ML19347D268
| ML19347D268 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 12/31/1979 |
| From: | Christie H, Haub A, Horton J SOUTHERN CALIFORNIA EDISON CO. |
| To: | |
| Shared Package | |
| ML13302A498 | List: |
| References | |
| 59351, NUDOCS 8103110698 | |
| Download: ML19347D268 (244) | |
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500THE AN C AllFORNI A E0150N COMPANY P8EPARED TESTIMONY TA8tt OF CONTENTS witness G E NE R A L C ONS I D E RA t l 0NS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Jack K. Norton F i kANC I AL C HAR AC TE R I S TI CS - EX H i 8 l f No. (5C E -1 ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . H. Fred Christle EXHIBITS RtSULTS OF OPERATIONS - EXHIBIT NO. (5CE-2)
Chapter No.
1 INTRODUCTION )
2 H IS TORY )........................................ Robert P. Haub 3 PRESENT OPERATIONS) 4 BALANCE SHEET )
5 I NCOME AND RETAI NED E AAN I NGS S TATEMENTS ) . . . . . . . . . . . . . . . . . . Anthony L. Smi th 6 CLEARING ACCOUNTS )
7 KILOWATTHOUR SALES. CUSTOMERS. AND OPERATING REVENUES KWH. KW, Customers ................................... N. D. Whyte Revenues'............................................ Warren E. Ferguson 8 POW E R PRO DUC T I ON EX PE NS E S ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ronald V. Knapp
, 9 TRANSMIS$10N EXPENSES )
10 DISTRIBUTION EXPENSES ) Alan J. Valker 11 C US TOME R AC C 00NT S E X PE NS ES ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12 CUS TOMER S E RV I CE AND I NFORMATI ONAL EX PENS ES . . . . . . . . . . . . . . . .
M rgo A VIs' 13' ADMINISTRATIVE AND GENERAL EXPENSES Adminis t ra ti ve and Gene ral Expense s ' . . . . . . . . . . . . . . . . . . Ray V. Scofield
' Ad v e r t I s i n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ed.ard A. Myers. Jr.
Plant Abandonment Costs .............................. M. D. Whyte 14- TAXES ......... ................'........................... James S. Pignatelli 15 ELECTRIC PLANT )
16 - DE PREC I ATI ON E X PENS E AND RES E RVE) . . . . . . . . . . . . . . . . . . . . . . . . . . Larry 0. Chubb
-17 RATE BASE - )
18 ^
SUMMARY
OF EARNINGS ....................................... Rodney L. Larson 19 TARlFF CONSIDERATIONS .
C os t o f 5 e rv i ce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rodney L. Larson Rate Design .......................................... Warren E. Ferguson
'20 CONCLUSIONS N A'D RECOMMENDATICNS ........................... Ronald Daniels
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$/o3 (l c(A3
SOUnlERN CALIF 04NIA EDISON COMPANY Prepared Testimony of Mr. Jack K. Horton (General Considerations) 1 Q. Please state your name and address for the record.
2 A. My name is Jack K. Horton and my business address is 2244 Walnut Grove 3 Avenue , Rosemead, California.
4 Q. What is your occupation?
S A. I am Chairman of the Board of Directors and Chief Executive Officer of 6 the Southern California Edison Company.
7 Q. For the record, please briefly summari:e your qualifications.
8 A. I. am a graduate of Stanford University in 1936 and Oakland College of Law 9 in 1940.
10 From 1943 to 1944, I was employed by Standard Oil Company of 11 California as an attorney.
12 From 1944 to 1951, I was the Secretary and Legal Counsel of 13 Pacific Public Service Company and its subsidiaries. The subsidiaries 14 included two pipeline companics, a gas and electric utility company, and 15 a : company engaged in the exploration and production of natural -gas. I 16 was elected Executive Vice President for this group of companies in 17- March 1951 and President in March 1952.
'18 From May 1954 to February 1959, I was Vice President of Pacific
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19- Gas and Electric Company.
20 In 1957, I was' elected President of Alberta and Southern Gas 21- Company and Alberta Natural Gas Company, which were Canadian subsidiaries
'22. _- of Pacific Gas and Electric Company.
23 On February 1,1959,'I was elected President of the Southern
'J K11 27 79
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Jack K. Horten 1 California Edison Corpany. In April 1965, I was elected President an d 2 Chief Executive Officer and in April 1965. I was elected to ny present f 3 position.
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4 Q. Mr. Horten, why is Edison seeking a general rate increase at this tice?
5 A. Edison's financial perfornance in 1950 and 19S1 is expected to deteriorate '
6 to below acceptable levels, with the earned rate of return and return en 7 connon equity projected to be consiocrably belcw the levels authori:ed by S the Co==ission in Decision No. 89711. This deterioration is forecast to 9 be caused by rising imbedded debt and preferred stock costs , cost 10 increases stenning fron a geaeral inflation rate in excess of Si, 11 additional costs icposed by legislative and regulatory reqairenents 12 without adding to output, and additions to rate base. Substantial rate 13 relief is an absolute necessity in 1981 if a decrease in Edison's 14 financial integrity, credit standing, and ability to centinue to attract 15 capital is to be a._;ded.
16 The Company appreciates the progress made by the Cc=nission in 17 its 1979 decision. The return on co= mon equity was increased to a sore IS appropriate level, rate relief was effective for the full test year, and 19 the regulatory tine was reduced to 14 conths free filing the application 20 to decision. However, subsequent to that decision, the inflation rate rose.
21 financial costs increased, additional regulatory and legislative requirements 22 . were icposed, and the rate base increased substantially (on a projected 23 basis) with the addition of San Onofre Unit No. 2. With the advent of the 24- Three Mile Island incident, world fuel oil and natural gas problens, and the 25 deterioration of general econo =ic conditions, investors perceive electric 26 ' utilities as more risky and now require a higher return in order to be 37 attracted. As a result , the cost of debt and preferred stock have 2S risen since the Commissica authori:ed Edisen a 13.49% return on cocaon JKH-2 8-37-79
Jack K. Horton 1 equity for 1979, and the Company's conmon stock reice remains well below book 2 value, indicating that the authorized return an common equity is inadequate.
3 Q. What is the purpose of your testimony?
5 A. The purpose of my testimony is to provide the general framework upon which 6 Edison's request for rate relief is based. More specifically, I intend to 7 discuss:
d 1. The reasons for the expected earnings decline.
9 2. What Edinan has done to reduce financial and operating costs, 10 increase productivity, and optimize the funds required to 11 provide necessary production, transmission, and distribution 12 facilities.
13 3. The need for timely and adequate rate relief, lk h. The need for a rate of return allowance to compensate for the 15 1982 earnings erosion resulting from the expected increases in 16 imbedded debt and preferred stock eosts, in operating and 17 maintencree costs exclusive of fuel and income taxes, and in 18 rate bast resulting primarily from the addition of San Onofre 19 Unit No. 2.
20 5 The need for a balancing account to compensate for that portion 21 of the erosion in rate of return attributable to the addition 22 of San Ono r e Unf L No. 2 to rate base since its impact on 23 earnings during 1981 is not reflected in the request for rate 24 relief in this filing.
25 . Q. What is the primary financial cause of earnings erosion?
26 A. Financings are expected to cause considerable earnings erosion during the 27 1979-1983 period. This is primarily because a substantial amount of debt and 28 preferred stock are forecast to be sold at vell in excess of imbedded costs 29 during the period.
H-3 12-18-79_
Jack K. Ilorton 1 Edison's cash needs attributab7e to its construction program 2 and refundings during the 1979-1983 period are expected to total $3.4 3 billion, an increase of 42% over the cash requirement during the 1974-1978 4 period. Even with the rate relief requested in this application and 5 sufficient 1983 rate relief to provide about a 15% return on comon 6 equity, Edison's dependence on financial markets for cash funds would be at 7 about the 70% level, or $2.4 billion during the 1979-1983 period. To 8 emphasize the magnitude of this financing need, the $2.4 billion financint' 9 requirement is 71% greater than the $1.4 billion requirement during the 10 1974-1978 pe riod.
11 In addition, Edison cannot maintain its financial integrity, 12 credi+. standing, and ability to attract capital if its dependence on 13 external sources for cash funds remains at about 70t,in the long run.
14 .llowever, for the 1979-1983 period, such a level may be the minimum 15 acceptable. This is because appropriate rate relief in 1981, 1982, and 16 1983 should sharply reverse the serious -level of 95% dependence from 17 external sources in 1979 and 1980. This further emphasizes the importance 18 of sufficient and timely rate relief with adequate provision for attrition 19 during the 1981-1983 p eriod.-
20 The cost of debt and preferred stock financings in .1982, even
-21 with sufficient and timely rate relief with adequate provision for attrition, 33 will be much higher thin'in the past. Debt and preferred stock financing 23 costs are expected to average abour 9.75*..and 9.50% during the-1979-1983 24 period. .These costs, along with the amount of financings required, will
- 25. 'ncrease imbedded costs to about 8.03% for debt 'and 7.80% for preferred
-26 stock in'1981. The. imbedded. cost' increases alone in 1982 will result in
.27 - a'37 basis point drop in the return in comon equity in that year.
'28 Q. Has Edison's return on common equity been adequate?.-
JKH-4 5-15-79
Jack K. Horton 1 A. Edison's price / book ratio has remained well below one for the entire 2 period since 1972. This price performance indicates that investors do 3- not believe Edison's return on common equity has been adequate.
4 Q. What did these inadquate carnings cost Edison common stockholders?
5 A. The 19 million shares of common stock which were sold below 6 book value during the 1974-1978 period 7 reduced existing common shareholders' book investment by about 10.15 8 per share during the period. This also means that all prospective 9 carnings per share have been reduced by the same 10.1% because or nings 10 per share are derived from book investment per share.
11 Q. If Edison had been able to sell shares at book value during the 1974-1978 12 period, how many fewer shares would have been sold?
. 13 A. Edison would have sold 6.4 inillion fewer shares during the 1974-1978 14 period to raise the same amour.t of common equity capital it actually 15 raised by issuing 19.1 million ' shares, a potential 34% reduction.
16 Moreover, If Edison had been able to sell 6.4 million fewer shares, its 17 dependence on capital markets for funds to build plant would have been 18 substantially reduced. For example, at the current annual dividend rate
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19 of $2.72 per share, the Company has to_ pay about $17 million more annually 20 in dividends than it would have if common stock had been sold at book value 21 since 1973. Therefore, not only has the issuance of common stock been 22' be' low book value, ther(by eroding earnings per share and shareholder worth, 23 . but it also has' placed additional pressure on Edison's financing needs because 24 of the increased dividend requirement.
25 Q. How do operation and maintenance costs contribute to earnings crosion?
26 A. The general rate of inflation is expected to exceed 8% during the 1979-
- 27 1983 period compared to an annual trend rate of about 7*. during the 1974-28- - 1978. period. While Edison might compensate for some of this expected JKH-5' 12-15 Jack K. Horton 1 inflation through productivity increases, it would not be reasonable to 2 assume inflationary increases could be offset in this way, especially because 3 legislative and regulatory requirements continue to increase costs without 4 increasing output.
5 Q. Ilow do rate base additions reduce the rate of return on investment and 6 erode carnings?
7 A. San Onofre Unit No. 2, for example, is expected to be added to rate base 8 in 1981. At that time, the financing costs for San Onofre Unit No. 2 9 will no longer be capitalized through AFDC, and earnings therefore 10 will decline. Other expenses associated with plant, such as ad volorem 11 taxes, will be expensed instead of capitalized, and depreciation expense 12 will begin to be charged to utility-operations. These changes also will 13 reduce earnings. In addition, the rate base will be increased out of 14 proportion to the increase in system capacity. Without a substantial 15 increase in revenues to cover the increased expenses associated with 16 San Onofre Unit No. 2 and to provide the authorized rate of return on 17 the investment, the earned rate of return will decline. Because San Onofre 18 Unit No. 2 represents a 1981 investment of about $1.2 billion, the impact 19 would be substantial unless some provision is made for its impact. It 20 should be noted that the fuel expense associated with San Onofre Unit No. 2 21 will be less than that for fuel oil. As San Onofra Unit No. 2 increases 22 its production of electricity, fuel oil costs will be displaced, resulting
~23 in a -lower ECAC billing factor. This benefit , which will be passed on to 24 customers in a very short time, should lai.<ely offset the revenue increase -
.25 required for 'the addition of San Onofre Unit No. 2 to rate base.
=26 'Q. What has Edison done to reduce costs and increase productivity and
-27 managerial effectiveness?
28 A. Edison has implemented many management processes and controls to reduce JKH-6
- 8-27-79 H _
Jack K. Horton 1 costs and increase productivity and managerial effectiveness. These 2 require a high level of interest and involvement on the part of Edison's 3 senior management.
4 The Management Committee, which I chair, is at the center of 5 these processes and controls. It consists of the Chairman of the Board, 6 President, Executive Vice President , and the two Senior Vice Presidents.
7 The Committee meets weekly to review corporate plans, budgets, and provide 8 corporate policy decisions. Some of the key plans reviewed by the 9 bbnagement Committee include Executive Plans, Program Plans, and 10 Replaceability and Executive Developnent Plans.
11 Executive Plans are prepared annually by corporate vice 12 presidents to determine corporate problems and opportunities, develop 13 objectives, and provide plans of action.
14 Program Plans are prepared for specific areas by the organiza-15 tions involved. Recent program plans have been prepared with regard to 16 research and development , the environment, fuel supply, financial needs, 17 and data processing.
18 Replaceability and Executive Development Plans are prepared by 19 departments each year to deal with the availability of managers ready to 20 replace department heads and officers. It also deals with the development 21 'and cross training needs 'of those managers who have high potential but who 22 are not yet ready.
23 The Management Committee also reviews budgets that are prepared 24 by each organization annually and at mid-year for those that have material 25 deviations from budget. The process used by Edison to eliminate 26 unnecessary expenses and to cause plans for increased expenses to be
. 27 carefully reviewed and justified is referred to as the modified zero based 28 budgeting process. In addition, the expanded use of internal operational JKH-7 8-27-79 L _
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Jack K. Ilorton l
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'I and financial auditing provides control and incentive for managers to be i 0 l 2 efficient and cost conscious.
3 The committee process is also used to proute cost reductions 4 and improve productivity as a joint process. Some of the key committees
-5 in this regard include the Corporate Budget Committee, the Plant 6 Expenditure Review Committee, the Productivity and Management Effectiveness L7. Committee, and 'the Peak Demand and System Capacity Factor Management 8 Committee.
9 The Corporate Budget Committee reports to the Chairman of the Board'and provides staff support to the Board of Directors' Budget
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10-i11 Committee. We chairman of this committee is a Senior Vice President.
12 .The. purpose of the committee is to review all. budgets and control costs.
13 The Plant Expenditure Review Committee reports to the Chairman L14' 'of the Corporate Budget Consnittee and is chaired by a Senior Vice 15 Presid ent '. Its purpose is to review plant expenditures in order to
' 16..~ - minimize the . level of plar- investment required to provide reliable 17- service.
-18: The Productivity and Management Effectiveness Committee reports
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19 '- to the-Chairman of the Board and is . chaired by the Corporate President.
- 20. Its. purpose .is to direct L productivity and management' effectiveness '
programs, toLevaluate policies and practices related to productivity, and
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21,
_22 .to measure corporate productivity with regard to capital, labor, and fuel.
, 23- ~ The efforts are not.only' directed at the most efficient mix of inputs 124 (e.g. - capital, labor, and fuel) for a given ' output (i.e. , kWh. sales) but
?25- Talso directed. at; improving the output' for a given -setJ of inputs. -For, c26' example,'one' program'is directed atl reducing.line losses on the
- 27J subtransmission and distribution system with al goal of ereducing line 28- losses ,in 1981 by 50:million kWh.
JKH-8 8-27. , >
r Jack K. Horton
.1 The Peak Demand and System Capacity Factor Management Committee 2 reports to the Corporate President and is chaired by a Senior Vice 3 ' President. Its purpose is to formulate strategies and policies to modify 4 'peaUemand and improve the system capacity factor.
5' Q. How have you determined whether you have been successful at controlling
- 6 costs and improving productivity and managerial effectiveness?
7: A'. Several measures can be used. Edison's labor productivity performance
- 8 ,has'been excellent as indicated by the following measures: The U.S. Bureau 9 of Labor Statistics uses a measure that is often quoted in the news media
.10 .outp'ut per manhour. Edison increased its output per manhour on an annual
.11. trend rate basis of 3.3% compared to a 1.8% average for U.S. Gas and Electric
.Utilitiesiand 1.9*. average for U.S. Non-farm Business during the 1974-1978 g H13' period. Since Edison's ' output is based on kWh sales, it should be noted 14 that Table i 9 of Exhibit; No. - (SCE-1) shows that kWh sales during the
..C ,
15- 1same' period grew at about the same annual trend rate. This indicates that z 1'6 : Edison's manhours were held constant for about five years while kWh sales 17- increased. '
118 ~ Table 9 of Exhibit' No. (SCE-1) shows that the number of 19-- : Edison's~ employees: declined at' an annual trend rate of about 0.4% while v
20.- :the; number of Lemployees for' the 20 largest electric utilities increased
- '21 Latian 'annuali trend rate of 2.3% during the 1974-1978 period.
! 22J ChartiSA of Exhibit No. ' (SCE-1) 'shows that Edison's
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J23: : employees per-10',000. customers. declined from about 51'in'1974 to about 46
.s (24 , in 1978 while' the same ratio for the 20 Llargest group remained-at about L76-during the period'. 1 Customer growth was obviously'not the cause because-
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, c25) 1261 ' Edison's ' customers ' increased atlan ~ annual ~ trend rate of 2.6'. for the U27, period. compared !to 2.4% ; for .the 20l largest group during' the -same1 period.
" ':28? , l Table (9 of Exhibit- No. !(SCE-1)' 'shows these customer ' data, gi o _
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., . f I121'8-7,9) m , ,.. n; .
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Ja ck K. Ho rt on 1 While a 2.6*6 annual trend rate in customers does not seem large, 2 this amounted to about 348,000 customers from 1973 through 1978, which is 3 about half the number of San Diego Gas S Electric's customers. Edison 4 reduced the average number of its employees by 235 during that same period.
5 Edison's financial costs have also been kept under control.
6 Table 11 of Exhibit No. ( SCE-1) shows that Edison's average cost of 7 debt and preferred stock are below those for the 20 largest group. In 8 addition, Edison has maintained its bond and preferred stock ratings, even 9 with depressed earnings. This has been accomplished by reducing the debt 10 ratio as imbedded costs have risen, maintaining open and frequent contact with 11 rating agencies, and constraining construction expenditures to manageable 12 levels. Tables 5 and 6 of Exhibit No. (SCE-1) show that double-A 13 rated bond and preferred stock yields are lower than those for lesser 14 rated securities.
