. An explanation of how this relates to Account 105 is contained in the staff's Resules of Examination report. 1 New Plant Additions 7. Staff's estimate is lower than the utility's by $1,902,000. The l staff's weighted average net plant additions for the test year was arrived at by applying a weighting factor of 4.43% to the plant-in-service amounc. This weighting factor is based on the 5 years average of the annual recorded, 13 months, weighted average additions. This is in accordance to procedures adopted in Decision No. 83746 (dated November 26, 1974). The utility also used 13 months weighting method based on uncertain future estimated dates of plant additions to go on line in a particular month. l Customer Advances for Construction 8. The customer advances for construction is an advance of construction fund pursuant to the rules set forth in tariff schedules. The amount advanced is deducted from rate base for it represents _ funds provided from the customers. The staff's estimate of c.ustomers advances for construction is higher than the 1 utility's by $919,000 and is arrived at by the same methodology as applied by the utility, except the staff had access to 1979 recorden sSta as opposed to the utility's 1979 estimated data. 17-2 I i

i l 17 - RATE 3ASE Puel in Storage 9 Staff's estimata is lower than the utility's estimate by $33,424,000 for test year 1981. Both the staff and utility used the same 13-month weighted average methodology in arriving at the estimated amount. Both staff's and utility's number include $11,185,000 for Nuclear Fuel. The staff adopted the fol'owing utility's estimated quantities in its computa-l tion for fuel in storage for test year 1981; Monthly Residual and Distillate fuel quantity purchases from Hawaiian Independent Rafinery Incorporated (HIRI), 1 Tesora Alaska Petroleum Company (TESORO) and Chevron U.S. A., Inc. (CHEVRON), including Exchanges Displacement Oil and Payback, Monthly total burn requirements for residual oil for Encino and South Bay planta and distillace a fuel for Silver Gate, Station B, Gas Turbine plant.s ad steam heat depart-ment; Monthly Residual 011 and Distillate fuel handling costs; Method of computing the moving average costs; Monthly estimate of fuel costs. l l 10. Staff reviewed the adopted quantities above for the estimated and test year, compared ct.es with past recorded amounts and future projected requirements from currently available information, and concluded that these amounts are reasonable. l 11. The staff adopted as being reasonable, after review of past recorded fuel deliveries, fuel burns, fuel in' storage, supplier's contractual i obligations, the utility's 1979 recorded monthly Day Burn average of 65 as the asount of fuel in storage for residual fuel, and which was arrived at in the following manner. 1979 Recorded Annual Fuel in Storage x 365 Day Burn = 1979 Recorded Annual Fuel Burned 12 17-3 h r r e.,.. wa..

i i 17 - RATE EASE l 64.7 Day Burn (Utility's 1979 recorded) 22.478.000 x 365 = 10,571,000 12 12. The staff adopted ss being reasonable, after review of past recorded day burns for distillate fuel, a monthly average Day Burn of 200, I as the mount of fuel in storage and which was arrived at in a similar manner as residual fuel. Distillace fuel is used in part by the utility for standby units at Silver Gate and Station B, and for peaking gas turbine units at Esarney and other. Since the amount of distillate fuel burned by these units, for the 1981 test year is of smaller magnitude.as compared to some recorded amounts in the past, a prolonged peaking requirement as longer than anticipated standby unit operation, may well exceed the required amount of 65 Day Burn as reccamended for residual fuel. The utility has requested the following estimated residual fuel monthly average Day Burn: 1981 Estimated Annual Fuel in Storage x 365 = Day Burn 1981 Estimated Annual Fuel Burned 12 l 32,412,000 x 365 84 Day Buru = l 11,729,000 12 i and for distillate fuel the following estimated monthly average Day Burn: 5,689,500 x 365 652.5 Day Burn = 265,200 12 i Oe G 9 e i 17-h l-i d l t k