15 Other measures show Edison has been effective in controlling 16 plant investment. Table 8 of Exhibit No. (SCE-1) shows that Edison 17 has been able to reduce its forecasted kW demand and kWh sales during the 18 1979-1983 period as a result of its conservation and load management 19 efforts. This has allowed Edison to reduce its total construction 20 expenditures from $5.0 billion to $2.9 billion during the 1979-1983 period.
21 as shown on Table 8. This has been achieved despite an annual trend rate 22 of 10.6% in construction costs during the 1974-1978 period and forecasted 23 . construction cost increases of 10's in 1979, 9's in 1980 and 1981, and 8%
24 in 1982 and 1983.
25 Another measure of Edison's effectiveness in controlling plant 26 investment is shown on Table 9 of Exhibit No. (SCE-1) . Edison 's 27 net electric plant increased at an annual trend rate of 8.9% while the
-28 20 largest group's net electric plant increased at an annual trend rate JKH-10 12-15-79
Jack K. Horton
.1 'of 12.01.. Chart SB of Exhibit No. (SCE-1) further shows that 2 Edison's plant investment per customer was comparable to that of the 20 3 . largest group in 1968, but by 1978, the investment per customer was
- 4. substantially differeut , with Edison's investment being much less (about 5 $2,200 per customer.for Edison compared to about $3,600 per customer for L6 the'20 largest group).
7 Q. How has Edison used research and development?
- 8. A. Edison-has actively moved into research and development projects to find 9 new sources of energy, since conventional sources are in short supply,
' 10 and to maintain and improve the environment. I am quite proud of Edison's l11 record in this. regard.
121 Q.' What are some of;the research and development programs undertaken by Edison
' 13i ~ to find new sources of energy?
14' A. Edison is participating ;in the development of a 10 megawatt solar plant,
- 15.. -a.3 megawatt wind. turbine, and two geothermal plants of about 9 megawatts.
l 16 In1 addition, synthetic fuels are- being researched. A 90-100 megawatt 17-, coal- gasification . plant at Cool Water is planned, a full-scale methanol
- 18 test at Ellwood -is-under ws/, and shale oil testing at .Highgrove has been 19 completed. While this is not a complete list, I believe it is representative.
520 ~Q. What are ;some 'of the environmental projects being undertaken?
21 - A. c Edison has embarked 'on several programs. Some of these programs include:
- 22 11. -- A study of Atmospheric Properties to determine the effects -
of relevant pollutants.
23' z24 . 2. San Onofre Marine Studies to determine ecosystem effects on z
25 '
.Unitsil, -2, and 3 and ~ methods to mitigate adverse'long-term 26 effects.
27- ; 3. , ALHazardous' Waste 'and Toxic Substances Program to deal with '
' 28 -
potentiale biological and human health problems.
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- Jrck K.' florton l
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4~. A NOx Flue Gas Clean-up Program to determine NOx removal
.2- performance of selective catalytic reduction (SCR) compatibility of SCR units with existing generating stations
-4l and determine design criteria, cost, and schedule estimates 5 for commercial operation (SOHIO project).
6' 5. A NOx Combustion Control program to fully evaluate Low N0x
'7 Burners (LNB). The LNB Project at Highgrove demonstrated 8~ that such technology could reduce NOx.
-9;
- 6. A' Sulfates. Particulates, and Trace Elements Program to 11 0 ~ measure effects at Mohave and Four Corners, measure effects 11: of oil-fired emissions at Ormond Beach, and test a 10 MW
12- 3_ oil-fired stack' gas scrubber for reductions of SO 2'
~13 .Q . Does that complete your comments with regard to Edison's cost control,
' L14' . productivity, and managerial effectiveness programs?
115 4-A ? Yes, .-i t does. However, Edison cannot stem financial deterioration, no matter how effective its management performs, without substantial rate
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rel ie f.'
18LQ. What level. of: rate relief do you believe is necessary?-
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' 19 - A. . Edison requires a 10.78% rate of return and at least a 15.00% return'on 120- . common. equity to be earned in 1981. Rate relief must be sufficient-in
-21 -1981 to allow these returns to be achieved. A provision for -the impact -
22 - of San.Ondfre Unit No. 2 being placed in rate. base on' July 1,1981, and
.its negative impact on. earnings in i 1981 and:1982 should also be made to 223i 24~ J reduce;the: otherwise substantial. earnin6s erosion. .While Edison has 225 ~. .
separated .the expenses and associated investment of San -Onofre Unit No. 2
'26 : ifrom this filing by; placing thdse . costs-in a balancing account to be activated :
' 127f ' when the unit [gossiinto operation,1the rate relief requested in -this filing .
1283 " (vill]be sufficidntionly if another procedure to compensate Edison for the
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-JKH-12c
- 11a15-79
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Jack K. Horton 1 negative impacts resulting from the addition of the unit to rate base is 2 a' proved. The balancing account method vill benefit the consumer by enabling 3 deferral of the revenue increase associated with San Onofre Unit !k. 2 4 until the time that the plant actually goes into operation. a s a result it i 5 reduces the amount of the request for a general rate increase which vill be 6 in' effect for the full test year of 1981.
7 Finally, Edison needs an attrition allowance for 1982 to compensate 8 for the 15 basis point increase in imbedded debt and preferred szoek costs 9 and the impact of an 8% inflation rate on operating and maintenance expenses, 10 exclusive of fuel and income tax expenses.
11 Q. Why does Edison require a return on cobmon equity of at least 15%?
12 A. Edison requires this level of return on common equity in order to meet the 13 Hope and Bluefield Supreme Court tests that a company's return should be lh sufficient for it to maintain its financial integrity, credit standing and 15 ability to continue to attract capital. In my judgment, this can be done
' 16 only if Edison's return is commensurate witn its cost of capital. I believe 17 that Edison's common stock costs are in excess of 15%, with 15% being the 38 minimum of the reasonable range. I believe Edison requires a return on 19 common equity in excess of 15% in order to:
20 1. Increase Edison's common stock price to book value over a 21 reasonable period of time.
22- 2. Reflect the earnings / price ratio cost of common equity.
23 3. Reduce its dependence on financial markets for cash funds 2h to an acceptable level.
US h. Permit dividend increases at a rate that vill meet investors' 26 long-run inflationary expectations by providing sufficient 27 cash earnings to cover dividends.
28 5. Maintain the r~isk premium investors require over bond yields 29 without having the common stock price drop.
30 6. Maintain the interest coverage required to maintain bond 12-15-79' JKH-13~
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Jack K. Horton 1 ratings as imbedded costs rise.
2 7 Compensate for Edison's increased risk level.
3 Q. What has caused Edison's risk level to rise?
h A. While investors' perceptions may not be known fully by me, the price 5 performance of Edison's common stock indicates that the return on common 6 equity must be increased to compensate for the increased risk. Sone of the 7 risk 3 which investors may believe have changed the attractiveness of 8 Edison as an investment include:
9 1. The fear of investment loss has become an important consi-10 deration for utility investors. Since the Three Mile Island 11 incident and the uncertain environment brought on by legis-12 lative and regulatory bodies, investors are less certain.
13 2. Plant siting problems cause longer lead times, more concern Ih about final approval, and a greater CWIP financing burden.
15 Diablo Canyon delays concern investors when they discuss 16 Edison's San Onofre Units 2 and 3.
17 3. Environmental concerns dominate other issues, place standards 18 and requirements in a state of flux, force investment before 19 ability to meet standards and requirements is determined, 20 and increase costs while. impairing output.
21 h. Fuel availability and cost recovery are less certain.
22 5 Cash flows are less stable, especially with regard to ECAC, 23 than before the oil embargo.
2h 6. The impact of inflation on earnings, especially on regulated, 25 capital-intensive utilities such as Edison has increased.
26 7. Demand forecasting is less certain tus price increases, rate 27 designs change, and the impact of programs are not reflected 28^ in historical data.
29 8. Energy policies .at the state and federal level are sometimes
.30 inconsistent.
JKH-lh 12-20-79 L
I Jack K. Horton i 9. The uncertainty pertaining to plant investment resulting 2 from technological change and the need to invest in new 3 technology has increased.
4 10. The likelihood of Commission disallowances because of 5 consumer advocacy and pressures to hold rates down have been 6 perceived to have increased.
7 This list is by no means exhaustive, but I believe it does t
8 represent some of our investors' major concerns.
9 Q .' Is it your view that these risks were not adequately recognized by the
.10 . Commission in its 13.49% return on common equity allowance in Decision 11: No. 89711 for test year 1979?
12 A. The performance of Edison's common stock since that decision for test year
- 13 1979 indicates that investors do not believe that the return on common 14 equity allowance was adequate. Therefore, it is my belief that the
- 15. authorized. return- on common equity of 13.49% did not fully recognize the .
116- risks. perceived by investors.
'17 Q. Mr. Horton, would you please summarize your testimony?
18 A .- Edison i ls faced with accelerated inflation,-increasing governmental 19- requirements which add to the cost of doing business without increasing 20' output, and die commitment to plant investments that, despite scaling
- 21. down projected growth rates, are greater-than;at any time in its history.
22 In' order to avoid financial deterioration, Edison's management has
! 23 ~ minimized cost increases, increased productivity and managerial effectiveness,
~24 and constrained plant . investment through budgeting review and peak demand l25 . and ' eapacity; factor . programs . Despite Edison's' substantial achievements
- 26. with. regard to ' cost : control and increased' productivity, Edison faces l27- ) financial disaster unless' substantial . rate relief is approved. At least
- 28 a 15%~ return on common equity is required to be earned in 1981. In addition, JKH-15
- 8-27-79
i 1' Jack K. Horton l' rate relief is required to compensate for the substantial attrition 2- .
expected in 1982 as a result of' continued escalation in the cost of
,. service beyond management's control. Edison requires the rate relief
- 4 :. requested in this Application in order for it to earn a return on common 5 equity commensurate with its cost 'of capital and to maintain its financial integrity, credit standing and ability to continue to attract capital.
-6
, .7 . Q. . Does-this complete your prepared testimony?
i- .8 A. Yes, it does.
1 4
b f
b T
s
. JKH-16 --
- ,8 27-79.
- i~ _ , _ , ., _
SOITDIERN CALIFORNIA EDISON COMPANY Prepared Testimony of H. Fred Christie Exhibit No. (SCE-1)
(Financial Characteristics, Cost of Money and Required Return) 1 - Q. Please state'your name and business address for the record.
2 14. .My name is H. Fred Christie, and my business address is 2244 Walnut Grove 3 Avenue, Rosemead, California.
4 Q. What is your position with Southern California Edison Company?
S A. I am Senior Vice President.
6 Q. Please refer to Exhibit.No. (SCE-3) for identification, entitled
~7.- " Qualifications of Witnesses". Directing your attention to the page 8- entitled " Qualifications of H. Fred Christie", does that portion of the
'9 ~ exhibit accurately set forth your background, training, and experience?
10 A. Yes, it does.
11 Q. Are you testifying with respect to Exhibit No. (SCE-1) entitled 12 " Financial Characteristics, Cost of Capital, and Required Rate of Return"?
. 13 A. Yes.
.14 . 'Q. : Was this exhibit prepared by you or under your supervision?
-1S A. Yes.
16 - :Q. What- is the. purpose of your testimony and Exhibit No. (SCE-1) ?
17 - A.' . The purpose of my testimony is to demonstrate that:
18- 1. The Company's cash needs from financial markets are. larger 19 now than in the past.
20 2. : The Company's cost. of debt and preferred stock financings 21 /will continue ~ to'be much greater than its imbedded cost of
-22 debtLand preferred stock.
- 3. Tie Company has done much to reduce its cash need from
~
23' HFC-l' L12-18-79 .
H.-Fred Christic .
1 1 -- investors and to reduce the level of its debt and preferred
-2 stock costs.
3 4. The Company's control of imbedded debt and preferred stock 4 costs, employment, kWh sales growth, and electric plant
<5' investment has been better than that of coc: parable electric 6- utilities.
'7 - 5. The Company needs a rate of return adjustnent (attrition
'8- allowance) and a balancing account for the addition of
-9 San Onofre Lnit No. 2 to co=pensate for the expected decline
-10 in earnings in 1982 since the Commission has indicated
'll filings should not be made more than every other year.
- 12 6. De Company's required return on comon equity is greater 13 - ithan that.authori:ed in CPUC Decision No. 89711 for 1979.
14' .Specifically, the Company needs at least a 15% return on 15- common equity and a 10.78% rate of return authorized and 16' earned in '1981 for its returns' to be commensurate with its 17 . ~ cost-of capital. -
~18 .Q.
How large are Edison's cash needs from financial markets?
19 - A.. Table 1 'of' Exhibit No. (SCE-1) -shows that construction expenditures.
i20- - and.refundings during the 1979-1983 period are currently expected to total 21 - $3.4 billion,!or about 42% more than required-during the- 1974-1978 period.
-22' Without. rate: relief, at least $2.9 billion, or about 87V of the
. s23 cash funds needed, would have to be obtained from financial markets during
- 24. the 1979-1983 period.' His amount of financing,.'even if possible,~ would L25:2 :
seriously' damage ~ Edison's; financial integrity, credit standing, and ability n 26L to continue ;to = attract capital.
27 f Q. How much rate relief is required to achieve. earnings results sufficient .to
~ 28 ?^ -
enable Edison to meet -its; financing requirements and maintain its C
HFC 12 15-79J' g
H. Fred Christie 1 financial integrity, credit standing, and ability to continue to attract 2 capital?
3 A. Edison needs to reduce its average dependence on financial markets for 4 cash funds to 60% in the long run; otherwise, Edison will not be able to 5- maintain its financial integrity, credit standing, and ability to continue
.6 to attract capital.
'7- Table 1 of Exhibit No. (SCE-1) shows that with the rate 8 relief requested.in this filing for 1981, the balancing account to
.9' compensate for the addition of San Onofre Unit No. 2 to rate base and 10 revenues needed to produce a 15% return on common equity in 1983, Edison's 11' dependence on financial' markets for cash funds is reduced to the 70% level 12 during the 1979-1983 period. . While this is not believed to be satisfactory 13: in the'long run, it is believed to be' satisfactory for the period because 14 of'the strong reversal of trend during the 1981-1983 period. The need to 15 obtain about 95% of'the funds through external-financing during 1979-1980 16 must be followed by-less demanding years for Edison to maintain its
'17 financial well-being.
18 Q. How' do you expect the construction program and refundings to be financed 19' .during.the 1979-1983 period ?.'
-20 A. Table 2 of Exhibit No. (SCE-1) shows the amount of long-term debt,
- 21. preferred stock, and common stock that will be needed during the 1979-1983 22~ , period.to finance the construction program, refundings, and to maintain
~
23 .the target capital structure.
24- While Table 2 of Exhibit No. (SCE-1) shows a schedule of
.HFC-3
.I9-2-79
- 11. Fred Christie 1 financings without rate relief, that schedule should be regarded in 1
2' light of the fact that it assumes the Company's financial integrity, 3 credit standing, and ability to continue to attract capital would not
.4 be seriously damaged. This would not be the case, but the full impact 5 cannot be completely predicted through financial simulation. The 6 diminished- carnings would (at the very least) greatly increase the cost 7 of financing because the Company's bonds and preferred stock would be 8 derated one or more times, legal investment. laws in several states would 9 not be met, and the common stock dilution would be devastating as the
'10 common stock price fell and the number of shares sold would need to be 11 greatly increased to raise the necessary funds. In the worst case, however, 12 the Company might be unable to obtain the furds required.
13 Table 2 also shows a schedule of financings based upon the 14' effect of the requested rate relief in 1981, rate relief to fully
- - 15 ~ compensate for the addition of San Onofre Unit No. 2 on about July 1, .1981,
-16: and additional rate relief sufficient to earn a 15% return on canmon 17 :- . equity in 1983. This schedule of financings shows that the external cash 18 requirement is about 71% greater than the $1.4 billion raised during the 19: 1974-1978 period. The $2.4 billion required to be raised during the
-20 1979-1983- period under these assumptions is comprised of $1.6 billion debt.
L21; $337 million preferred,' and $547 million common stock. 'While this amount 22, is;1arge, it is believed to be manageable and should not harm the 23: financial integrity. and credit standing .of.the Company as .long as the earnings' assuined are achieved with regard to common equity.
~
z25lQ.1Whatisthetargetcapitalstructureduringthe 1980-1982 period?
26 : .1.< .: Th'e financings shown. on Table 2 of. Exhibit No. (SCE-1)' are designed-27; to achieve, during the 1980-1982 period, .a capital structure average of
.28 Esbout' 470 debt,1130 preferred . stock, and 40% consnen equity, the Company's
/
3 N
8330-79 f _
u
H. Fred Christie 1- target capital structure for that period. These ratios are used on Table 2 24 of Exhibit No. (SCE -1) to determine Edison's over-all cost of 3 capital in 1981 and 1982. This capital structure reflects a reduction of 4 ene percent in both the debt and preferred stock ratios from the target 5 ratios of 48% debt ,14% preferred stock, and 38% common equity used during 6 the 1977-1979 period. The reductions in debt and preferred stock ratios 7 have been made in an effort to help maintain financial integrity and credit 8 standing of the Company and to reduce Edison's over-all cost of capital 9 needed to maintain its times interest earned after tax ratio close to 10 three times.
11 Q. Why do you expect senior financing costs to be high relative to Edison's 12 debt and preferred imbedded costs?
13 A. Even with the rate relief required to maintain financial integrity, credit 14 standing, and the ability to continue to attract capital, Edison's 15 financing cost of debt and preferred stock will be much higher in the future 16 than its imbedded costs. One reason is Edison's increased dependence on 17 capital markets. The need to enter the market more frequently and with 18 larger' issues for cash funds reduces the ability of Edison to time issues 19 to either take advantage of short-run conditions or to avoid adverse 20 market conditions. A second reason is that energy and ecological require-21 ments have increased investment demands on finite capital markets at the 22 same time that government deficits are expected to be very large. Since 23 the saving rate has not increased, the added demand pressure increases 24 investment costs. A third reason, which is probably the most important 25 reason, is the level of inflation. Investors' inflationary expectations 26 have been affected by the experience of the past several years.
27 Table 3 of Exhibit No. (SCE-1) shows the three major price index measures: The GNP Implicit Price Deflator, the Consumer Price Index, HFC-5 8-30-79
H. Fred Christic 1
'1. and the Producer Price Index. Since 1969, all three indicate an average !
2 . inflation rate in excess of 6.6%. This experience and economists' l l
3 forecasts indicate investor expectations should exceed that amount. Edison l 4 expects the inflation rate to average in excess of 8% during the 1979-1983 5 period, with investors expecting about a 7% inflation rate in the long run.
l 6 The -investors' long-run inflationary expect ations are important because 7' they are a component of the cost of capital. Otherwise, the investor would 8 be unable to achieve the return goal required to attract his funds after 9 ~ the inflationary effect is subtracted. While the short-run inflationary 10 experience has an impact on inflationary expectations , the two are not the 11 same; and it is-inflat i anary expectations that affect.the level of the cost 12 of capital, not the short-run experience.
13 Q. How have money rates, bond yields, and preferred stock yields compared to 14 Edison's imbedded costs during the past ten years?
t 15 ~A. Money lratri, bond yields, and preferred stock yields have exceeded imbedded
-16 ' costs over the past ten years.. This experience would also tend to further 17 support the expectation that bond and preferred stock yields would continue
- 18. to exceed Edison's imbedded costs.
19 LQ . What h'a s been' the experience with regard .to money rates?
20 A. Table 4 of Exhibit No. .(SCE-1) shows 'short-term money-rates 21' fluctuated from about(4V to 12% 'during the. 1969-1978-period. While the
'22 = money rates differ among 'themselves somewhat.. note how:each approximates -
- 23. - the inflation rates over the ten-year period. Only 90-day Treasury Bills
'24' average less than 6.6% during the--1969-1978 period.
.25 . Chart 1 of Exhibit No. (SCE-1) . draws the parallel.between -
26 -inflation rates' and money rates. even closer. : Note how 4-6 month commercial 2 7. - . paper rates on a year-by-year basis nove with the GNP Implicit Price I ~28' . Deflator. This' indicates that Edison's short-term money rates should not
' HFC 8-30-79
, - , - - , 9 g. qu y
H. Fred Christie 1 be expected to be less than the inflation rate for any reasonable length
'2 of time.
~3' 'Ihe. current high short-term money rates tend to support 4 higher.~ inflationary expectations.
5 Q. What has been the experience with long-term bond yields?
6L - A. . Table 5 of Exhibit No. (SCE-1) shows Moody's Aa, A, and Baa Public 7 Utility bond yicids and U.S. Government long-term bond yields. The Aa 8 bond yields represent Edison's bond class, while the A and Baa bond yields
'9 represent the potential-increased bond yield cost to Edison of being 10 derated one or two times. Chart 2A shows how these yields tend to move 11 in the same pattern. Note that during the 1969-1978 period, Aa, A, and 12 Baa bond yields averaged about 8.4%, 8.7%, and 9.1%, respectively, with 13 the yields generally being higher after 1973.
14 Since the U,S. Government long-term bond yields represent the
~ 15 ~ risk-free rate, the differential between the Aa bond yields and the U.S.
16 -. Government bond yield represents the risk premium investors demand to 17 purchase Aa Public Utility bonds. Note that in 1979, even U.S. Government 18 long-term bond yields exceeded 9%, while the Aa bond yields approached -10%.
shows that while Moody's 19! Chart.2B of Exhibit. No. (SCE-1) 20 Aa Public Utility Bond'. Yields are generally higher than the GNP Implicit 21- Price Deflator, the movement's of the two are similar.
22' Q. What has been_ the experience with regard to preferred stock yields?
23 ~ Al Table'6 of Exhibit No. - (SCE-1) shows Moody's aa, a, . and baa Public 241 Utility! Preferred Stock Yields since September 1975 when . Moody's started 255 publishing-preferred' yields by rating. Table 6 and Chart 3A show that a 261 t and baa preferred stock yields. move in ~a pattern similar but higher than J27 . aa preferred stock yields. . Chart ,3B shows that Moody's aa Public Utility 28' -Preferred Stock 1 Yields and Aa Public Utility. Bond-Yields move in a highly
" ~
3- 112-18-79 e
- 11. Fred 'Christic 1 correlated manner but that aa preferred yields move at a level somewhat 2 below that of Aa bond yields.
i 3 - Q. What do you expect Edison to pay for long-term debt and preferred stock 4 through 1982?
5 A. Based upon the data in Tables 3, 5, and 6; Charts 1, 2B, and 3B; and my 6 estimation of investor expectations and of the financing situation. I
.7 expect Moody's Aa Public Utility Bond Yields and Moody's aa Preferred Stock )
8 Yields to average 9.75% and 9.50%, respectively. If Edison receives rate 9 relief sufficient to maintain its financial integrity, credit standing, 10 and ability to continue to attract capital, I vould expect Edison yields 11 to approximate. the Aa and aa levels of 9.75% and 9.50%, respectively.
.12 If Edison's rate relief is not sufficient, it will have to pay more than 13 the 'Aa bond yield and aa. preferred stock yield, as indicated on Tables 5 14 and 6, and Charts,2A and 3A. Without rate relief, Edison might find it 15 imprudent, If not impossible, to continue to finance its construction 16 program.
17 .Q. What will happen _ to Edison's imbedded costs of debt and preferred stock 18- as a" result of the financings required during the 1979-1983 period?
19 A. Table 7_ 'of Exhibit No. (SCE-1) shows Edison's imbedded costs of debt and preferred stock during the recorded period through June 1979-and 21 sduring the forecast period through 1982.
-22 With rate relief as required, the imbedded _ cost of debt would 23 rise from 6.87% in 1978 ' to 8.03% in 1981, and then to 8.30% in 1982; and '
'24 ' the imbedded cost of- preferred stock' would rise from 7.13% in 1978 to
.25 7.80% in 1981, and then to_7 90% in 1982. 'Ihese projections are made with 26' the. financings shown on' Table 2 of Exhibit No. (SCE-1) and the 9.75%
-27c . debt' cost and 9.50% preferred' cost assumption for financings made after
.28 1979.
HFC-8 12-15-79 L
- 11. Fred Christic 1 Without rate relief, the capacity to issue debt and preferred 2 stock would be reduced to where sufficient financing to continue the 3 construction program would not be expected. In addition, the cost of each 4 new issue would increase above that presumed for double-A securities.
5 Therefore, imbedded costs are not projected without rate relief.
6 Q. What has Edison done to reduce its financing needs and to reduce the level 7 of its debt and preferred stock costs?
8 A. The Company has done much to reduce its financing needs and capital costs.
9 'these include load management and capital rationing efforts, productivi' y 10 and managerial effectiveness programs, capital structure changes, and 11 innovative financing methods.
12 Q. llave load management and capital rationing efforts reduced Edison's 13 construction expenditures?
14 A. Yes, Table 8 and Chart 4A of Exhibit No. (SCE-1) show that 15 substantial reductions have been made to plant expenditures programs for 16 the 1979-1983 period. These changes have been possible because of Edison's l' success in reducing kWh sales and kW demand growth during this period, as 18 shown on Table 8 and Charts' 4B and 4C of Exhibit No. (SCE-1) . In 19 addition, the Company's strict review and budgeting procedure in the 20 Plant Expenditure Review Committee (PERC) and the evaluation process for 21 resource planning encourage the efficient use of funds.
22 Q. What else has been done to reduce cash needs from investors?
23 A. The 2ompany has a strict budgeting process, ;sometimes referred to as a-24 modified zero-based budgeting procedure, under the direction of a Budget 25- Director and the Budget Committee to assure efficient allocation of 26 resources to the functioning of the Company. In addition to elimination 27 of waste and redundancy, the Company has focused on increasing productivity.
28 'A Productivity and Managerial Effectiveness Committee was formed in 1978 IIFC-9
.8-30-79
H. Fred Christic 1 with the President of the Company as chairman to emphasize its importance.
2 A work group was also formed to measure the progress of the Company with 3 regard to itself and to others. The superior performance of the Company, 4 when compared to similar utilities, is shown on Table 9 and Charts SA, 5B, 5 and 5C of Exhibit No. (SCE-1)_ . Edison's performance has been 6 superior to that of the 20 largest electric utilities with regard to 7 controlling the growth of employees, kWh sales, and electric plant.
8 Q. What has Edison done to reduce debt and preferred stock financing costs?
9 A. In addition to reducing the amount of cash funds required from financial 10 markets, the major changes the Company has implemented include the 11 reduction of the debt ratio and the use of appropriate cost-effective 12 financings.
13 Table 10 and Chart 6 show that Edison reduced its debt ratio 14 from 53.8% in 1969 to 48.lt. in 1978, while the 20 largest electric 15 utilities did euch less, declining from 52.S% to 51.4% during the period.
16 By reducing its debt ratio, Edison reduced the amount of debt it sold by 17 $350 million by 1978 and its 1978 imbedded debt cost by 20 to 28 basis 18 points.- In-addition, Edison's times interest earned ratio was maintained.
19 This' helped to maintain Edison's Aa bond rating.
.20 Some of the innovative financings which held the Company's
-21 imbedded costs down included nuclear fuel and other lease arrangements, 22L project financing, pollution control bonds, intermediate-term bonds, off-23- shore preference stock, private placement of bonds and preferred stock,
-24 foreign financing through the Export Credit Guarantee Department, and
.25 . foreign financing through an investment banker.
26 -- Q. How successful has Edison been in reducing debt and preferred stock costs?
27 'A. = Table 11 of Exhibit No. (SCE-1) shows nominal debt and preferred 28! stock. costs for Edison and the 20_ largest electric utilities.. Since.
HFC-10
.8-30-79
H. Fred Christie 1 Edison's ' debt and preferred costs are well below the average of the 20 2 largest, it can be said that Edison has been more successful in controlling 3 its costs than the comparable utilities.
1
~
j _4 Q. 'You have shown that reduction of bond and preferred stock ratings increases ,
5 bond and preferred' stock yields. How does this impact the ratepayer?
4
'6 A. Increased bond and preferred stock yields mean higher imbedded costs, and t
7 this causes the rate of return requirement to be higher. Rus, the cost of 4
8 1 service paid by the consumer is greater. Decreased bond and preferred 9 stock ratings also affect the size of the issue and the width of markets 10: available to it.
11: h is is important because Edison must obtain $600 million cash
. '12 Tper year to continue its construction program. Therefore, the size and
- 13' frequency of issue is important. .For example,~in 1978, the largest Aa
'14 electric utility bond issue was $250 million while the largest Baa electric
~
- -15 utility bond issue was $100 million. This means that the Aa electric t'
116L utility, if-derated to.Baa, would have gone to the market over two times as 17 auch in 1978 to raise.the same amount of money. Since market conditions 18 vary, the impact on a large company such as Edison could be' serious for 19 ; reasons other than costs', such as a practical limit on the number of times 20? any company can enter.the financial market in a-year as-investors strive to 21J l diversify their portfolios.
I22- The width of market is 'also important. Many fiduciaries limit L23 .themselves -to Aa electric utility bonds because of the " prudent man" rule.
~
. ; 24 . State-legal investment laws may bar entry of: insurance companies, savings
-: 25 banks, and otherLlarge' investors in their states ~if certain criteria are i
~
"261 1not met.
- b. 27g Q. Why do-investors turn away from lower-rated utilities?
7 28 L :: A. The two primary reasons are: (1) fear of . investment loss, and (2) returns A .. 4 - - s ,
. HFC-11
- .8 -30.-79, r
~- , , , . .-~ .- , ,. .c,, 1 4 .-, - , -, . . .
H. Fred Christie
- 1. insufficient to compensate for the perceived risk.
l 2 The return differences are shown on Tables 5 and 6 and Charts 3 2A and 3A of Exhibit No. (SCE-1) . One dimension of the risk that 4 detours investors from a utility about to lose its bond or preferred stock 5 rating is the loss of investment. Tables 12 and 13 of Exhibit No. (SCE-1) 6 show that when the yield changes as a result of, or in anticipation 7 of, a derating, the bond or preferred stock investor immediately loses a j 8 . portion of his investment as it is devalued. If they are doubtful about '
9 the credit standing of the utility, those who continue to invest will 10 discount the bonds and the preferred stock. Ilowever, the more doubt, the 11 ~ fewer the investors; and under certain market conditions, other invest-
- 12. ments .may take all the funds available.
'13 Q .' Does the risk of devaluation of investment pertain to common stock as well 14 as to bonds and preferred stock?
15- A. Yes. Studies indicate that investors also require a higher return on
-16 common equity to invest in lower-rated companies than in higher-rated
'17 companies. Chart 7 of Exhibit No. (SCE-1) shows that the earnings /
18 price differential between As and A public utilities varied from 7 to 128 19 basis points during the 1974-1978 period.
20 When an electric utility's comon stock price falls below book
.21 . value, sales of additional shares of common stock dilute the investment of 22 each share.in the utility. Table 14 of Exhibit No. (SCE-1) shows 23 that since 1974, Edison's common stockholders suffered a.10.1% loss in 24 book value and . earnings per share as a result of common stock sales below
. 25 bc,ok value. It also shows that the Company was required to issue about 26 6.4 million more shares'during the 1974-1978 period than it would have if a
- 27 coasson stock had sold at -book value during the period. The cash drain
'28 caused by these additional shares at the current annual dividend rate of HFC-12
- 8-30-79 ~
H. Fred Christie 1 $2 72 is about $17 million per year.
2 Q. How does dilution work?
3 A. The revenue requirement for electric utilities in California is based upon 4 original cost of plant less accumulated depreciation, i.e. , book value.
5 The book value per conmon share represents the portion of the original cost 6 of the investment in plant less accumulated depreciation that is assigned 7 to each share of common stock. In effect, it represents the common equity 8 investment per share upon which the Commission allows a return. If the 9 price of new shares falls below book value (the price of the previously-10 sold shares plus retained earnings per share - earnings not distributed as 11 cash dividends), the common equity investment per share decreases.
12 This happens as follows. Assume two shares of common stock with 13 book values of $20 each, earning a 15% or $3.00 annual return per share, and 14 $40 additional funds are needed. The price of the stock determines the 15 nunber of shares needed to raise the $40. If the price per share is $20, 16 twr. shares will be needed, and no dilution will occur because price equals 17 book value ($20 + $20 + $20 + $20 = $80/4 shares $20 x 15% = $3.00 per 18 share). However, if the price per share is $10, er half of book value, 19 four shares will be needed and dilution will occur ($20 + $20 + $10 + $10 20 + $10 + $10 = $80/6 shares = $13.33 x 15% = $2.00 per share).
21 The following table shows the impact of selling common stock 22 both above and below book value.
23 Earnings Shares Investment at 15%
24 Per Per Case Start Added Total Start Added Total Share Total Share 25 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) 26 A 2 2 4 $40 $40 $80 $20.00 $12.00 $3.00 27 B 2 4 6 40 40 80 13.33 12.00 2.00 28 C 2 1 3 40 40 80 26.67 12.00 4.00 HFC-13 12-15-79
H. Fred Christie 1 Q. Why do you feel Edison needs a rate of return allowance above the 10 78%
2 rate of return in 1981 based upon a 15% return on common equity and a 3 . balancing account to compensate for the addition of San Onofre Unit No. 2 4- in 19827 5 A. The Company needs the higher rate of return allowance in fixing rates on 6' the basis of the 1981 cost of service to compensate for the fact that 7 estimates of imbedded senior capital costs, operating and maintenance 8 expenses, and rate base used for 1981 will be deficient in 1982. Without 9 the additional rate of retuta adjustment and a balancing account for San
.10 ' Onofre Unit No. 2, the . return on comon equity and earnings for the
~11 1981-1982 period will be less than what the Commission authorizes. This l12 deficiency will result from the fact that the rate of return and return on 13 common equity'in 1982 will fall below what the Commission authorized for 14 .1981 because rates will be fixed on the basis of 1981 costs. This decline 15 'in earnings, subsequent to the test year, is of ten referred to as attrition.
(16 Q. If the need for an attrition allowance is recognized by the Commission 17 in the proceeding, why would a balancing account for San Onofre Unit No. 2 18: be appropriate? Wouldn't that be duplicative or at least overlapping? ,
. 19 A. No. ~The attrition allowance, which Edison has requested in this proceeding, 20: does not. include either the operating cost or rate base effects caused by 21 adding San Onofre Unit.No. 2 to rate base.
22 Q. What is the cause of attrition?
23 ;A. It is.related'to primarily three factors which are: (1) financing costs 24 of' debt and preferred stock in' excess of their respective imbedded costs, f 25; (2)-inflation rates at'the.8% and~ greater levels, and (3) additions to
- 26 rate base which' reflect.b'oth inflation rates and internalization of social i
-27 ; costs resulting in 'a higher rate base 'per unit.of . output.
28' _ Q.1 How do the higher'f'inancing costs of debt and preferred stock cause
. . HFC-14 12-15-79
H. Fred Christie 1 attrition?
2 A. Table 7 of Exhibit No. (SCE-1) shows that Edison's imbedded cost of 3 debt.will rise from 8.03% in 1981 to 8.30% in 1982, and its imbedded 4 cost of preferred stock will rise from 7.80% in 1981 to 7 90% in 1982 as 5 a result of 1982 debt and preferred stock financing costs in excess of 6 1981 imbedded costs. Table 24 of Exhibit No. (SCE-1) shows that 7 when these imbedded debt and preferred stock costs are multiplied by the 8 47% debt and the 13% preferred stock ratios, the weighted cost components 9 for _ the two rise from 4 78% in 1981 to 4 93% in 1982, an increase totaling 10 15 basis points. Table 24 shows that even with the other components of the 11 . cost of capital unchanged, a 15 basis point increase in the total cost of
-12 capital occurs during the 1981-1982 one-year interval. However, if no rate 13 relief is afforded and everything e'se remains the ' sane as in 1981, the return on common equity would drop 37 basis points as shown below:
~
'14 15 Return on Common Equity Attrition When Total Return on Capital is Not Increased.But 16 Imbedded Cost of Debt and Preferred Stock Increases 17 Target 1981 1982 Capital x Cost Weighted x Cost Weighted 18- Ratios Factor = Cost Factor = -Cost 19- Debt 47.00%. 8.03% 3.77% 8.30% 3.90%1 20 Preferred 13.00' 7.80 1.01 7.90 1.03
- 21. Fixed. Costs 60.00% 7.97%- 4.78% 8.22% 4.93%
f 22 Common _ Equity 40.00 15.00* 6.00 14.63 ** 5.85
~231 -Total Capital 100.00% 10.78% :10.78%
~
'24
- 1981
-25 10.78%' Total Cost of Capital - 4 78% Fixed Costs =. 6.00% Weighted
- Cost of Common Equity /40.00% Common Equity Ratio = 15.00% Return 26 ~
on Common Equity.
27 ** 1982 2 81 --10 7@6: Total Cost of Capital - 4 93% Fixed Costs = 5.85% Weighted
- Cost -for_ Common Equity /40.00% Common . Equity' Ratio = 14.63% Return on Common Equity;
"##~1 112-15-79
l l
H. Fred Christie )
l 1 This demonstrates the need for the Commission to make an adjustcent in !