17 - RATE BASE 13 The acility has current contracts with oil suppliers rmning well through the year 1982 Oil deliveries are scheuuled monthly with SDG8aE to specify the oil quantity ana cate or celivery. oWiss es oil ' suppliers incicated favorable oil-availability -throu h 198d. Recorded nonthly oil e celiveries have incicated a steady pattern. 14. Applicant states that Decision No. 90405 authorized a 45-day a fuel oil inventory in rate base. Staff found.that fuel in storage for test year 1979, of~ the previous rate case, was not an issue. The staff witness for test year 1979, adopted the utility's amount. 15 Applicant also states that the average inventory level for 1981 is projected at 3,000,000 barrels, which represents'a 70-day'inven+2ry or burn. Staff observed that if 3,000,000 barrels reflect a 70-day burn, then the following average monthly burn will apply: 3,000,000 365 l Average Monthly Burn 12 ~ "I /xarage Monthly Burn: 3,000,000 x 365 1,303,571 Bbis = 12 x 70 Annually this corresponds to: 12 x 1,303,571 = 15,642,857 Bbis Applicant's request reflects the following annual burn for test year 1981. l Residual 011: 11,729,000 Bbis Burn / Annual l Distillate Fuels 265,200 Bbis Burn / Annual 11,994,200 Bbis Burn / Annual l Gas Equiv. Burn : 3,668,000 Bbis Burn / Annual i Total Burn: 15,662,200 Bbla Burn / Annual (Easid. + Distil. + Cas) I j 16 From the foregoing it is apparent that applicant in its [ computation of the fuel in inventory day burn, has completely disregarded ( the availability of gas as a partial source of energy. l 17-5 i i

~ 1 17 - RATE 3ASE i 17. Exhibit No. 3, in Application No. 55780, SDGEE's witness, Gregory L. Nesbitt, prepared direct testimony, dated February 27, 1978, states the following regarding SDGEE's miniman inventory requirement on i l page 9, question 15, answer 15. l l "3DG&E's minimum inventory requirements must be maintained l at between 0.8 and 1.2 sunbbis, depending upon the time of year. Historically, high fuel oil burn rates occur during the summer and winter months. It is at these times that inim = inventory requirement is highest. Independent of the time of year, the company must maintain this rarge as a 30-day minimum fuel oil supply to protect against delays in deliveries, refinery strikas or other supply disruption." 18 The following table shows the weighted costs for Fuel in Inventory and other pertinent specifics for the recorded yeses 1977 through 1979 and Test Year 1981. ruel in theusands of Barrels j Dollars in thousands l l 1977 1978 1979' 1981 Test Year Staff Utility Averste Monthly Fuel in Inventerv Residual 2,436.3 2,923.5 1,873.3 2,088.9 2,701.0 Distillate 479.5 393.0 415.9 145.3 474.1 Total 2,915.8 3,316.5 2,289.2 2,234.2 3,175.1 Weighted Average Cost of Fuels in Inventorv $59,257.5 $71,659.4 $58,665.0 $108,105.0 $141,529.0 Average Month 1v Fuel Burned Residual 973.5 823.4 880.9 977.5 977.5 Distillate 78.9 77.6 23.8 22.1 22 JL l Total 1,052.4 901.0 904.7 999.0 95 M l l I 17-6

i 17 - EATE 3ASE Verking Cash Allevance 19 In anovance for working cash is included in rate base in order that the investors may be coerpensated fer monies they have supplied over and above the investments in properties. The allevance is based en the average lag in collection of revenues and payment of expenses, as well as maintaining mini =u= bank balances, working funds, and certain deferred debits and credits. 20. The main difference between the staff and utility is due to differences in various lag days. The staff has increased the lag days for fuel oil, federal inecce tav. atate corocrate franchise tax, anc reducea lag days for revenues and benefits. 21,, The utility used zero lag days for fue3 Sil. This is not proper because r there are 22.06 days of lag between the delivery of fuel oil and actual payme=t for the delivery of fuel oil. The staff used a lag of 22.06 days for fuel oil. l 22 The utility arrived at the revenue lag days based on average daily l accounts receivables by the amount of average daily collections. Since the average daily accounts receivables include potential uncollectible accounts receivables, it, therefere; overstates revenue lag days. In order to offset such overstated revenue lag, the staff reduced the accounts receivables by the a= cunt of average uncollectible accounts receivablesincluded in the accounts receivables resulting in a reduction of 0.21 days. Uncollectible expenses are excluded from lead-lag study. Uncellectibles is an accounting entry for unrealized revenues and it is net a cash expense item. The staff also increased the federal and state income tax lag days to 103.65 compared to the utility's las days of 81.60 days, giving the effect of paying 80% of tax liabilities by the end of the year and an IRS revenue ruling allowing the utility to deduct 100% of property tax frc= the first quarterly tax liability. 23 The staff also increaeer. the las days of benefits to-2.6c days based en detailed expense lag-day study. The utility arbitrarily used zero lag days. Re=aining differences are due to different staff's expense estinates and inecce taxes and franchise require =ents are coc:puted c= a 10 59% rate of return. 17-7