2 the rate of return based on the 1981 cost of capital to cc pensate Edison 3 for its 1982 financing cost attrition since general rate increases are to 4 be spaced at two-year intervals.
5 Q. How is times interest earned affected by increased financing costs?
6 A. For Edison to maintain its financial integrity and credit standing, it 7 must maintain its times interest earned ratio. For 1981, a 10 78% return 8 on capital provides a 2.86 times interest earned after tax, as shown on 9 Tabic 24 of Exhibit No. (SCE-1) . If the return on capital were to 10 remain at 10 78% in 1982, the times interest earned after tax ratio will 11 fall to 2.76 times (10 78%/3 90%). With the return on capital increased 12 to 10.93% to maintain earnings and the return on common equity at 15.00%,
13 the times interest earned after tax ratio still declines somewhat, falling 14 to 2.80 times.
15 This change in interest coverage resulting from much higher debt 16 costs is another reason why Edison has needed to reduce its debt ratio 17 from about 54% in 1969 to about 47% in 1981. Without that change, the 18 cost of common equity to maintain Edison's financial integrity, credit 19 standing, and ability to continue to attract capital would be much higher.
20 It is also logical that when it takes 9.75% to attract bond investors, 21 compared .to the past costs which averaged about 8.00% for Edison, the 22 return on common equity will need to increase at least as cuch to attract 23 common stock investors; otherwise, the common stock price will fall in 24 order- for the incoming investors to get their risk premium. Existing 35 Edison investors would lose the difference.
26 -Q. How does ' inflation -cause attrition?
27 A. Edison expects its costs, exclusive of fuel costs and income taxes, to 28 increase about 8% during 1982. While Edison is proud of its past HFC-16 12-15-79
H. Fred Christie 1 productivity and managerial & ' .:tiveness gains, as reflected on Table 9 2 and Charts SA, SB, and SC of Exhibit No. (SCE-1) , any future gains 3 cannot be expected to compensate for price level increases resulting from 4 increased labor costs, material and supply costs, and contract conts. This 5 is especially true since regulatory and legislative costs are expected to 6 continue to increase the cost of service without increasing output.
7- It should be noted that during the 1974 -1978 period Edison 8 increased output per manhour at an annual trend rate in excess of 3% while 9 both U.S. Gas and Electric Utilities and U.S. Non-farm Business were able
~10 -to achieve averages of less than 2% during the same period.
11.'Q.. How 'does the addition to rate base reduce the return on common equity?
12 A. .The Commission authorizes a rate of return on rate base for the test year.
13 This return on rate base can be affected by changes in revenues, expenses,
.14- and rate base as shown-by the following formula:
Reve xpenses Percent' Return on Rate Base = X 100 16 17 .If the rate base? increases, the rate of return, or percent return on rate 18 base,is reduced unless either revenues increase or expenses decrease 19 sufficiently to compensate for the change in the rate base.
20 Since the return on rate base will decline and the fixed costs 21 for debt and preferred stock will not,.the return on common-equity will 2 2' . absorb all the impact of the decline in common equity. With the common
- 23 equity ratio of 40% the impact on the common equity return will be two 24 and one-half times the impact on the return on rate base.
25 :Since San Onofre Unit No.92'is scheduled to be in operation in 26' 'mid-1981', it would substantia 1'ly reduce Edison's rate of return in,1982 27l unless revenues'are adjusted to compensate.. Since .the ECAC procedure will
'28,
. flow'through'the benefit' of reduced energy costs to ratepayers as San HFC-17
<12-15-79
.H. Fred Christie 1 Onofre Unit lio. 2 increases producticn, the revenue increases needed ta ecm-2 pensate for the operating costs and rate base additions associated with San Onofre Unit !io. 2 shou'd be largely offset by the energy cost benefit. There-3 b fore, the Company is requesting, by separate application, that the Ccenission 5
establish a balancing account procedure to deal with the revenue requirements 6 associated with the addition of San Onofre Unit No. 2. If such a procedure 7 is not implemented, the Commission should make an additional attrition 8 allc unce because neither the operating costs nor the rate base additions 9 associated with San Onofre Unit fio. 2 have been included in the base rate or 10 attrition allowance requests in this application.
11 Q. k*hy should the return on cernon equity be greater than the return en cernen 12 equity authorized in Decision fio. 89711 for 19797 13 A. There are several reasons. Primarily, Edison's return on common equity must 1h be raised to a level that is commensurate with the cost of capital if it is to 15 be able_to maintain its financial integrity, credit standing and ability to 16 continue to attract capital. Some of the specific causes include:
17 1. Edison's large financing needs require maintenance of bond and 18 preferred stock ratings and the ability to sell common stock at 19 book value or higher if it is to maintain financial interrity 20 and be able to attract the capital required in the long run.
21 2. An allowance must be made for investors' increased inflationary 22 expectations.
23 3. Since the coat of Edison's bonds and preferred stocks have 2h increased, the return on common equity must be increased in 25 order to maintain the risk premium.
26 h. The common stock price performance of Edison and comparable 27 utilities in relation to their earnings and the price 28 performance of unregulated enterprise indicate that a higher HFC-18 12-20-79
H. Fred Christie 1- return on common equity is both justified and required.
2 5. Edison's earnings /1, rice cost of capital on a discounted 3 cash flow (DCF) basis indicates a 15% return on common equity 4 is required.
- 5. 6. An allowance needs to be made for the increase in risk 6 perceived by investors.
7 Q. How do Edison's large financing needs impact the return on common equity 8 requirement?
9 ~A. Table 1 of Exhibit No. (SCE-1) demonstrates that Edison must earn in 10 excess of a 15% return on connon equity in 1981 and 1983 and receive 11 sufficient revenues to compensate for the impact of San Onofre Unit No. 2 12 on carnings in 1982 to achieve 40% internal cash generation. Since Edison 13 must average 40% internal cash generation in the long run to maintain its 14 financial integrity, credit standing, and ability to continue to attract 15 capital, Edison's large financing needs make it vital to the continued 16 adequacy of service that its authorized return on common equity should be
'17 raised from 13.49% to at least 15.00% in 1981.
18 Q. How do inflation rates demonstrate that Edison requires a higher return on 19' common equity than authorized in Decision No. 89711 for 19797 20 A.. Table 3 of Exhibit No. (SCE-1) shows that the inflation rate averaged 21 over 6.6% during the 1969-1978 period. While this rate is expr, red to 22 average in excess of 8% through 1983, investors' inflationary expectations 23 in the long run are believed to be at about the 7% level.
24 For Edison's common stock investors to maintain equivalent cash
' 25 - income, their cash ' dividends must rise at the same rate as the inflation 26~ rate. It'would follow that- Edison's stock _ price would not be discounted 2 7. ' - = below book, value 'as -long as dividends grow -at a rate equivalent.to 28 investors' long run inflationary expectations.
In order to sustain a
~8-30-7E?
. H. Fred Christie 1 dividend growth rate, dividends cannot, in the long run, grow at a rate 2 faster than earnings. The two, in the long run, must grow at the same 3 rate. Earnings per share (and thus dividends per share) can grow at a 4 7% rate in the long run if the following conditions can be met:
5 1. The price is equal to book value and the following combination 6 of return on common equity and retained earnings after 7 dividends:
8 Retained Return on Earnings Earnings X Common Equity = Growth 9
10 35% 20.00% 7.0%
11 40 17.50 7.0 12 45 15.56 7.0 13 2. Price 20% greater than book value with sales of 5% of common 14 per year and the following combination of return on common 15 equity and retained earnings after dividends:
16 Retained Return on Benefit Earnings Earnings X Common Equity + From Sales = Growth 17 18 35% 17.14% 1.0% 7.0%
- 19. 40 15.00 1.0 7.0
'20 45 13.33 1.0 7.0 21 Since Edison is committed to maintaining a payout in the range of other 22 utilities .(about 65%), the above examples show that a return on common 23 equity in excess of 15% is needed to avoid downward stock price pressure.
- 24 Q. Does the composition of Edison's common stock investors impact the 25 sensitivity of Edison's ability to increase dividends sufficiently to l 26- compensate for the impact of. inflation?-
' 2 7' - A. Yes. . Edison has many common stock investors who are dependent. on dividends l
~28 for. income. Many of these are retired persons whose incomes would other-HFC-20 9-2 79
- 11. Fred Christic 1 wise be fixed. For exampic, Edison's common stock investors total 138,032 2 with the average holding per investor being only 457 shares. liowever, 3 registered individual holdings average only 174 shares per individual.
4 While individuals comprise the largest group, institutions hold 22.8% of 5 Edison's outstanding common stock. These institutions consist largely of 6 insurance companies, pension funds, and other fiduciaries.
7 Q. Ilow does the cost of bonds and preferred stock indicate an increase in 8 required return on common equity?
9 A. There are two ways that the cost of bonds and preferred stock affect the 10 cost of common equity. First, a risk premium is required to attract the 11 investor from the less risky bond and preferred stock investment to the 12 common stock investment. Even if this premium does not increase as bond 13 and preferred stock yields rise, the earnings required for a given stock 14 price will rise. If these earnings expectations do not rise, the common 15 stock price will fall. Since Edison's cost of debt has increased about 16 75 basis points since 1978, the cost of common equity of at least as much should be allowed. Table 22 and Chart 8 of Exhibit No. (SCE-1) show 17 18 the risk premium investors require to invest in common equity versus debt.
19 'Ihis is done by showing the difference between Aa bond yicids and Edison's 20 return on common equity adjusted for price / book ratio differentials.
21 Second, the return on common equity requirement is related to 22 imbedded cost icvel because coverage must be maintained if Edison's 23 financial integrity and credit standing are to be maintained. When 24 imbedded costs rise, interest coverage can be maintained by raising the 25 return on commen equity and reducing the debt ratio. Edison has reduced 26- its target debt ratio one percentage point from the 1977-1979 level.
27 Ilowever, this~alone is not sufficient to maintain the times interest earned 28 after tax ratio, 'as shown below using the 13.49% return on common authorized IIFC-21 112-18-79
l
- 11. Fred Christie 1 in Decision No. 89711 for expository purposes only:
2 1979 1981 Capital Cost Weighted Capital Cost Weighted 3 Ratios Factors Cost Ratios Factors Cost 4 Debt 48.0% 7.40% 3.55 47.0% 8.03% 3.774 Preferred 14.0 7.40 1.04 13.0 7.80 1.01 5 Common 38.0 13.49 5.13 40.0 13.49 5.40 6 Total 100.0% 9.72% 100.0% 10.18%
7 9.72%/3.55% = 2.74x 10.187/3.774 = 2.70x 8 For the 2.74x to be maintained even after the capital structure 9 changes, the return on common equity would have to be raised 39 basis 10 points *.. Table 24 of Exhibit No. (SCE-11 shows that at least a 15%
11 return on common equity is required in 1981 to maintain the 2.8 times 12 interest earned after tax that is the minimum level necessary to maintain 13 an Aa bond rating.
14' Q. Why are comparable carnings data significant in determining the appropriate 15 return on comon equity?
16 A. 'the Hope and Bluefield cases established comparable earnings as one of the 17 tests required to be met in determining the reasonableness of utility 18 rates.
19 _Q. What-are'the problems in applying comparable earnings?
20 'A. 'Ihe first problem is to identify a comparable group that also meets the 21 financial integrity,' credit standing, and capital attraction tests of the
.22 -Hope and Bluefield decisions. 'Ihe second problem is the avoidance of 23 ' circularity ;(e.g. , inadequate returns for one company used to justify 24 l inadequate _ returns for another company). The third problem is to determine 25 if the earnings _of the comparable group have been adequate.
26 ~Q. What criteria have you used to identify the comparable group of companies
'27 - in order- to meet the financial integrity, credit standing, and capital V 10.33%/3.75 - 2.74x 10.33% ' 3.73 - 1.01%~ = 5.55%/40.0% .13.88% 13.49% = 0.394 -
212-15-79
l H. Fred Christie l
1 attraction tests?
2 A. De selection criteria for the comparable group has been made as follows:
3 1. H e companies should be regulated utilities which receive 4 at least 90% of their revenues from electric utility l
5 operations. This assures that the group is engaged in l
[ 6 essentially the same business as Edison and indicates that l 7 their business risks are similar.
l l 8 2. ne bonds of these utilities should have been rated no less l 9 than single-A by both N ody's and Standard and Poor's during i
! 10 the past five years. Since bond ratings indicate credit l 11 standing and level of financial integrity, this assures that 12 the utilities selected will be similar to Edison with regard 13 to credit standing and financial integrity.
14 3. The conmon stocks of the utilities should be traded on the 15 stock exchanges and be .widely held. His provides a basis 16 to test the adequacy of returns on comon equity through 17 price performance with regard to the capital attraction test.
18 4. H e utilities should be relatively large with large capital 19 needs in order to be similar-to Edison. His avoids scale
~20 problems and includes utilities with similar capital needs.
21--Q. Please describe the comparabic group you have selected for comparable 22 earnings analysis.
~23 .A. Tables 15 and 16 of Exhibit No. (SCE-1) list the 20 largest electric 24 utilities. - Table 15 ranks the 12 double-A' and 8 single-A utilities by.
4 '25 ; operating revenues, shows the percent electric, and also provides fuel
-- 26 expense _and labor expense data. Table 16-indicates the bond ratings, 27 deratings,l shares outstanding, number of shareholders, shares per stock-
._28 , holder, percent of _ shares' held by institutions, net utility plant , and the
. . . HFC-23 8.-30-7 9, -
II. Fred Christic 1 magnitude of construction expenditures relative to net utility plant.
2 Q. Ilow have you avoided the problem of circularity?
3 A. Circularity with regard to the 20 largest electric utilities has been 4 avoided as follows:
5 1. Several jurisdictions regulate the 20 largest electric 6 utilities; thus, a cross section of regulators' judgments 7 are represented.
8 2. These regulators' judgments at: made at diverse times and 9 intervals.
2 10 3. The common stock price performance of the 20 largest electric 11 utilities reflect investors' judgments as to the adequacy of l 12 the book returns.
13 4. ~ The 20 largest electric utilities' price performance may be 14 compared to that of unregulated enterprise as an independent
.15 test of relative attractiveness. Standard and Poor's 16 Industrials have been used to represent unregulated enter-17 prise.
'18 _ Q.- What comparable earnings data have you provided?
19 A. Tables 17 and 18 of Exhibit No. . (SCE-1) show the comparable earnings 20 data for Edison and the 20 largest electric utilities. Table 17 shows 21, earnings and dividends per share comparisons. The growth in the inflation 22 rate since 1969 exceeded that of Edison and the 20 largest electric 23' utilities. This means that utility investors have not maintained parity 24_ with inflation over the period. However, during the 1974-1978 period, 2S. ' Edison's earnings and dividends per share growth, while still less than 26 S't andard ano: Poor's Industrials,' exceeded that of the 20 largest electric
-27 utilities and the rate of inflation.
- 28 The circumstances which allowed Edison's earnings and dividends HFC-24 E 8-30-79 ,
H. Fred Christie 1 per share growth to exceed 7% on a trended basis during the 1974-1978 2~ period, unfortunately, cannot be sustained. First, the increase in the 3 return on common equity from the depressed 1974 level of 9.5% to the 4 1976-1977 level of 12.1%, as shown on Table 18, accounted for the sharp 5 earnings per share rise. Second, the change in dividend policy to increase 6 the payout from a historical level averaging about 55% to a level more 7 commensurate with the electric utility industry average accounted for the 8 unsustainable increase in dividends per share. The following example 9 shows the tremendous impact of these two changes:
10 Book Return on Earnings Dividends Value X Common Equity = Per Share X Payout = Per Share 11.
$30.00 9.5% $2.85 55'. $1.57 12 30. 00 12.0 3.60 65 2.34 13 Growth 26.3% 49.0%
14 Earlier testimony demonstrated that when 35% of earnings per 15 share are retained, the return on common equity must exceed 15% for a 7%
16 earnings per share growth to be sustained. Table 18 shows that while the J
.17 20 largest electric utilities' average returns on common equity :iere 18 higher than those for Edison during the 1969-1978 period, they were not
-19 sufficient to provide earnings per share growth to match investor expec-20 tations of a 7% inflation rate in the long run.
21 Since investors expect the inflation rate to be at about 7% in 22 the _ long run, Tables 17 and 18 indicate that Edison and the 20 largest 23_ group. require returns on common equity in excess of 15%.
24 'Q. Have you tested to see if investors believe- that the returns on common
- 25. equity earned by Edison and the 20 largest electric utilities are
?26 adequate?
- 27 .A.
Yes. Tables 19, 20, and 21 of Exhibit No. (SCE-1) indicate the-28 . price performance of Edison, the 20 largest' electric utilities, and HFC-25 8-30-79
H. Fred Christie 1 Standard and Poor's 400 Industrials. These data all indicate that the 2 returns on common equity for Edison and the 20 largest group have been 3 inadequate.
4 Table 19 shows that through 1978, the stock prices of the 20 S largest electric utilities and Edison are depressed, while the price index 6 for Standard and Poor's Industrials is not.
7f Table 20 shows the earnings / price ratios for Edison, the 20 8- largest group, and Standard and Poor's Industrials. These earnings / price ,
9 data reflect the relative attractiveness with Edison being the least 10 attractive and the 20 largest group being more attractive than Edison but 11 less attractive than unregulated enterprise, as represented by Standard 12 and Poor's Industrials.
11 3 ' Tabic 21 shows the price / book ratios with Edison the least 14 - ' attractive and the 20 largest group more attractive than Edison but less 1S attractive than unregulated enterprise. In addition, Edison's cornon stock 16 . price remained well below book value during each year of the 1973-1978 17' period, and the 20 largest group's price / book ratio averaged just less than one-during the >ame period, although exceeding book value in four out 18.
19 ' of six years.
- 20 Q. ' What conclusions can be drawn from these comparable . earnings and price
' 21 ' performance data shown on Tables 17, 18, 19, 20, and 21 of Exhibit No.
l 132. (SCE-1) ?
23 A. - The returns on common equity for Edison and the 20. largest electric
- i. L24' utilities have been inadequate, especially ' subsequent to 1973. For the i .
25- purchasing power of earnings and dividends per share to be maintained, a 26 . return on common . equity in excess of 15% is required. 'Since Edison and
'27 lthe 20 largest electric utilities have not achieved such earnings, their 28' . common stock prices.have fallen, earnings / price ratios have risen, and
. HFC-26 8-30179
H. Fred Christie 1 price / book ratios have fallen to less than one.
2 In addition, Edison's price performance indicates a return on 3 common equity requirement in excess of 15%. First, Edison's earnings / price 4 ratio during the 1974-1978 period reflects an investor requirement of 5 15.1%, as shown on Table 20 of Exhibit No. (SCE-1) . Second, Table 6 22 of Exhibit No. (SCE-1) reflects the investor return on common 7' equity requirement to raise Edison's price to book value. With price as a 8 function of return, a 14.9% return on common equity average is shown to be 9 required to raise Edison's price to book value since it fell below book 10 value in 1973.
'll Q. What other measures have you employed to demonstrate Edison's need for a 12 return on common equity in excess of 15%?
- 13. A. Table 23 of Exhibit No. (SCE-1) provides two comparisons. The first 14 method compares the recorded earnings per share to the average monthly 15 high-low price recorded during the same year. On this basis, the cost of 16 common stock during the 1974-1978 period averaged 15.6%.
17 The second method uses five years of recorded data to provide 18 the expected earnings per share extrapolated by exponential curve fit.
19 . These trend e'a rnings per share are then compared to' year-end price. On 20 this . basis, the cost of common stock during the 1974-1978 period averaged 21 16.0%.
.22 Q. Was risk considered in determining Edison's cost of common equity?
23- A. Yes. As indicated earlier, a comparable group was selected to present the. investor a similar risk. situation in order that the comparable require-
~
24
_25 ment would be satisfied in determing the cost of common equity.
26 Q. What risks do these _ utilities and Edison now face that may' have changed L ~
27 Ltheir cost of' capital in recent years?
28' A. Edison's depressed _ stock price since 1972 and that of comparable utilities HFC .8-30 II. Fred Christie 1 Indicate that the authorized and earned returns on common equity have not 2 increased sufficiently to compensate for the increased risk.
3 Q. Why do you believe that investors perceive an increase in risk associated 4 with Edison's comparable utilities' securities in recent years?
5 A. While there is no certainty that either an exact or a complete list of i 6 reasons for investors' perceptions can be captured, some examples can be 7 listed as to why investors perceive that the risk associated with an 7 8 investment in Edison and comparable electric utilities have increased. In 9 doing so, the risks will be separated into two classifications - business 10 and financial. The business risks include:
-11 1. The fear of loss of investment has received increased 12- attention. The Three Mile Island incident demonstrated 13 that even after state and federal regulatory approvals, 14 a multi-billion dollar investment can be lost, and unlimited 15 lawsuits can follow into the distant future.
16 2. Plant siting problems continue to increase. Millions are 17~ spent on feasibility and environmental impact studies before
-lo- applications for operating permits are considered.
.19 3. Environmental concerns make operating conditions and costs 20 _ relating to new and existing generating facilities uncertain.
21 Environmental control standards and requirements are unstable, 22 and many are based on " state-of-the-art" technology before 23 . testing.
- 24 4. Special_ interest and consumer hara f sment continues Eto
.25l increase with outcomes uncertain, but over-reaction is often 26 .the result.
l27- 5. Longer lead times to build more costly generating facilities increase financial problems, placing many utilities in the
~
28
. -HFC 30-79.
H. Fred Christie 1 position that the failure of one project could mean the 2 failure of the company.
3 6. Edison's dependency upon oil-fired generation is a concern.
4 Availability of low sulfur fuel oil originating primarily 5 from overseas sources is less certain than in the past.
6 7. While the fuel adjustment clause reduces the impact of 7 increased risk associated with the rising cost of fuel oil, 8 it does not eliminate the risk. At the same time, it 9 introduces cash flow problems and regulatory risk. Under-10 collections in excess of $100 million are not uncommon.
11 These accumulate while the costs already incurred for fuel 12 are reviewed with no certainty that all will be recovered.
13 8. The magnitude of Edison's fuel cost increases places 14 additional pressure on regulators to resist other needed 15 rate relief.
16 9. Successful conservation efforts can cause revenues to be 17 less than assumed when fixing the rates authorized.
18 10. Technological changes are more rapid, increasing the speed 19 of obsolescence and increasing the risk associated with new 20 projects that may not be economically viable.
21 *1. Resale business is more risky than in the past.
22 a. The level of energy supplied fluctuates while the 23 capacity to serve to meet total resale customer needs 34 continues.
35 b. The timing of when resale customers will drop Edison 26 capacity and energy sales is uncertain.
27 c. Participation in generation projects by resale customers 28 follows after the front-end risks are assumed by Edison.
HFC-29 8-30-79
- 11. Fred Christie 1 -12. Inflation impacts capital-intensive, regulated utilities
'2 more than unregulated enterprises.
3 a. Rate relief does not keep pace with increased operating
- 4 and financing costs (attrition) .
.5' b. Investments at a single site become so large that the
- 6 risk of catastrophic loss increases.
- 7. c. H e temptation by regulators to undernourish utilities 8 makes them less able to survive a shock of even less 9 magnitude than the Three Mile Island incident. <
10 13. He effect of price changes, innovative rate designs, 11 conservation and load management efforts, and government 12 regulations on usage makes demand forecasting less certain.
13L 14. Federal and state energy policies are not always clear and 14 consistent.- At times, energy policies direct themselves
~
- 15 at goals in opposition to other policy, with the result 16 being counter-productive.
17 The ~ financial risks that have increased include the following:
18 1. The need to continue to sell common stock below book
~19 - value to c'ontinue the construction program reduces the
!20 ' commonLequity. investment per share which further dissipates
~ 21 the attractiveness of Edison's common stock to investors.
'22f 2. He danger of bond and preferred stock doratings increases
~
with the magnitude of financing needs and the' higher level
~
23 (24 - . ofifinancing costs. . Rising imbedded debt costs. place 25; pressure on interest coverage.
- 3. . Edison.is conmiitted to a construction-program to meet ~
4 27x . consumerIdemand and cannot postpone construction 28
- expenditures.-lne' increase'd financin'g needs make the I .
-HFC-30..
L8-30 ,79. ~
1 x
y ,t g ' - * -r+ g- f [g & . -e e- r-, i r--,w+y ". - yw=-, r--1m,-4 -t~-m < - w -- er
l H. Fred Christie 1 Company more dependent on and subject to the whims of a
)
2 finite capital market. l 3 4. The quality of earnings deteriorates as a higher percentage 4 of earnings are comprised of AFDC.
5 Q. Mr. Christie, have you indicated what Edison's minimum capital costs are?
.6 A. Yes. Table 24 of Exhibit No. (SCE-1) shows that with a 15% return 7 on common equity and the target capital ratios of 47% debt,13% preferred 8 stock, and 40% common equity, the 1981 composite average cost of capital 9 is 10.78%. A return on rate base of 10.78% in 1981 would allow a 2.86 10 times interest earned after tax which, in my judgment, would allow the 11 Company to maintain its current bond rating.
12 Q. Does Table 24 of Exhibit No. (SCE-1) show anythingin addition to 13 the 1961 composite cost of capital?
14 A. Yes. Table 24 of Exhibit No. (SCE-1) also shows Edison's 1982 15 composite average cost of capital to be about 10.93%. The reason the 16 _1982 composite average cost of capital is 15 basis points higher than the 17 1981 cost is because the imbedded cost of debt rose 27 basis points while 18 the imbedded cost of preferred stock rose 10 basis points during that same 19 year. The Commission should consider this 15 basis point increase in the 20 composite average cost .of capital as part of the attrition allowance 21 requirement when authorizing Edison's 1981 return on rate base.
22 Q. Do you believe the factual material contained in Exhibit No. (SCE-1) 23 is accurate?
24 A. Yes.
25 Q. ; Insofar as that material in your testimony represents your opinion, 26- does it represent your best judgment?
27 A. Yes.
~ 28 'Q. Does this conclude your prepared' testimony?
29 A. Yes,-it does.
HFC-31
'.12-15-79
SOUTHERN CALIFORNI A EDISON COMPANY Prepared Testimony of Robert P. Haub Exhibit No. (SC E-2) , Chapters 1, 2, and 3 1 Q. Will you please state your name and address for the record?
2 A. My name is Robert P. Haub, and my business address is 2244 Walnut Grove 3 Avenue, Rosemead, California.
4 Q. What is your position with the Southern California Edison Company?
5 A. I am a Supervising Regulatory Cost Specialist in the Company's Revenue 6_ Requirements Department.
7 Q. Please refer to Exhibit No. (SCE-3) for identification, entitled 8 " qualifications of Witnesses". Directing your attention to the page 9- entitled " Qualifications of Robert P. Haub", does that portion of the 10 exhibit accurately set forth your background, training, and experience?
11 A. It does.
12 Q. Are you testifying with respect to Chapters 1, 2, and 3 of Exhibit 13 No. (S'CE-2) for identification, entitled "Results of Operations"?
14 A. Yes, I am.
15 Q. Were those chapters prepared by you or under your supervision?
A.. Yes, with the exception of Chart 3-B, Summer Generating Capacity and
~
16 17 Peak Demand, and Section F - Palo Verde Units 4 & 5, which were prepared
- 18 for me by the responsible departments. This material will be covered by
~19 ; witness M. D. Whyte in his . testimony relating to Chapter 13
-20 Q. -Referring now to Chapter 1, entitled " Introduction", please indicate 21- briefly the. purpose' and scope of that chapter.
.22 'A. The purpose and scope of Chapter 1 is to introduce this exhibit covering 23' the Results of Operations of the Southern California Edison Company, which 8-13-79.- 1/2/3-1 E
Robart P. Hrub i has been prepared in support of the Company's application for a general 2 increase in its rates for electric service.
3 Q. Turning now to Chapter 2, entitled " History", please indicate generally 4 what is reflected in that chapter.
5 A. Section A presents the corporate history of the Southern California Edison 6 Company f rom its earliest predecessor, which is considered to be West 7 Side Lighting Company, incorporated in California in 1896, through its 8 merger with the California Electric Power Company in 1963 The develop-9 ment of the Company is graphically depicted on Chart 2-A.
10 3ection B presents significant features of electric service -
11 history within the territory now served by Southern California Edison 12 Company, 13 Section C summarizes significant proceedings before the CPUC 14- to which Edison'is a party. The decisions included reflect the scope of 15 matters which bring the Company before the CPUC and include plant sitings, 16 rate changes,-and general investigation proceedings, among others.
17 Q. 'Now turning .to Chapter 3, entitled "Present Operations", what does 18 that chapter cover?
19 A.. In general. terms, it aescribes the present operations of the Company.
20 Q. What information is contained in Section A?
21 A. Section A ' describes the territory served. Southern California Edison 22 Company sells electric energy under its certificates of public convenience 23- and necessity in fifteen counties in central and southern California.
241 Electrical service'Is furnished within these counties to some 800 cities 25 and communities.
26 A map showing the present division boundaries and district 27- : offices is presented on Chart 3-A. The population of the area served 28 was estimated to be 8,062,000 as of December 1978.
8-28 1/2/3 L
Reibsrt P. Haub 1 Q. With what other electric utility systems does Southern California Edison 2 Company sell, buy, or Interchange electricity?
3 A. The Company sells electric power to the cities of Anaheim, Azusa, Banning, 4 Colton, Riverside, and Vernon. Each of these customers owns 5 the distribution system within its boundaries. Additionally, as of 6 December 1978, electric power was sold to, purchased from, or inter-7 changed with various nonassociated utilities, municipalities, cooperatives, 8 and pubile authorities, including the State of California, the U. S.
9 Department of interior, and the Bonneville Power Adminis tration.
10 Q. Please describe the Company's production facilities.
11 A. These are described on the table in Section B of Chapter 3. The table 12 shows that at the end of 1978, the Company's generating resources were 13 comprised of 14 oil and gas plants containing 41 steam units, 4 combined 14 cycle units, and 7 combustion turbine units, 2 coal plants with 4 units, 15 one nuclear plant with one unit, one diesel plant with 5 units, and 36 16 hydro plants consisting of 79 units.
17 As of December 1978, the total effective operating capacity of 18 these facilities was 13,156,120 kilowatts. Additionally, the Company 19 had 1,201,003 kilowatts of firm capacity available under the terms of 20 purchased power agreements, 100,000 kliowatts from May through October 21 under the provisions of the Portland General Electric Company Assignment 22 Agreement, and from 345,950 to 349,500 kilowatts of seasonally adjusted 23 operating capacity, under generally prevailing conditions, at Y. caver Dam 24 and the Parker-Davis Dam sites through contracts with the United States 25 Government. -
26 Q. What does Chart.3-B show?
27 A. Chart 3-B 111ustrates the growth of effective generating capacity and 8-22-79 1/2/3-3
Robsrt P. Hrub i summer peak demand f rom 1969 through 1978, together wi th planned 2 addi tions to capacity and expected summer peak demand f rom 1979 through 3 1990.
4 Q. Referring now to 'section C of Chapter 3, please describe, briefly, the 5 company's transinir.slon system.
6 A. As of December 31, 1978, there were 11,628 circuit miles of transmission 7 lines for voltages between 33 kV and 800 kv, inclusive. This is an in- ;
8 crease of approximately 0 7% over the 11,549 circuit miles on December 9 31, 1977. These lines transmitted power to and between 53 transmission 10 substations, not including generating station switch yards, with an aggre-11 gate transformer capacity of approximately 30 million kVA.
12 Chart 3-C shows the Extra High Voltage Transmission System 13 through 1978..
!!4 Q. .Please describe, briefly, the Company's distribution system.
15 A. The electrical distribution system as of December. 31, 1978, consisted of 16 approximately 41,446 miles of overhead lines (not including 2,342 miles
~17 of distribution lines on transmission poles), approximately 8,403 miles 18 of underground trench with 28,953 miles of underground cable of 16 kV 19 or less. These were supplied from 540 distribution substations with an 20 aggregate capacity of approximately 14 million- kVA.
l '21 The number of installed electric meters increased from 2,938,615 22 at-'the end of 1977 to 3,024,325 at-the end of 1978, an increase of 2.9%
23 Total sales decreased f rom 57 7 billion kilowatthours during 24 the year 1977 to 57.0. billion kilowatthours during the year 1978, a decrease 25 of 1.2%, as a result of the absence of unusually high energy sales to drought-20 affected utilities in 1977 27 Q.
Referring to Table 3-A, what were the principal sources and general dis-28- . position of electric energy-during 19787'
< 8-28-79 1/2/3-4
Rob 2rt P. H3ub I A. Section A of Table 3-A shows that 68.6% of the energy was obtained f rom 2 steam, 3.4% from nuclear, 9 2% f rom hydro, and 1.9% from other generation.
3 Purchased and interchanged power totaled 16.9%. The disposition of this 4 energy is described in Section B. The system load totaled 63.9 billion 5 kilowatthours, of which 89 3% was sold. Energy losses and Company use 6 account for the balance of 10.7%. Of the 57.0 billion kilcwatthours sold, 7 domestic use amounted to 27.0%, lighting and small power use was 18.2%,
8 large power customers consumed 24.6%, and the very large power customer 9 use was 16.5%. Remaining sales accounted for the balance of 13.7%.
iC Q. What is the purpose of the statement regarding the Palo Verde Units 4 & 5 11 Project outlined in Section F of the exhibit?
12 A. The purpose of the statement made in the exhibit text is to describe the 13 circumstances surrounding Edison's participation in that project and the 14 cancellation of that project resulting in the abandonment losses reflected 15 In the cost data included in this filing.
16 Q. Mr. Haub, insofar as the material in Chapters 1, 2, and 3 of Exhibit No.
17 (SCE-2) is of a factual nature, do you believe it to be accurate?
18 A. Yes, I do. .
19 Q. Insofar as it represents opinion, does it represent your best Judgment?
20 A. Yes, it does.
21 Q. Does this conclude your prepared testinony?
22 A. Yes, it does.
8-28-79 1/2/3-5
SOUTHERN CALIFORNI A EDISON COMPANY Prepared Testimony of Anthony L. Smith Exhibit No. (SCE-?) , Chapters 4, 5, and 6 1 Q. 'Will you please state your name and address for the record?
2 A. My name is Anthony L. Smith, and my business address is 2244 Walnut Grove 3 Avenue, Rosemead, California.
4 Q. What is your position with the Southern California Edison Company?
5 A. -Supervisor of Financial Accounting.
6 Q. Please refer to Exhibit No. (SCE-3) for identification, entitled 7 " Qualifications of Witnesses". Directing your attention to the page 8 entitled " Qualifications of Anthony L. Smith", does that portion af the 9 exhibit accurately set forth your background, training, and experience?
10- A. Yes, it does.
1I Q. -Are you testifying with respect to Chapters 4, 5, and 6 of Exhibit No.
I2 (SCE-2) for identification, entitled "Results of Operations"?
- 13. A. Yes.
141~Q. Directing your attention now to Chapters 4, 5, and 6 of Exhibit No.
15 (SCE-2) , were those chapters prepared by you or under your
- 16) -supervision?
17 -A. Yes, they were.
18 . Q. ' Please briefly indicate what Chapter 4 shows.
19 A. . Chapter 4 reflects the financial position of the Southern California 20- Edison Company.- It contains comparative balance sheets, as of December 31, 31 -for the years-1976, I977, and'1978.
It also includes explanatory comments
-22' relating to.some of the accounts contained in the balance sheet as of 23 ' December: 31, 1978.
- 7-27-79 )4/5/6-1
Anthony L. Smith I The balance of the chapter reflects certain detail as to various 2 reserves and to Statements of Changes in Financial Position for each of
- 3 the years 1976, 1977, and 1978, as shown on Table 4-C.
r j 4 Q. Please indicate briefly what Chapter 5 shows.
5 A. This chapter deals with income and retained earnings statements. It 6 contains the following tables:
i 7 Table 5-A, Statements of income, covering the years 1976, 1977 8 and 1978.
9 Table S-B, Statements of Retained Earnings, covering the years 10 1976, 1977, and 1978.
11 Table 5-C, Disposition of Earnings, covering the years ended 12 1976, 1977, and 1978.
13 Table 5-D, Earnings and Dividends on Common and Original Pre-14 ferred Stock, for the period 1968 through 1978.
15 - Q. Turning now to Chapter 6, designated " Clearing Accounts", please indicate
'16 briefly what'this chapter shows.
17 A. The Company currently maintains 31 clearing accounts used for the purpose 18 of clearing various expenses to job and work orders or to operation and 19 maintenance expense accounts.
20 Table 6-A is a summary' of charges and credits tr, the various 21 clearing accounts'for the years 1976, 1977, and 1978, indicating a volume 22 of charges'and credits to these accounts for each of these years.
23 Q. Mr. Smith, insofar as the material presented in _ Chapters 4, 5, and 6
-24 of Exhibit No. (SCE-2) is of a factual. nature, do you believe it
'25 ~to be correct?
.26 TA. Ido.