.-....~.. - - --.-.-- TABL E 17-A SOGE--ELECTRIC DEPT WEIGHTED AVERAGE DEPRECI4TED RATE BASE TEST YEAR 1951 LN ACCT. UTIL. EXCEEDS STAFF NO NO ITEM STAFF UTILITY' AMOUNT PCT (A) (B) (C ) (0) (THOUSANDS QF DOLLARS) 1 BEG. BALANCE-FIXE 0 CAPITAL 2 PLANT IN SERVICE 3 1152375 31153501 3 1126 0.1 3 PLANT HELO FOR FUT USE 49478 59097 9619 19.4 4 RESEARCH AND DEV. 2060 4121 2041 100.0 5 SUBTOTAL 1203913 1216719 12806 1.1 6 NET PLANT ADDITIONS 51050 52952 1902 3.7 7 TOTAL FIXED CAPITAL 1254963 1269671 14708 1.2 8 CUST ADVANCE FOR CONST -20620 -19701 919 -4.5 9 WORKING CAPITAL 10 FUEL STORAGE 108105 141529 33424 30.9 11 MATERIALS & SUPPLIES 19392 19392 0

0. 0 12 WORKING CASH 37078 61904 24826 67.0 l

13 TOTAL WORKING CAPITAL 164575 222825 58250 35.4 14 TOTAL BEFORE RESERVES 1398918 1472795 73877 53 l 15 RESERVES l 16 DEFERRE0 INCOME TAXES 401 401 0 0.0 '17 DEPRECIATION 330065 330041 -24 0.0 -18 AMORIZATION & OTHER 13051 13051 0 0.0 19 TOTAL RESERVES 343517 343493 -24 0.0 20 TOTAL RATE BAS $ 1055401 1129302 73901 7.0 e D 17-8

TABLE 17-3 (Sheet 1 et 2) San Diego Gas & Electric Cergany Electric Departnent WRKING CASH ALIDWAUCE ST'JDY Year 1981 Estinated /

Line:

nectrie

No.:

Item

Department :

(A) (Donars in Thousands) Operational Cash Recuirements 1 Compensating Minimum Bank Balances $ 5,086 2 Special Deposits and Working Funn: 70 3 Miscenaneous Receivables 2,263 h Prepayments 1,315 5 Deferred Debits 3,794 6 Total Operational Cash Requirements 12,525 Deductions for the Acounts Not Supplied by Investors 7 Accrued Vacations, Sick Leave and Withholdings 4,430 8 Accounts Payables 5,890 9 User Taxes 216 10 Customer Deposits h,llo n To'tal Deductions 14,6k6 12 Average Amount Needed as a Result of Paying Expenses, Taxes and Depreciation in Advance of Conecting Revenues 39,885 13 ' Total Working Cash Allowance 37,764 i i e o a 17-9

~ ^ TABLE 17-3 (Sheet 2 of 2) $0GE--ELECTRIC OEPT DEVELOPMENT OF AVERAGE LAG IN PATMENT OF EXPENSES $ 1000 AVG DAY LAG $ 1000 A 8-C=A X 8 FEDERAL INCOME TAX $ 12635.20 103.65 $1309638.00 STATE INCOME TAX 4233.60 103.65 438812.70 FRANCHISE REQUIREMENTS 6460.40 159.81 1032437.00 FUEL OIL 504088.00 22.06 11120180.00 i PURCHASED GAL 101233.00 37.82 3828632.00 NUCLEAR FUEL 4020.00 0.00 0 00 COMPANY LA80R 48802.00 12.77 623201 50 PURCHASED POWER 60864.00 31.34 1907478.on GOODS & SERVICES 62865.00 29.91 1880292.00 EMPLOYEE SENEFITS 8416.00 -2.60 -21881.60 MISC. TAX 2.00 0.00 0.00 FEDERAL UNEMPLOYMENT TAX 85.00 72.04 6123 40 FICA TAX 2821.00 T.59 21411.39 l A0 VAL 10893.00 43.01 468507.90 OEPRECIATION 49950.00 0.00 0.00 i MATERIALS FROM STORER0OM 1563.00 0.00 0.00 STATE UNEMPLOYMENT TAX 340.00 T2.04 24493 60 ENCINA 5 LEASE EXPENSES 9302.00

91., )

860435.00

• MISC. RES.