In so far as the material in those chapters represents opinion, does it
~
27 KQ.
~
l28 / represent your best j udgment?
- 7-27-79L 4/5/6-2
Anthony L. Smith 1 A. It does.
2 Q. Does this conclude your prepared testimony?
3 A. Yes, it does.
4/5/6-3 7-27-79
SOUTHEkN CALIFORillA EDISON COMPANY Prepared Testimony of M. D. Whyte Exhibit No. (SCE-2) , Chapter 7 (Part 1)
I Q. Please state your full name and address for the record.
2 A. My name is M. D. Whyte. My business address is 2244 Walnut Grove Avenue, 3 Rosemead, California.
4 Q. What is your position with the Southern California Edison Company?
5 A. I am the Manager of the Electric System Planning Division of the System 6 Development Department.
7 Q. Please refer to Exhibit No. (SCE-3) for identification, entitled 8 " Qualifications of Witnesses". Directing your attention to the page 9 entitled " Qualifications of M. D. Whyte", does that portion of the exhibit 10 accurately set forth your background, training, and experience?
11 A. It does.
12 Q. Are you testifying with respect to Chapter 7 of Exhibit No. (SCE-2) 13 for identification in this proceeding:
14 A. Yes, for Part i of Chapter / relating to kilowatthour sales and customers, 15 as presented in Table 7-A.
16 Q. Was Part I of Chapter 7 prepared by you or under your supervision?
17 A. Yes, it was.
18 Q. Has the forecasting procedure used in preparing Part 1 of Chapter 7 been 19 changed since Edison's last rate case?
20 A. Yes, it has.
.21 Q. .Please describe the nature of changes in Edison's forecasting procedure.
22 A. Previously, Edison used a " committee" approach to estimating kilowatthour 23 sales and customers. ' The committee was comprised of representatives from 8-22-79 7(1)-1
H. D. Whyte I the following organizations: Comptroller's; Conservation, Cocynunications, 2 and Revenue Services; Customer Service; System Development; Power 3 Supply; and Treasurer's. Each convaittee member (except Power Supply) 4 prepared forecast estimates which were averaged to develop the singic 5 estimate for each customer class.
6 Since February 1979, the responsibility of preparing kilowatt-7 hour sales and customer estimates was transferred to my department. We 8 continue to utilize representatives from other departments as advisors 9 to review the assumptions used in the forecast. Hovever, the forecasts 10 are now developed under my direction, il Q. Pica'e explain generally how the kilowatthour sales estimates were made 12 for 1979, 1980, and 1981, as presented in Table 7-A in Part 1 of Chapter 7.
13 A. Econometric models are used to develop initial kilowatthour sales estimates 14 for the residential, commercial, industrial, other public authority, and 15 resale customer classes, based on historical regressions. These estimates I6 are adjusted based on judgment, short-term economic trends, and expected 17 conservation impacts. Agricultural sales are estimated to remain constant 18 except for the impact of conservation programs and are based on average 19 precipitation conditions.
20 Estimated sales for the State Water Project (SWP) are based on 21 the State Department of Water Resources' estimate of power required from 22 the California suppliers to pump water through the Californla aqueduct 23 and represent Edison's estimated share of such supply obligation. Metro-24 politan Water District (HWD) and Resale - Special Contracts' expected 25 kilowatthour sales are based on forecasts by the customer or firm contracts.
26 Q. Please describe the econometric model used in preparing the kilowatt-27 hour sales estimates.
28 A. Electricity sales for each customer class are forecast as a function of
.8-22-79 7(1)-2
_ _ . . . ._ _ . ___._ _.____m _
L M. D. Whyts i electricity price, natural gas price, previous year's sales, and an 2 econoe.lc variable (personal income or gross state product). These l
3 variables are adjusted for the effect of inflation - that is, all econ-4 omic variables are in " constant" dollars. The regression equations are !
5 developed from a historical data base starting in 1951.
6 q. How do you take con.servation into account in your forecast?
7 A. The impact of conservation can be grouped into several categarles. First 8 is voluntary conservation, including " price-induced" conservation which 9 represents our customers' responses to changes in electricity prices.
10 Also included are other customer actions which take place due to customers' 11 own initiative'or in response to advertising and other utility conserva-12 tion programs. The impact of such conservation is accounted for directly 13 In our forecast through the price variable.
14 Second is the impact of conservation programs on Edison's side 15 of the meter, such as conservation voltage regulation (CVR),and street-16 Ilght conversion. The impact of these efforts is estimated empirically 17 and' incorporated in the forecast.
IS Third is the impact of conservation programs mandated by regu-19 lations, such as applience efficiency standards, building insulation 20 standards, etc. .The impact of these programs on sales is based on 21 ' estimates of new applicances and buildings and the impact of standards 22 on .isage per appliance or per square foot of building space. The fore-23 castsalesareadjustedtoreflectthe.impactofthemandatoryconser-
'24 vation programs.
.25 q. How does recorded sales history: Impact your forecast?
'26 'A. .We monitor recorded kilowatthour sales and transmitted data closely to 27 . identify factors which may influence future sales. Due to billing lags,
- 28: Ltransmitted kilowatthour data provides a five-to-six week forward look
- 7 (1)-3 9-2-79
M. D. Whyta I- at expected kilowatthour sales. This allows us to reflect the impact of 2 short-term trends on the forecast of kilowatthour sales. This is im-3 portant because econometric models forecast changes in future activity 4 on the basis of long-term historical correlations and do not always 5 reflect short-term perturbations.
6 q. How do you develop forecasts of economic variables used for the kilo-7 watthour sales estimates presented in Part 1, Chapter 77 l 8 A. We use the Data Resources, Inc. (ORI), economic forecasts for the nation 9 and the University of California, Los Angeles (UCLA), model of the ,
10 California economy to develop the economic Inputs for the forecast.
11 These estimates of economic activity are adjusted, if necessary, to ,
12 account for unique economic and population trends in the Edison service 13 territory.
14 Electricity prices are based on rates adjusted for expected 15 changes in fuel costs and the rate base due to changes in generation, 16 transmission, and other facilities. Natural gas prices are based on the 17 latest available projections. tiectricity and gas prices used in the 18 forecasting model are in terms of " constant" dollars.
19 'Q. What types of customers are included in the classification designated 20 as "Other Public Authorities"?
- 21. A. Included in this classification.are military establishments; pubile 22 schools; _ federal, state, county, and. city governmental of fices; and
-23: street and public highway lighting.
t 4
l24 q. Would you briefly explain the basis for. the estimates for the increase in 25 the number-of customers for 1979, 1980, and 1981, as shown on Table 7-A?
26; A. We' estimate the total increase in customers on the basis of building 27 ' activity,' past and present trends of customer growth, In-migration into 28 :the service territory, economic conditions, and any other appropriate 8-22-79l --7 (1 ) . _
M. D. Whyte I factors.
2 in 1978, our customers increased by 85,689 on the strength of 3 a high level of building construction. Construction permits started to 4 turn down in August of 1978 We are forecasting customer increases of 5 81,000 for 1979, 76,000 for 1980, and 76,000 for 1981, reflecting the 6 construction slowdown.
7 0.. Are the system load estimates used to develop Power Production Expenses 8 in Chapter 8 based on the kilowatthour sales forecast?
9 A. Yes, they are.
10 Q. Please describe how system loads are estimated.
11 A. System loads are equal to forecast sales plus estimated losses.
12 q. Mr. Whyte, insofar as the material presented in Part I of Chapter 7 of 13 Exhibit No. (SCE-2) is of a factual nature, do you believe it to 14 - be correct?
15 A. I do.
16 q. Insofar as it represents opinion, does it reflect your best judgment?
17 A. It does.
'8-22-79 7(1)-5
Warrcn E. Ferguson SOUTHERN CALIFORNIA EDISON COMPANY Prepared Testimony of Warren E. Fe rguson Exhibi t tb. (SCE-2) . Chapter 7, Parts Il & III 1 Q. Please state your full name and address for the record.
2 A. My name is Warren E. Ferguson. My business address is 2244 Walnut Grove 3 Avenue, Rosemead, California.
- 4. Q. What is your position with the Southern California Edison Company, 5 Mr. Ferguson?
6 A. I am Manager of Tariffs in the Revenue Requirements Department.
7 Q. Please refer to Exhibit tb. (SCE-3) for identification, entitled 8 " Qualifications of Witnesses". Directing your attention to the page 9 entitled " Qualifications of Warren E. Ferguson", does that portion of the 10 exhibit accurately set forth your background, training, and experience?
11 A. It does.
12 Q. Are you testifying with respect to Chapter 7 of Exhibit No. (SCE-2) 13 for identification in this proceeding?
14 A. Yes, for Parts lI & III of Chapter 7.
15 Q. Were these parts of Chapter 7 prepared by you or under your supervision?
16 A. Yes, they were.
17 Q. What does Part ll of Chapter 7 cover?
'18 A. It covers the translation of the kilowatthour sales forecast by revenue 19 class, shown in Part I, to customer group.
20 Q. What is the basis for the translation?
.21 A.- Based upon our historical data, the kilowatthour sales, by revenue class, 22 are spread to rate schedules. The sales are then further adjusted by 23 known or anticipated transfers of customers either between rate schedules 7(11/111)-1 8-28 WsrrIn E. Ferguson 1 or to rate schedules which were effective at the time of preparation of 2 this filing for which little or no historical data is available.
3 Q. Could you explain that a little further?
4 .A. For example, we have had some 500 customers during the first six months 5 of 1979 transfer from Rate Schedule No. A-7 to Rate Schedule No. GS-2.
6 These are primarily low load factor customers who benefit from the lower 7 demand charges of the latter schedule. Because the transfers are so 8 recent, our historical data does not fully reflect this transition.
9 Similarly, Schedule No. TOU-8 became effective for customers with demands 10 between 1,000 kW and 5,000 kW at about the time the filing was being 11 prepared. As a result, we were aware that customers would be trans-12 ferred from Schedules Nos. A-7 and PA-2 to Schedule No. TOU-8. Ob-13 vlously, the historical data for these schedules does not reflect these 14 . changes.
15 Q. What does Part ill of Chapter 7 cover?
16 A. _It covers revenues derived from the sale of electric energy and from such 17 other sources as rental of electric properties, transmission charges for 18 redelivery of energy, and other miscellaneous services to our customers.
19 in this part of the chapter are presented the recorder' operating revenues
'20 by rate' schedule and customer group for 1976, 1977, and 1978, as well as
-21 the estimated operating revenues for 1979, 1980, and 1981.
22_ Q. ' Please explain how the revenue estimates were made for the years 1979,
- 23. 1980, and 1981 for Chanter 7 24 A. Again, based upon our historical data, the kilowatthour sales, kilowatt-25 . months, and horsepower-years-by rate schedule are spread to the various 26 billing blocks. Base rate revenues are then calculated at the presently
~
-27 effective base tariffs. In addition, revenue was also computed based 28 'upon Edison's currently effective Energy Cost Adjustment Clause, with 7(11/111)-2 9-3-79
Warren E. Ferguson 1 future billing factors based upon estimated fuel and purchased power 2 expenses. The revenues were then further adjusted to reflect changes as 3 a result of the operation of the balancing account contained in the Energy 4 Cost Adjustment Clause. The revenues derived in this manner were then 5 combined to produce total revenues by customer group.
6 Q. Table 7-H, also shows kilowatt-months and horsepower-years.
7 What is the purpose of that estimate?
8 A. In order to develop revenues for rate schedules with demand or connected 9 load charges, it is necessary to estimate kilowatt-months and horsepower-10 years. Historically, although the Company has always done this in pre-11 paring revenue estimates, it has never been shown in the forecast, and
- 12 the Commission has always adopted only a kilowatthour sales estimate in 13 Its decision. Since a substantial portion of the Company's base rate 14 revenue is now derived from such charges, I believe it is appropriate for 15 these estimates to be included in the table, and I would urge the 16 Commission in its decision to not only adopt a kliowatthour sales estimate 17 but also a kilowatt-month and horsepower-year estimate where appropriate.
18 , Q. Would you please explain briefly what types of accounts are comprised in
.19 the "Other Operating Revenue" classification?
20' -A. "Other Operating Revenue" consists of revenues received by the Company for
- 21 other than sales of electric energy. These would include, for example, 22 revenues from the service establishment charge, reconnection charges, and 23 special contractual agreements involving the transmission of energy for 24 others under various' transmission service agreements. Revenue in this 25 classification is.also realized from meter and transformer rentals, special 26 contract rentals, joint pole and property rentals, the installation of
- 27. : additional facilities to customers under added facilities agreements, and 28~ -other miscellaneous services.
7(11/181)-3 12-15-79'
W:rr n E. Ferguson l
1 Q. M r. Ferguson, insofar as the material presented in Parts ll and lit, l l
2 Chapter 7 of Exhibit No. (SCE-2) is of a factual nature, do you 3 believe it to be correct?
4 A. I do.
- 5. Q. Insofar as t represents opinion, does it reflect your best judgeent?
6 A. It does.
7(11/111)-4 8-28-79
SOUTHERN CALIFORfilA EDISON COMPANY Prepared Testimony of Ronald V. Knapp Exhibit No. (SCE-2) , Chapter 8 I Q. Please state your name and address for the record.
'2 A. Ronald V. Knapp. My business address is 2244 Walnut Grove Avenue, 3 Rosemead, California.
4- Q. What is your position with the Southern California Edison Company?
5 ' A. Manager of System Operation in the Power Supply Department.
'6 Please refer to Exhibi t No. -(SCE-3) for identification, entitled Q. ,
7 " Qualifications of Witnesses". Directing your attention to the page 8 . enti tle'd " Qualifications of Ronald V. Knapp", does that portion of the
-9 exhibit; accurately set forth your background, training, and experience?
10 A. Yes, it does, l l . , Q. Mr. Krapp, what portion of the Southern California Edison Company's
-12 Results-of Operations exhibit are you sponsoring?
.13 A. -l am sponsoring Chapter 8, Power Production Expenses. I am also sponsor-14: ing Chapter 9, Transmission. Expenses.
215 :Q. Please indicate briefly what Section A of Chapter 8 covers.
16 - A. Section A of Chapter 8, titled " System Loads and Resources, Fuel, and
- 17. ~ -
~ Purchased Power.", includes fuel and purchased power expenses, recorded Ib' .and adjusted to average year condi tions for 1976,.1977, 1978, and the 19 .first nine months of 1979 -The remainder of 1979 and, years 1980 and 20' 1981. reflect estimated-average year conditions.
21 Q. Since fuel and purchased power expenses are covered by the energy' cost 22 adjustment clause . (ECAC), why-are they being included in the general rate
.23 case?
5-79~ 8-1
j Ronald V. Knzpp i A. Since some elements of the base rate cost of service (e.g., working capital) 2 are influenced by the full cost of service, it is appropriate to estimate 3 the full cost of service in the test year. In addition, I am advised that 4- the effect of domestic lifeline rates on customer group rate of return 5' only becomes evident by studying the rate of return by customer group under 6 full cost of service analysis. The fuel and purchased power expenses must ,
7 therefore,' necessarily be considered in this proceeding along wi th all other 8 costs.
- 9- Q. Where in this exhibit are net fuel and purchased power expenses shown af ter 10 removal of ECAC related expenses?
11 'A. Line 38 on Table 8-A reflects the net fuel and purchased power expenses 12 without ECAC. Calculation of ECAC related expense appears in footnotes 13 at'the bottom of Tables 7-C in Chapter 7
'l4 q. Having in mind the fact that energy produced from oil fuel is the most 15' costly.among the resources available to the Company, what methodology is 16 reflected in.your estimates that results in minimizing use of this source 17 .of energy?
.18 A. The basic tool that is used for determining the oil / gas unit energy require-
- 191 ment.Is'a' computer program that simulates the integration of Edison's
- 20 .r'esources to. meet the projected' load. Beginning with the load forecast, 121 the' program deducts energy .that is estimated to be available # rom resources
-22. other than oil / gas'such as hydro, nuclear, coal and purchased power. What-23: . ever- load ~ requirement L remains must be served by energy supplied by Edi son's 24 oil / gas 1 units. 'By providing the program with average year gas availability-25 data, the amount of energy expected to be generated on gas fuel is c.educted l 26 - f rom 7the rema'ining load : requi rement . Any residual load is assumed to be
'l
~27: : served.by.. units burning oil' fuel.
l 428 ; :QJ. ' Considering the favorable price'of purchased power in relation to energy 8-2'
- 12-5-79?
Ronald V. Knapp I derived from oil fuel, what effort is made to maximize energy purchases?
~2 A. The Company has an enti re division whose major responsibility is to nego-3 tlate long- and short-term contracts with utilities throughout the western 4 United States and Canada. In order to make these contracts work, we have 5 an aggressive power scheduling or " power broker" section devoted to ob-6 talning and scheduling any economical energy which is made available by 7 utilities on a day-before basis. In addition, on a real-time basis, our 8 Energy Control Center Dispatchers maintain a regular search for economical 9 hourly spot purchases to fill any remaining transmission line capacity.
10 in 1978, for example, we were successful in procuring energy 11 purchases amounting to about 17 percent of the Company's total energy re-12 quirement, representing a savings of almost 18 million barrels of fuel oil.
13 Of course, hydrological conditions in the northwest play a significant part 14 in the availability of purchased power, and 1978 was a better-than-average 15 year in this regard.
16 Q. Referring to Table 8-A, please indicate the volumes of fossil fuels ex-17 pected to be burned and discuss the price trend for these fuels from 1979 18 through 1981.
19 A. Our gas suppliers have estimated that average year gas availability will 20 decrease in future years resulting in greater dependence on oil fuel.
21 Approximately 21 million equivalent barrels of natural gas fuel are esti-22 mated to be available in 1979, 15 million equivalent barrels in 1980, and 23 11 million equivalent barrels in 1981. Due to inflation and gas deregula-24 tion, the average gas price is estimated to increase from $2.41 per million 25 Btu in 1979, to $3.35 per million Btu.in 1980, and to $4.02 per million 26 Btu in 1981.
27 Edison's share of coal consumption at Mohave and Four Corners in 28 1979, 1980, and 1981 is estimated to be 12, 15, and 15 million equivalent 8-3 12-5-79
Ronald V. Knapp 1 ba r re ls , respectively. Average coal prices are estimated to increase 2- from $0.68 per million Btu in 1979 to S0.70 and S0.79 per million Btu l
3 in 1980 and 1981. These estimates are based on the assumption that mining, l 4 transportation, and labor costs will continue an upward trend.