3441.00 0.00 0.00 TOTAL 892014 20 23499770.00 EXP LAG DAYS = C/A = 26.34 REVENUE LAG DAYS = 42.38 i A0JUSTMENT TO RATE BASE 39199.74 NEW RATE 8ASE= 1012202.0 + 39199.T= 1051402.0 17-10 -a

-^ CF N 18 SLEMARY OF FX4:iUGS 1. The revenues, expenses, taxes and depreciation expenses developed in the preceding chapters of this report for San Diego Gas & Electric Ccepany, Electric Department, are brought together here in order to develop the net revenues and to determine the rate of return based en present rates and also at preposed e rates. 2. In Tables 18-A and 18-3 are shown eccparisons of staff and utility sw/ of earnings for the 1981 test year esttnated at present and utility proposed base rates, respectively. The utility showing is free its original application filed July 1, 1980. 3. A suesnary of the principal assim:ptions and rate-fixing adjustments reflected in the staff estimates is as follows: A. The staff's revenues are based on higher esti=ated sales resulted in a $21,563,000 difference at proposed rates. i B. The major differences in production expenses are due to enviren-l . mental expenses and fuel related expenses associated with Depart 2 tent of '4ater Resources sales (DWR). The staff's environmental expense esti=ates reflect five-year amortizations of expected expenses, and are lever than the utility by $516,200. The staff's exclusion of $10,900,000 for :F4 expenses reflects the staff's position in OII-56. 1 C. The ::ajor difference in tramission expenses is due to the exclusien by the staff of $1,512,800 for wheeling charges. This is based uoan the staff's reccammendations in CII-56. D. ACC. 588 (Miscellaneous Distribution Expenses [ - Due to =cre recent data on the DyIS pregram and different estimating =ethods, the staff's esti= ate was $1,162,200 lower than the utility's. 18-1 l k

4 18 - SIMARY OF EAFRINGS E. ACC. 593 (overhead Lines Expenses) - Staff disallowed $400,000 requested for additional tree tr % ing. F. ACC 594 (thierground lines Expenses) - Ihe staff's estimated rate of growth for this account was lower than the utility's and resulted in a $401,900 adjustment. G. ACC. 903.7 (Postage Expenses) - Staff did not include postal rate increase for 1981. Staff's estinate is $961,400, $354,200 lower than utility's. H. The staff has made a $5,533,900 adjustment in SDG&E's conservation estimates. Details of this adjustment are shown in the conservation report. I. Staff's ad valorem taxes are approximately $816,000 lower than the utility's. This difference is primarily due to the method 2 sed to allocate total ccupany ad valorem taxes between operative plant and CWIP. J. The staff's estimate of income taxes follows the Commission's policy as expressed in previous decisions. Major differences result from the deductions for capitalized benefits and R&D as it relates to Heber. K. The staff adjusted rate base by $33,424,000 as a result of usi=g a 65-day burn for fuel storage as compared to the Utility's 84-day burn. L. l A wage adjuztment of $1,240,400 was made by the staff. This amount l reflects the difference between a 13.55 and 11.0% wage increase. Net-to-Gross Multiolier 4. The net-to-gross multiplier for the test year 1981, which is the ratio of the gross revenue required to preduce a unit change in net rt tenue, l l l 18-2 i

s 13 - SINMARY CF FAP2TrTGS is 2.092 for sales to electric custccers. This =earr that an ine,rease of $2,092 in gross revenue is required to produce an increase of $1,000 in net revenue. The net-to-gross multiplier is developed as follevs: Gross Operating Revenue 100.0000 Less: theollectibles at 0.155 0.15 Subtotal 99.8500 Less: Franchisst Requires:ents at 1955 1 9h7 Subtotal 97 903o State Ine:xte Tax at 9.$ 9 3o87 Subtotal 88.5ch3 Federal Income Tax at h6 LO.7120 Remainder 47.7923 Net-to-Gross Multiplier 2.0924 (Gross Revenue Divided by Re=ainder) i l l l e 18-3

l l TA BLE IS-A i 50GE--ELECTRIC DEPT i

SUMMARY

OF EARNINGS TEST YEAR 1961 AT PRESENT RATES LN NO UTIL. EXCEEDS l ITEM STAFF STAFF UTILITY AMOUNT PCT (A) (9) (C) (0) (THOUS ANDS OF DOLLA RS) 1 OPERA TING REVENUES 2 REVENUES 3 TOTAL OPERATING REVENUES $_296647.3 $ 282943.0 $ -13704.3 -4 6 296647.3 282943.0 -13704.3 -4 6 l 4 OPERATING EXPENSES 5 PRODUCTION EXPENSE 6 TRANSHISSION EXP. 52290.7 63764.7 11474.0 21.9 7 OISTRIBUTION EXPENSES 6793.2 8648.7 1855.5 27.3 8 CUSTOMER ACCT. 22870.6 25101.3 2230.7 9.8 1 9 MARKETING EXPENSES 10598 2 11259 6 661.4 62 i 10 ADMIN. & GENER. EXP 9268 1 14802.0 5533.9 59.7 - 42314.1 43750.0 1435.9 3.4 11 SUBTOTAL 144134.9 167326.3 23191.4 16 1 12 WAGE A0J. i 13 SUBTOTAL AFTER W AGE A0J. -1260.2 0.0 1260.2 -100.0 142894.7 167326.3 24431 6 17.1 14 DEP AND AMORT 15 TAXES CTHER THAN INCGME 49950.0 50076.0 126.0 0.3 16 CALIF CORP FRANCHISE TA X 14141.0 14957.0 816.0 5.8 17 FE0 CORP INCOME tax 532.4 2180.0 1647.6 309 5 l -633.2 9055.0 9688.2-1530.0 l 18 TOTAL OPERATING EXPENSES 206884.9 264594.3 36709.4 17.7 19 NET OPERATING REVENUES A0 JUSTO 89762.4 39348.7 -50413.7 -56 2 20 RATE BASE 1055401.0 1129302.0 73901.0 7.0 21 RATE CF RETURN i 8 51% 3.48% -5.0 3% W 4 18-4 l

TABL E 18-9 SOGE--ELECTRIC DEPT

SUMMARY

OF EARNINGS PROPOSED RATES-TEST YEAR 1981 LN UTIL. EXCEEDS STAFF NO ITEM STAFF UTILITY AMOUNT PCT (A) (8) (C ) (0) (THOUSANDS OF 00LLARS) 1 OPERATING REVENUES 2 REVENUES 3 431135.6 3 409573,0 3-21562 6 -5.0 3 TOTAL OPERATING REVENUES 431135.6 409573.0 -21562.6 -5.0 4 OPERATING EXPENSES 5 PRODUCTION EXPENSE 52290.7 63764.7 11474.0 21.9 6 TRANSMISSION EXP. 6793.2 8648.7 1855.5 27.3 7 OISTRIBUTION EXPENSES 22870.6 25101.3 2230.7 9.8 8 CUSTOMER ACCT. 10800.0 11450.0 650.0 6.0 9 MARKETING EXPENSES 9268.1 14802.0 5533.9 59.7 10 ADMIN. A GENER. EXP 44936.1 46219.0 1282.9 2.9 11 SUBTOTAL 146958.7 169985.7 23027.0 15.7 12 WAGE A0J. -1240.2 0.0 1260.2 -100.0 13 SU8 TOTAL AFTER WAGE A0J. 145715.5 169985.7 24267.2 16.7 14 DEP AND AMORT 49950.0 50076.0 126.0 0.3 15 TAXES OTHER THAN INCOME 14141.0 14957.0 816.0 5.8 16 CALIF CORP FRANCHISE TAX 13172.2 9386.0 -3786.2 -28.7 17 FE0 CORP INCOME TAX 51354.2 35941.0 -15413.2 -30.0 18 TOTAL OPERATING EXPENSES 274335.9 280345.7 6009.8 22 19 NET OPERATING REVENUES ADJUST 0 156799.7 129227.3 -27572.4 -17.6 20 RATE BASE 1055401.0 1129302.0 73901.0 7.0 21 RATE OF RETURN 14.86% 11.44% -3.42% 13-5