5 Oil fuel consumption in 1979, 1980, and 1981 is estimated to be 6 about 49, 56, and 61 million barrels, respectively, assuming average year 7 conditions. Average oil price estimates are influenced by recent OPEC 8 price-increases. and reflect domestic oil price decontrol. For the three 19- years,:1979 through 1981, average projected prices are about $20/ barrel, 10- $30/ barrel, and $36/ barrel, respectively. ;
11 Q. Looking now at nuclear production, what is the energy cost in the estimated 121 years, and what' do the expenses for San Onof re Unit 2 represent?
13 - A. The fuel expense. component of energy generated at 5,: Onofre Unit 1 is 14 estimated-to average about 4.8 mills /kWh in 1979, 6.3 mills /kWh in 1980, 15 _and 6.9 mills /kWh in 1981. These expenses are very favorable when com-
' 16L pared with' projected oil-fueled unit energy costs of 32 mills /kWh in 1979, 17_ 48 mills /kWh in 1980, and 58 mills /kWh in 1981.
. San Onof re Unit 2-is expected to be in a start-up and power 19 escalation phase f rom March I through June 30, 1981. Edison's share of (20 -pre-release energy ger -ated during this period is estimated to be about
- 21. 506.GWh and'is inclu n purchased power at an average oil-fueled ~ unit
'221 energy cost of 47 mills This expense will become a credit to the 23 Work Order.
24?- Beginning July 1, 1981, San Onofre Unit 2 is included ~in Thermal L25- StationfExpense, and_ energy iscpriced at about 12 mills /kWh.
26 : Q; : With' re's pect to 'pu'rchased Jxwcar, what is the basis for economy and surplus energy purchases,-Land what is'the expected price in 1979, 1980, and 19817
~
[27:
28 lA. -Economy-and surplus, energy is purchased'on a when-an-if-available basis.
t %
L 12-5-79 _
3
Ronald V. Knapp 1 The average year economy and surplus estimates are derived f rom an 2 -average of sixty months of recorded purchases through the end of 1978.
3 The price of economy energy is expected to average about 16.5 4 mills /kWh in 1979 and is estimated to increase approximately in proportion
-5 to the price of oil-fueled generation. Accordingly, estimates of 16.5, 6 18.5, and 21 mills /kWh were used for economy energy in 1979, 1980, and
[ 7 .1981, respectively.
8 Surplus energy is currently priced at 3.5 mills /kWh in the 1
9 winter months and 3 mills /kWh in the summer months. These rates are
- 10- subject to revision effective December 20, 1979, but since it is not 11 known to what extent the rate will be changed, surplus energy in 1979, 12 1980,.and 1981 is priced at the current rates.
L 13 Q. Turning to Section B of Chapter 8, please indicate briefly what the
,14 section-reflects.
15- A. This section_ includes the Operation and Maintenance Expenses (Pro-16 . duction - Excluding Fuel) for Steam, Hydro, Nuclear, and Other types 17 :of generation, summarized in Table 8-B for 1976-1978 recorded, and 1979,
- 18 1980, and 1981 estimated.
19 Q. How were the estimates for future years 1979, 1980,'and 1981 developed?
.20_ .A. We used a trending method.
21 Q. Mr. Knapp, please describe the methodology used to determine the:
-22 trende'd estimates.
23; ' A, . The estimated Production- Expense for: the f uture years 1979, 1980, and
- 24. 1981 was l derived by . trending historical ' data for the recorded years "25' 1974 through-1978. Adjustments were made to each ' account's historical 26 costs:for 1974.through 1978 to remove the. effects of' unusual conditions
. 27 that'would affect the recorded. year's usefulness for. trending. purposes.
28 Af ter the recorded- years were adjusted,- the recorded costs for 1974
-- 29; through 1978lwere indexed to 1978' dollars. This was the starting point-8-5 l12-7-79 t
Ronald V. Knapp 1 for the future year estinates. The adjusted-recorded f'gures were then 2 trended for estimates for three future years (1979-1981) . A least 3 squares linear trend method was used. The future year estimates were 4 developed, and each year was then escalated 7% for labor and 9-1/2%
5 for non-labor. Adjustments were made to the escalated estimate for 6 certain accounts by adding known signi ficant activi ties that were con-7 sidered new or expanded and for which costs would not be provided by a 8 trending method.
9 Q. How did you determine the escalation factors that were used to index the 10 recorded years to 1978 monies and the future year escalation factors for 11 1979, 1980, and 19817 12 A. Escalation rates for Operation and Maintenance accounts for Production 13 were developed by our Economics Division based on economic assumptions 14 and forecasts made by Data Resources, Inc. These escalation factors 15 were then converted to 1978 constant dollar inflator / deflator indices, 16 for the period 1974 through 1981, by our Revenue Requirements Department.
17 Q. Was this method of estimating used for Steam, Nuclear, Hydraulic, and Other 18 Power -Generat ion Accounts ?
19 A. Yes, with minor exception. -in determining the future year estimates for
'20 the Hydraulic Power accounts, it was decided to use a 9% escalation factor 21 : for non-labor estimates rather than the 9-l/2% used for Steam, Nuclear, 22 and Other Production.
23 ~ Q. Why?
24 A. This was a judgment' decision. In reviewing the ratio of material to con-25 tract work and the types and cost of materials used in Hydraulic Pro-
-26: duction, it was determined that the escalat;on factor for non-labor for
~
27 , Hydraulic expense should be 9%.
28 'Q. Mr.' Knapp, have any speci fic programs been initiated to reduce production, 8-6 12-6-79
Ronald V. Knapp 1 operation, and maintenance expenses?
-2 A. Edison has implemented many programs to increase productivity and reduce 3: operation and maintenance expenses. Our ef forts have been and will be 4 directed specifically toward increasing generating unit availability and 5 ' capacity, increasing reliability of our operating equipment, reducing 6 operating costs, and improving manpower productivity.
7 Q ,' Will you please tell us what specific programs have been undertaken to 8 improve productivity?
9 A. In the production, operation, and maintenance areas, a comprehensive 10 maintenance management system is being developed. The primary objective 11 of this' system is to improve unit reliability. Also, as part of our 12' program to reduce costs, an automated material inventory control system 13 is in the development stage. The system will provide better visibility 14 and control of maintenance.materiai and parts usage, thus reducing excess
~ 15 redundant stock and reduce stock shortages. In the area of cost reduction, we have recently implemented a 7-day work week at our Mohave Generating
-17~ Station. 'Under this arrangement, it is expected that labor costs will be 18 . reduced'as a result of reduced payment of overtime. Other programs being 19 ~ implemented include -integrating major maintenance and overhaul activities 20 at different production locations, expanding our capability of performing 21 repai r. work of major equipment , and more closely controlling work performed 22-
~
by contractors.
Our management is and has been dedicated toward improving pro-
~
23-24 'ductivity and controlling costs'. We plan to continue to seek areas of ImprovementLto reduce costs and improve productivity. To assist us in 25-26 7 this endeavor, we have obtained.the services of an outside consultant and 27? the! services-of our Company's internal- Audits Productivity Measurement -
28- organization.
18-7
' :12-6-79 2
. Ronald Vi Knapp l 1 Q. 'Will you please tell us specifically how these savings were included in 2 your estimates? I 3 A. Edison management has been and wi1I continue to be committed to increasing 4 productivity. This concept is not new to us. Our estimates have been
-5 developed based on a trending method, and since our recorded data implic-6 _Itly considers productivity improvement, no specific adjustments were 7 required.
8 Q. Mr. Knapp , in preparing the estimates for Production, did you have to make ,
9 adjustments to each account prior to developing the trended estimates?
1
'10 A. No. ' Accounts that did not have significant high or low yearly expenditures 11 and did not' distort the future year trend were not adjusted.
12 ~ Q. Were adjustments required for Accounts 500, operation supervision and 13 engineering,-and 505, Electric expenses?
14' A. No. The over-all projection of the trend presents a realistic reflection 15 of expected expenditures to these accounts for the future years.
T 16- Q. Please explain what major adjustments were- require'd for the other Steam 17 Power-Production accounts.
18 -A. The. balance of' the other accounts in Power Production required adjusting 19 '- before trending could begin. Probably the most significant adjustment was 20 _ related to major unit planned overhauls. Overhauls expenditures vary b'e tween years with the. level of overhaul activity, such as the number of 21.
22 unit overhauls, the size of-the generating units, and the work activity
'23 required to accomplish the overhaul work. As an example, 10 major unit 24 overhauls were accomplished in 1974, 4 in 1975, 8 in 1976,15 in 1977, and 25 14 in 1978. There are 7 major unit. overhauls planned for.1979, II in 1980, J26. and-7 In 1981. This includes overhauls f?" Steam, Other, and Nuclear
- 27. Production. :To develop-an estimating trend for normal operation and
-maintenance. activities, 11! was-necessary to remove the overhaul costs from
- 28 8-8 !
i l2-6 i'
Ronald V. Knapp 1; the recorded years before trending and add in the costs for overhauls 2 ' planned for 1979,1980, and 1981 as adjustments to the figures developed 3 by trending. Another major adjustment pertains to unforeseen maintenance 4- expense associated with overhaul expenditures. As previously discussed 5- above, trended estimates are based on rec.orded expenditures, less recorded 6f major overhaul expenditures, while future year adjustments for major unit 7 overhaul are based ~on field estimates, which do not include any amount for 8' repairs determined necessary at the time of overhaul accomplishment.
_9 : Analysis.of major unit overhauls historical budgeted versus actual expendi-
- 10) 'tures for the years'1976 through 1979 disclosed that unforeseen work II' averaged $522,400 per major unit . overhaul for this period. Based on a
- 12 . linear trend of the average overrun cost per major unit overhaul for the years'1976 through 1979, the unfores'een maintenance expenditures for the
~
- 13.
14 ' estimated years 1979, 1980, and CEI are $5,172,300-, $6,101,100, and
'15' :- $4,684,800, . respectively. As such, this estimate ><as allocated to accounts
~l6 506, 510F 511, 512, 513, and 514 based on a percentage of each account's 17 adjustment' for expenses associated with generating unit overhauls.
18' Account 502, Steam expenses, required two' adj ustments. The most
~
- 19) .significant was the' removal of air quality regulatory requirements costs
~
20.- . f rom '.the recorded' years 1974 1978 before trending and the inclusion of 21 these costs _in;the estimated years 1979-1981 as adjustments to the trended' 22 : figures. . Costs' for.. ai r'~quali ty moni toring studies , investigation, operation 23 .of equipment, etc., to comply with and/or contest regulatory agency require-mentsfand ordinances ah've varied in the recorded' years and are increasing
~
24 .
.~ 25 [ -In Se futurelyears due'to additional requir'ements. In_mid-1978',- the 26 South Coast Air Quality Management ' District Lpermit : renewal fees increased -
27 .significantly, and. additional. fees have beenLlevied for emissions.
4 28 ~ : Emission abatement orders 2008 and 2012 have been-received from the South
'8-9 12-5-797
, Ronald _V. Knapp 1 Coast Air Quality Management Oistrict and will require significant expen-
-2~ ditures to achieve compliance by September 1981. The following costs were 3-- removed from the recorded years: 1974 - $887,000, 1975 - $720,000, 1976 -
-4 $1,119,000, 1977 - $1,114,000, and 1978 - $1,533,000. The following costs I
-5~ were added to the estimated' years: 1979 was $3,340,000, 1980 - $3,788,000, 6- -.and 1981 - $3,598,000. Additional adjustments were made to the years 1974, 1 7- 1975, and 1976 to remove significant water chemical treatment costs which
'8 are no longer required at our Mohave Generating Station. '
9 Acr.ount 506, Miscellaneous steam power expenses, is mostly com-
~
.10 prised of Research and Oevelopment costs. These costs vary significantly l
11- from year to year based on programs' undertaken. The re fore , they were 12 removed.from the recorded years 1974-1978 before trending, and. estimated 13- amounts were added to the trended figures for future years 1979-1981 based L 14 . on current.. corporate Research and Development programs. In t'he recorded 15- years, $10,177,000 was removed from.1974, $2,280,000 from 1975, $2,137,000
- 16. from 1976, $1,862,000 from 1977, and $4,222,000 from 1978. To account for 17_ current corpora'te Research and Deve.lopment programs, $5,420,000 was added 18 to the 1979 figure developed by trending, 53,538,000 to 1980, and
.19 . . . $3,909,000 to 1981. - Another significant ~ adjustment to Account 506 relates
- 20- .to expendi tures for water- quali ty. monitoring studies, investigat ions ,
21 permits,-fees, etc.. to comply with and/or contest regulatory requirements 122 ~ related to' Steam Production'. ~These costs have varied in the recorded years x 23; 'and are projected to be significantly higher. in- the estimated years and, 124" - therefore, were removed. f rom the trend. .in 1975, $264,000 for water i25? - quality. control and mon 1toring was removed,L$457,000 in 1976, $335,000 In J26 ;1977,-and $7.40,000 in 1978. For. the-years 1979, 1980, and 1981, 27 ~$2,435,000,7 $1,770,000;and.$830,000l, respectively, was.added to the L28- :t' rended estimates to cover the cos'tsifor compliance.with current 4
8 - -
1 12-6-79,, ,
4 -
+ p ~ v-
1 l
Ronald V. Knapp 1 predictions of high activity in 1979-1981 to comply with the requirements 2 of Federal Water Quality Control Act 316.b., pertaining to the discharge 3 of cooling water into the ocean. In addition to these adjustments, other 4 adjustments were made to recorded and estimated years to cover expendi-
'S tures associated with generating unit overhauls, as previously discussed, 6 refurbishment of the Long Beach Generating Station Units 10 and 11, and 7 th'e Standards and Performance Study directed by the CPUC for Mohave and 8 Four Corners Generating Units.
9 Account 507, Rents, was neither indexed to 1978 monies nor 10 ' escalation applied as most Rents are firm contracts. Therefore, firm costs 11 were used for the future years 1979, 1980, and 1981.
- 12 . ' Account 510, Maintenance supervision and engineering. The major 13 adjustment to this account is associated with overhaul cost at various 14 generating stations - $31'9,000 -was removed in 1974, $153,000 in 1975,
)
15 -$315,000 in 1976, S713,000 in'1977, and $524,000 in 1978. For the future 16 ; years,'S588,000 was added'to 1979, $988,000 to 1980, and $495,000 to 1981. {
17 A small adju'stment was made to correct an accounting error in the years 18' -1977 and 1978. Monies were added to the future years' trend for 1980-1981
'19 In~the amount of $90,000 and $112,000, respectively, for the computerized
~ maintenance planning program. This wi11 be implemented for the purpose of
~
20 21- _ achieving a more over-all effective maintenance and improve generating 22 unit's'and equipment. reliability.
23 Account 511, Maintenance of structures. Adjustments were made -
24- to remove the cost ~of repairs to' a bridged . inactive coal storage pond in
-25l 1975, repal rs to - the --Iining of two water ponds in 1976,- and repai rs to the asphalt surfaces.in 1975, 1976, and 1978 4.c the Mohave Generating Station.
26
~
27 . Minor: adjustments were made to this account ' removing _ overhaul expendi tures
~28- lIn the recorded years and! adding overhaul costs to.the future' years.
11 l12-7-78 _
)
Ronald V. Knapp .
1 The cost for the refurbishment of Long Beach Generating Station Units 10 2 and 11 was removed from the years 1976, 1977, and 1978. In 1981, 3 $1,195,000 was added for the repair of the plant drainage system, including 4- asphalt surfaces and for the cleaning and repair of the linings of two 5 large water ponds at Mohave Generating Station.
6 Account 512, Maintenance of boiler plant, has significant adjust-7 ments for overhaul costs. The adjustments from the recorded years are 8 $2,492,000 in 1974, $2,223,000 in 1975, S4,539,000 in 1976, $9,046,000 in 9 1977, and $8,483,000 in 1978. Future year overhaul costs in the amount of 10 $4,721,000 were added to 1979, $5,799,000 in 1980, and $6,878,000 in 1981.
11 Also in 1981, significant maintenance expenditures amounting to $3,691,000 12 will be required at the Mohave Generating Station. This includes major 13 boiler plant equipment repairs.to improve capacity factors of coal plant 14 _. p rod uct i on . Some examples of the activities are; reheat tube replacement, 15 .
primary air ducts replacement, air preheater_ baskets, and super heater tube 16 replacement. it is necessary to replace boiler air preheater elements to 17- maintain thermal efficiencies, as well as preventing particulate fallout 18 due to existing fuel gases in-vartous generators. These expenditures vary
- 19 from year to year and, therefore, have been adjusted out of the recorded
'20 years. Expenditures for. 1979-1981 have been provided for in the future 21~ estimates. Air preheater heating elements replacement costs in the amount 22 of $906,000 were removed from recorded year- 1974,:$613,000 in 1975, 23 .$1,864,000 in 1976, $1,652,000 in 1977, $903,000 in 1978. Known future-24- year air preheater. element _ replacements. in the amount of $2,884,000 were 25 added to 1979, $1,548,000 to 1980, and $1,204,000 to 1981. These were the 261 major adjustments that were .made to Account 512. Other adjustments were 27 'made _ for the ref.Jrbishrr.ent .of Long Beach Generating Station Uni ts 10 and 28L 11 for the years 1977-1979, and costs for boiler plant OsM expenditures 8 12-7-79 L
1 Ronald V. Knapp l
1 in 1980 and 1981 in the amount of $6,939,000 and $1,900,000, respectively, l 2 to comply with emission abatement orders.
3 Part of the revenue received from contract energy sales to other 4 utilities is a cost factor for operation and maintenance. Therefore, that 5 part of the revenue received for contract energy scoes to other utilities 6 that relates to OEM costs was adjusted out of the recorded year expendi-7 tures. Half of these costs were adjusted out of Account 5'2 and the 8 other half out of Account 513 9 Again, in Account 513, Maintenance of electric plant, the most 10 significant adjustment relates to overhaul expenditures - $3,523,000 was 11 adjusted f rom the year 1974, $2,510,000 from 1975, $5,199,000 from 1976 12 $10,371,000 from 1977, and $11,301,000 from 1978. Future year estimated 13 overhaul costs in the amount of $8,264,000 were added to 1979, $8,048,000 14 to 1980, and $7,782,000 to 1981. Another significant adjustment was made 15 to this account for the removal of significant cost activities from the 16 recorde- ars that are considered to be non-routine type of maintenance 17 and the recurrence of same would not be expected each year. Some of 18 these maintenance activities are extensive cooling tower repairs, purchase 19 and replacement of steam turbine blading and diaphrams, and the purchase 20 of a high pressure steam turbine rotor. Considering the nature of these 21 activities, $916,000 was removed from the year 1974, $1,612,000 was 22 removed from the year 1976, $1,640,000 f rom 1977, and $1,922,000 f rom 1978.
23 Future year estimated cc>sts for these activities were added to the trend.
24 $4,480,000 was added to 1979, $2,449,000 to 1980, and $2,080,000 to 1981.