CHAPTDL 19 1 JURISDICTIONAL COST ALLOCATION 1. The purpose of this chapter is to segregate San Diego Cas' & Electric Cogany's electric revenues and to allocate electric expenses and rate base items between those subject to the jurisdiction of the California Public Utilities Commission and those subject to the jurisdiction of other regulatory agencies. 2. The United Scates Supreme Court, by ununheus decision of March 2,1964, reported in 376 US 205, held that the Federal Power Commission had jurisdiction over all sales of electric energy at wholesale in interstate cosnerce not expressly exempted by the Federal Power Act itself. This decision necessitated the juris-dictional cost allocation analysis. l l 3. Costs associated with the operation of the Pacific Intertie are allocated on the basis of a special study which has bee used in other proceedings before this Coanission. 4 All energy costs and related revenues have been excluded. These costs and revenues are treated separately in a special ECAC proceeding before this Commission and the Federal Energy Regulatory Cocunission. 5. The staff has examined the various allocation factor calculation methods used by the utility and is of the opinion that they are reasonable. They have been utilized by the staff for the purpose of this report, and they are consistent with the previous decisions. l 6, Tables 19-A and 19-B=====rize the results of the jurisdictional cost separation at present and company proposed rates for 1981 test year. The separation distinguishes between the California Public Utilities C:munission (CPUC) regulatory jurisdiction and that of the Federal Energy Regulatory Comnission (FERC). [ 7. Colunas (A) reflects systems total figures as set forth in Chapter 18 of the staff's results of operations report for the Electric Depart:nent. Column (C) consists of revenue and expenses subject to FERC jurisdiction and Column (E) con-sists of revenue and expenses subject to the jurisdiction of the lifornia Public Utilities Commission as calculated by the staff. Colu:nns (B), (D, and (F) represent equivalent utility figures in Tables 19-A and 19-B. 19-1

I t i TA8LE 19 - A SAN DIEGO GAS AND ELECTRIC COMPANY I ELECTRIC DEPARTMLNT i COST ALLOCATION

SUMMARY

TEST YEAR 1981 - SOGRE PRESENT RATES a TOTAL 3 FERC CPUC 'tLINEt SYSTEM JURISDICTIONAL JURISOICTIONAL l 8 NO. ITEM STAFF UTILITY : STAFF

UTILITY :

STAFF

UTILITY

{ (A) (8) (C) (D) (E) (F) l (DOLLARS IN THOUSANOS) i 1 REVENUEL 1 29664T S 282943 5 890 1 849 8 295T5T 1 282094 l l OPERATING EXPENSES i 2 PRODUC T I ON 52291 63T65 21 26 52270 63T39 l, 3 TRANSMISSION 6793 8649 172 219 6621 8430 4 DISTRIBUTION 228T1 25101 0 0 228T1 25101 f: I e5 CUSTOMER ACCOUNTS 10598 11260 0 0 10598 11260 '? 6 MARMETING EXPENSE 9268 14802 0 0 9268 14802 "7 ASG 42314 43750 121 125 42193 43642 8 WAGE ADJUSTMENT -1240 0 -3 0 -123T 0 9 SU8 TOTAL 142895 167327 311 370 142584 166974 10 DEPRECIATION 49950 500T6 164 164 49T86 49912 i 11 TAXES OTHER THAN INCOME 14141 1495T 46 49 14095 14908 12 INCOME IAXES -101 11235 109 59 -210 11176 13 TOTAL OPER. EXPEhSES 206885 243595 630 642 206255 242970 ~ 14 NET REVENUE 89T62 39348 260 20T 89502 39124 15 RATE BASE 1055401 1129302 224F 2404 1053154 1126898 16 RATE OF RETURN (PERCENT) 8.51 3.48 11.57 8.61 8.50 3.47 l l l l

~ TABLE 19 - 8 SAN DIEGO GAS AND ELECTRIC COMPANY ELECTRIC DEPARTMENT COST ALLOCATION

SUMMARY

TEST YEAR 1981 - SOG AE PROPOSED RATES TOTAL FERC CPUC sLINE: SYSTEN JURIS0!CT!0NAL 8 JURISOICTIONAL r a NO. ITEN 3 STAFF

UTILITY :

STAFF 3 UTILITY STAFF

• UTILITY :

(A) (8) (C) (0) (E) (F) (00LLARS IN THOUSAN05) 1 REVENUE s 431136 s 409573 s 890 s 849 8 430246 5 408T24 OPERATING EXPENSES 2 PRODUC TI ON 52291 63T65 21 26 522T0 63T39 3 TRANSNISSION 6793 8649 172 219 6621 8430 4 DISTRIBUTION 228T1 25101 0 0 228T1 25101 5 CUSTOMER ACCOUNTS 10800 11450 0 0 10800 11450 $6 NARKETING E XPENSE 9268 14802 0 0 9268 14802 aT AAG 44936 46219 121 125 44815 46094 8 WAGE ADJUSTMENT -1240 0 -3 0 -1237 0 9 SUBTOTAL 145719 169986 311 3T0 145408 169616 10 DEPRECIATION 49950 50076 164 164 49786 49912 11 TAXES OTHER THAN INCOME 1.4141 14957 46 49 14095 14908 12 INCOME TAXES 64526 45327 109 59 64417 45268 13 TOTAL OPER. EXPENSES 274336 280346 630 642 2T3706 2T9704 14 NET REVENUE 156800 129227 260 20T 156540 129020 15 RATE BASE 1055401 1129302 2247 2404 1053154 1126898 16 RATE OF RETURN (PERCENT) 14.86 11.44 11.57 8.61 14.86 11.45

~ t TA8LE 19 -C / SAN OIEGO GAS AND ELECTRIC COMPANY I ELECTRIC DEPARTMENT STAFF TAM CALCULATIONS AT PRESENT AND PROPOSED RATES j TOTAL FERC CPUC

• LINE:

SYSTEM JURISDICTIONAL 3 JURISOICTIONAL NO. ITEN PRESENT

• PROPOSED: PRESENT a PROPOSED: PRESENT PROPOSE 0s (A)

(B) (C) (0) (E) (F) (00LLARS IN THOUSANDS) 1 OPERATING REVENUES S 29664T $ 431136 8 890 s 890 s 29575T 1 430246 2 0

• M EXPENSES 142895 145T19 311 311 142584 145408 3

TAXES (OTHER THAN INCOME) 14141 14141 46 46 14095 14095 1 4 SUBTOTAL 15T036 159860 357 35T 1566T9 159503 I 5 CCFT DEDUCTIONS 134066 134066 295 295 133771 1337T1 6 TOTAL DEDUCTIONS (4*5) 291102 293926 652 652 290450 2932T4 $T NET TAXABLE INCOME (STATE) 5545 137210 238 238 530T 1369T2 1:. 8 CCFT 532 131T2 23 23 509 13149 9 ADJUSTMENTS 0 0 0 0 0 0 10 TOTAL STATE TAX 532 13172 23 23 509 13149 11 SU8 TOTAL EXPENSES (4*8) 157568 173032 380 380 15T188 172652 e 12 FIT DEDUCTIONS 138584 138584 305 305 138279 138279 13 TOTAL DEDUCTIONS (11+12) 296152 311616 685 685 29546T 310931 14 NET TAXABLE INCOME (FEDERAL) 495 119520 205 205 290 119315 I 15 F IT 228 549T9 94 94 133 54885 l 16 JOIC, DEFERRED TAX + SURTAX -861 -3625 -8 -8 -853 -361T l 1T TOTAL FIT -633 51354 86 86 -720 51268 l l 18 TOTAL INCOME TAX (10+173 s -101 5 64526 s 109 s 109 s -210 1 64417 l l l TAXES AT PRESENT RATES ROUNDEO OFF l l

CHAPTER 20 RECOMATIONS The Comission staff recommends that: 1. Department of Water Resources expenses should be included in ECAC. l 2. Variable wheeling expenses be included in ECAC. 3. The wage increase expenses be adjusted prior to the Commission's decision to reflect the latest consumer price index available. 4 Until the postal increase receiw s final approval, no postal increase should be included in the test year expenses. 5. If SDG&E sells the Niland facility prior to the Conunission's decision, the sale should be reflected in the test year estimates. 6. Without prior approval, SDG&E should not be allowed to cut major R&D program expenditures. 7. SDG&E be allowed to recover construction and demonstration expenses for the Heber Geothermal Project on a dollar-for-dollar basis with no allousnce for potential tax liability. 8. The accumuistica of the estimated not decommissioning costs should be recovered through the depreciation rates and retained by the utility. 9. The actual lag between the date of delivery and payment for fuel oil be included in the working cash allowance calculation. l \\ i o M-1 --,--e- --.,.--,r,----e- --.r+ r-v---, --v ---m= n' 'ev -- --= --ww-- - - ' - ' -- - ' - - - ' * - "-e-+- - - '- * "'}}