25 This amount includes $4,480,000 in 1979, $1,512,000 in 1980, and 26 $1,120,000 in 1981 for ccndenser .retubing requi red at Mohave Generating 27 Station. Another adjustment was made to this account for the refurbish-1 28 ment of Long Beach Generating Station Units 10 and 11. Part of the l
l 8-13 12-7-79
Ronald V. Knapp l
1 revenue received from contract energy sales to other utilities is a cost 3 factor ' for operation and maintenance. Therefore, that portion of the 3 revenue received for contract energy sales to other utilities that relates 4 to OSM costs was adjusted out of the recorded year expenditures. Half of
'5' these costs were adjusted out of Account 512 and the other half out of 6' Account 513 7 Account 514, Maintenance of miscellaneous steam plant, required 8 four adjustments - the most significant being adjusting of property damage 9 costs out of recorded years and adding the estimated property damage costs "10 .to the estimated years 1979, 1980, and 1981. Property damage costs have Lil varied sihnificantly'in the past, and trending of these costs did not 1125 appear to be logical. Therefore, the recorded expenditures were removed 13' ;in the recorded years 1974-1978, and the estimated amounts for property
- 14-
' damage'as determined by our Comptroller's Department were used for the
- 15 future year costs, 1979-1981. Rela ting tc property damage, $2,853,000 was l'6 - adjusted out In 1974~, $1,300,000.in 1975, si,048,000 in 1976, $3,646,000 17 in'1977, and $6,815,000 in'1978. The Comptroller's Department storm damage
- 18 estimate.for.1979 was $2,922,000, $3,127,000 for 1980, and $3,346,000 for 19- 1981. .These costs were added to the future years' estimate. ;
'20 .Q. Mr. Knapp, please comment on the significant adjustments that were required
.21 to develop' a trend ~ projection of expenditures for .0ther Power Generation
'22 L Production'for.the future years- 1979-1981.
23- A. The accounts Jin Other Power Generation Production did not require a great
.24 ' deal offadj ustments. The major adjustments to Other Power Generation
,;25! Production. accounts- revolved around any other production resources that
, 26 - : had 'been placed in service during -the December 31, 1976, through p Decembe r-- 28, ' 1978, . pe ri od . These added resources were the Long Beach' 128 Combined _ Cycle; Units 8 and:9, the Coolwater Combined Cycle Units 3 and 4 18-14
= ^
12-7-79:
Ronald V. Knapp 1 and the Yuma Axis Gas Turbine Peaker. The expenditures to operate these 2 new resource facilities are significant to the accounts for Other Power 3- Generation Production and are not represented in the recorded years.
4 Therefore, a reasonably accurate trend for the future estimated years 5 1979-1981.could not be developed until the expenditures relating to the 6 new f acilities were removed f rom the recorded years 1976, 1977, and 1978.
7 The estimated expenditures for the new facilities were then added to the 8- future years' trends 1979-1981 to provide realistic estimates. As i go 9 through Other Production by account, I will detail the adjustments relative 10 to the new facilities referred to.
11 In' Account 546, operating supervision and engineering, $15,000 12- .was removed from 1976, $105,000 from 1977, and $205,000 from 1978; and 13 S263,000 was added-to 1979, S279,000 to 1980, and $306,000 to 1981 for the 14 new Other Power Resource. facilities.
15 Again in Account 548, Generation expenses, the only adjustment
- 16 'was in the Long Beach, Cool Water, and Yuma Axis facilities, in 1977, 17- $556,000 was~ removed and $1,115,000 in 1978. In 1979, $1,389,000 was 18 added, $1,585,000 in 1980, and $1.770,000 in 1981.
19 Account- 549, Miscellaneous other power generation expenses, had -
20 two sdj ustments. One adjustment for the new facilities removed _S3,000
~
4!1 ~from the year 1976, S579,000 from'1977, and S886,000 from 1978. -in 1979, 22- S625,000.was added, S651,000 in 1980, and $596,000 in 1981. The other 23 . adj us tment is for Resear ch and Development. As an example, R&D comprised
'24- nearly 45% of the. total expenditures for this account in 1978. The pro-25 Jected expenditures for.the years 1979,1980, and 1981 will be more
- 26~ significant ~due to the current projects in various stages of Research and-
?27 Developnent for-other energy resources. The over-all level of R&D expendi-tures:has varied' annually and thus.were. removed from the recorded years, 28 4 . .
8-15
. l 12 79
-Ronald V. Kn pp I and the_ estimated costs of corporate R&D programs were added to the future l
2 years 1979-1981. For the recorded years, S375,000 was removed from 1974, ,
3 $448,000 from 1975, S317,000 from 1976, $539,000 from 1977, and $782,000 4 from 1978. Future corporate R&D programs were added to the estimated years 5 1979, 1980, 1981 - $1,950,000, S4,069,000 .d $3,940,000, respectively.
6 in Account 550, Rents, historic expenditures to this account 7 were neither indexed nor escalated as there was relatively little history
-8 and _because rents are contracted for firm amounts. Therefore, our pro-9 jected rents for the future years are stated in contracted amounts.
10' Account 551, Maintenance supervision and engineering, was again
-11 adjusted to remove the expenditures for new facilities f rom the recorded 12 years and provide for these facilities in the future years. These adjust-13 ments were the renoval of $78,000 from 1977 and $114,000 from 1978 and the 14 adding of $200,000 to 1979, $241,000 to 1980, and $253,000 to 1981. There 15 . was -a minor adjustment in this account for overhaut expenditures.
16 Account 552, Maintenance of structures, was adjusted only for 17: .the new Long Beach, Cool Water, and Yuma Axis facilities. The year 1977 18 was reduced $32,000 and 1978 by $207,000, and the estimated years were
_19 increased by $160,000 for 1979, $202,000 for 1980, and $222,000 for 1981.
20 Account 553, Maintenance of generating and electric plant, con-
'21 tained three types of adjustments. A new facilities adjustment was made (22 reducirig $427,000 from 1977 and $1,338,000 from 1978 and adding $1,553,000 23 in 1979, $1,594,000 in 1980, and $1,688,000 in 1981. In 1980, replacement 24 of four silencer stacks for the Mandalay Peaking Unit #3 is planned. The r
- 25. trended estimate does not reflect this major item of cost; therefore, 26 $838,000 was.added to the trended estimate for the year 1980. This account 27 Includes overhaul costs for peaking units and combined cycle units, and 128 thase overhaul costs have been' treated similar to those in Steam Production 8 12-7 Ronald U. Knapp
'I accounts. Therefore, the over-all costs relative to the heretofore men-2 'tloned new facilities were removed from the recorded years and added to 3 the estimated years. These adjustments were the renoval of S133,000 4 from 1977 and $512,000 from 1978.and adding of $30,000 to 1979 and 5 $124,000 to 1980.
- t. l6 Account 554, Maintenance of miscellaneous other power generation
~7 ' plant was adjusted for new facilities and for property damage. In regards
!. 8 to.the new facilities, the recorded costs were minimal, and no adjustmeats I
! -9 - were made. The future years were adjusted by increasing the 1979 trend lof b'y S45,000, 1980 by $54,000, and 1981 by S59,000.
11 Expenditures for property damage relating to Other Production r_ 12- have histor.ically~ been minimal due to the number and size of the Other i.
- 13_ . Production facilities. New Other Production facilities placed into
- 14- ' operation since 1976 are expected to-moderately impact property damage 15: expenditures. Is 1978, a significant property damage expenditure was 16' 2 incurred primarily due to a fire at-the Ellwood Energy Support Facility.
P
'17 - . This ' property damage expense amounted _ to 96% of the total 1978 expendi-
_ IS' 'tures to-this' account. .Therefore, trending' historical Property Damage.
~
19 'and escalating expenditures does'not provide a realistic projection of.
-20 'costsc Accordingly, expenditures in the recorded years- 1976, 19/7, and g 21 ~ ,1978 iwere ' removed , and estimated amounts determined by our. Comptroller's
-- 22 : Department were added :to- the estimated years 1979 through 1981 to more
~
t-23 accurately reflect.:our resource. requirements. These adjustments were:
p .24-u l$1^,000 removed in 1975,-SI,000'.in 1977, and $584,000 in 1978. 'The year 1
t 25- 1979 was:~1ncreased $25,000, 1980 by-$26,000, and 1981 by S28,000.
" 26 l :q.. Would you now, cover. Hydraulic Production?
- 27 . A.ULYes. Four accounts in. Hydraulic' Production -did not - requi re adj ustments as l28 there are'no' unusually'high or.Iow expenditures 1in the recorded-years or p . ._.
8 m , :12-7_-79
Ronald V. Knapp 1 anticipated in the future years. The over-all projection of costs using 2 the trend method appears satisfactory. These accounts are: 537, Hydraulic 3 expenses; 538, Electric expenses; 539, Miscellaneous hydraulic power l
l 4 generation expenses; and 536, water for power.
5 Q. Did you use the straight trending method for these accounts?
6 A. Yes.
7 Q. Please explain the adjustments for Hydraulic Production.
8 A. The adjustments in Hydraulic Production dif fer f rom the majority of Steam 9 and Nuclear as they do not relate to significant scheduled overhead costs.
10 Most of the adjustment in Hydraulic Production covers specific activities 11 that were either abnormally high in one year or low in another year that 12 had to be adjusted to normalize the recorded years. Future years' 13 estimates were increased to provide for significant planned items that 14 would not be accounted for by a straight trending method.
15 in Account 535, Operation supervision and engineering, the only 16 adjustnent made was to future year estimates 1979-1981. In 1979, two addi-17 tional control Station dispatcher positions were added to Bishop operations.
18 Therefore, the estimated years were adjusted to reflect the addition of 19 these two positions. As such, 1979 was increased $38,000; in 1980, 20 $46,000; in 1981, $50,000.
21 In Account 540, Rents, two adjustments were made. The recorded
' 22 . year 1975 also included the 1974 rental payments. Therefore, $75,000 was 23 adjusted out of 1975 into 1974. The other adjustment was to account for
- 24. timber ~ sales in 1976 of $53,000 and in 1978 of $14,000. To properly 25 reflect the 1976 and 1978 recorded expenditures, these years were increased 26 by' the amount of the timber sales to provide a more normal basis of 27 recorded expenditures and a -realistic trend for expected expenditures.
28 Account 541, Maintenance supervision and engineering, was 8-18 7 l
Ronald V. Knapp I adjusted to remove unusual expenditures in recorded years that were not 2 planned to be repeated in the future years - $51,000 was removed in 1974
^
3 and $41,000 in 1976 to cover the cost to prepare inundation maps as re-4 quired by the State of California, Office of Emergency Services. The year 5 ~ 1976 was also adjusted by removing $30,000 f rom the recorded costs for a 6' seismic stability study on Vermillion Dam to meet the requirements of the 7; California Division of Dam Safety. These adjustments to recorded figures
'8 helped to provide a realistic trend.
9 One adjustrent was made to Account 542, Maintenance of structures.
'10 The 1978 recorded expenditures were abnormally high for this activity.
-11 This was the result of extra maintenance performed to structures due to a 12- shif t f rom other work activities. The year 1978 being a high water year 13 prevented normal maintenance activities from being performed on dams, re-14 servoirs, etc. To normalize the effect of the above-average work
- 15 . activities'in this account, $50,000 was removed from the 1978 recorded
-16 costs. This normalization was required to provide a more accurate trend I 17' . for estimating. expenditures in future years 1979-1981.
-181 Account 543, Maintenance of reservoirs, dams, and waterways,
!!9 required several adjustments to normalize the recorded expenditures. In
-20 1976,.$118,000 was removed from the recorded costs'and $215,000 in 1977 21 These ' costs ' represent signi ficant repai r work that was pe rformed at Kaweah 22' 'No. 2 and at the' Rush Meadows Dam. These years were adjusted to more 23 .' . closely' reflect: normal maintenance expenditures in this account. Recorded
- 24) 1978 was'also.' increased $160,000. This was done to compensate for_a.below
'25' normal maintenance activity levelLin 1978 which was caused by an unusually 26- high' water; year. ..High water conditions, caused by heavy rain and snow,
~
~
27' : prevented normal maintenance-from being performed on activities in this account. ' Maintenance activities normally performed on equipment in this
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28 8-19 12-7 T
Ronald V Knapp i account were di rected to other work activitics that were not af fected by 2 the high water condition. Therefore, it was necessary to adjust 1978 to 3 reflect a more normal year's expenditure. The estimated 1979-1981 years 4 were adjusted to include significant planned maintenance activities for 5 which costs would not be provided in the trend method. The year 1979 was 6 increased $337,000 for repai rs to the Kaweah No. 2 canal lining and flumes, 7 repairs to Chinquapin and Camp 62 diversion pipeline repair intake ftruc-8 tures and grids at Big Creek No. 3, repair the gunite seals on Dams I and 9 2 at Huntington Lake, and coating the exterior of Kaweah No. I fiume. The 10 year 1980 was increased by $75,000 to provide for guniting the down-stream 11 face of Kern River No. 1 Intake Diversion Dam. The year 1981 was increased 12 by $125,000 for repair work for Kern River No. I intake.
13 Account 544, Maintenance of electric plant, also was adjusted to 14 account for specific maintenance activities in recorded years and to pro-15 via for specific maintenance activities in the future years. The amount 16' of $260,000 was removed from the 1974 recorded costs for the replacement 17 of. Big Creek No. 4 Unit 2 Generator Winding, $334,000 was removed in 1976 18 for replacement of Big Creek No. 4 Unit 1 Generator Winding, and the re-19 winding of Unit 3 at Kern River No. 1. The year 1977 was adjusted by 20 $215.000 for rebabbitting five main generator bearings and purchase of 21 replacement unit windings at Big Creek.No. 3 As a result of 1978 being 22 a high water year, caused by heavy rains and snow, normal maintenance work 23 . could not. be accomplished during the year on this account. To compensate
- 24. for this, $40,000 was added to this account to normalize the'1978 expendi- <
' 25- tures. Offsetting this . increase, another adjustment decreasing this 26; account by $157,000 was made. ' This adjustment was due to a significant 27 . maintenance work item involving the installation of No. 2 Unit winding at
.The net effect of these two adjustments was a net credit 28- l Big Creek 3 8-20
~12-7-79
Ronald U. Ctnapp I adjustment of $l17,000 to 1978. The estimated years 1979 and 1980 were 2 also adjusted for significant planned maintenance items. The year 1979
~3 was increased by $282,000 for installation of Units Nos. I and 3 generator 4 -windings at Big Creek 3, and 1980 was increased S173,000 for Unit No. 2
-5 generator winding installation at Big Creek 3 6'- Account 545, Maintenance of miscellaneous hydraulic plant, had
.7 two adjustments. The recorded 1974 year was reduced $102,000, which was 8 the cost to perform maintenance work on hydro cranes due to OSHA require-9 ments. The other adjustment was for property damage. The over-all level 10 , of property damage expenditures has varied yearly; thus property damage 111 costs were not trended. Recorded property damage costs were removed from 12- the recorded years, and estimates of property damage, as determined by our 13' T Comptroller's Department, were used for the future years 1979-1981.
'14 Q
.. Mr.'Knapp, what adjustments were required in the Nuclear Production
- 15' accounts 7
- 16 ~- A .' The most 'significant adjustments -involved overhaul and refueling costs.
17 ' The same meth'odology was used to adjust for these costs as previously
'l8 -explained in Steam Production. Other adjustments were made to normalize 19 the' recorded years 1974-1978,' and adjustments were made to the estimated
.20 years 1979-1981' figures developed by trending to include costs for signi-21 .ficant. activities that would.not be.provided for in.the trending procedure.
22 Account- 517,' operation -supervision and engineering', was adjusted 23' ~1n 1976 to . remove S5,000 f rom' the recorded year for overhaul- and refueling
. costs. -Overhaul costs'in the other' recorded years and future years in.this
~
24 25 . account were' considered minimal, and no' further adjustments were made.
~26 No adjustments were-made ;to Account 519, Coolants and water, and
~
Account ' 523, Electric expenses.
~
27-- -
28 _ . Account 520,' Steam expenses , was _ adjusted for overhaul and 8-21
- 12-7-79'
Ronald V. Knapp 1 refueling costs. The year 1975 was reduced $157,000, 1976 by $258,000, 2 and 1978 by $171,000. The year 1980 was increased by S409,000 and 1981 3 by $419,000.
4 Account 524, Miscellaneous nuclear power expenses, was adjusted 5 for overhaul and refueling costs and for Research and Development. The 6 years 1975, 1976, and 1978 were reduced S37,000, $73,000, and $42,000 7 respectively, for overhaul and refueling costs, and 1980 was increased 8 $136,000 and 1981 by $75,000. R&D was adjusted the same as in Other 9 Production accounts. Recorded R&D costs were removed from the trend 10 period and added to the future year trend in the amounts predicted for 11 future R&D corporate programs. The estimated years 1979, 1980, and 1981 12 were increased by $25,000, $100,000, and $100,000, respectively, for costs 13 relating to the~ Institute of Nuclear Power Operations (INP0). S. nc.e the 14 Pennsylvania accident, the nuclear indistry has established the Institute l 15 of Nuclear Power Operations (INPO), a privately funded organization. The 16 purpose of INP0 is to set criteria and monitor the industry's safety t 17 related goals. Also, INP0 will provide enhanced training for reactor 18- operators and bench marks for excellence in nuclear power operations 19 throughout the industry. Also, adj ustments were made to the es timated 20 years 1979 thru 1981 for costs relating to Senate Bill 1183, Chapter 956, 21 pertaining to appropriations for state governme.ntal agencies to declare 22 and investigate emergencies and to establish plans for responding to 23 emergencies. .For the year 1979, $25,000 was provided; 1980, $250,000; and 24 1981, $250,000.
25 Account 525, Rents, was not trended. Fi rm contract costs were 26' used in the estimated years 1979-1981.
'27 Account 528,'naintenance. supervision and engineering, was F .28 adjusted for overhaul'and refueling costs. The year 1975 was reduced
'12-7-79
Ronald V. Knapp 1 $83,000; 1976, $163,000; 1977, $36,000; and 1978, $140,000. The future 2 years 1980 and 1981 were increased $86,000 and $98,000, respectively, for 3 overhaul and refueling costs.
4 Account 529, Maintenance of structures, had only minimal adjust-5 ments to 1975 and 1976 for overhaul costs, $11,000 in 1975, and $8,000 in 6 1976.
7 Account 530, Maintenance of reactor plant equipment, was adjusted 8 for overhaul and refueling costs plus an accounting correction in 1975 9 amounting to $484,000. The year 1975 was reduced $568,000, 1976 by 10 $632,000, 1977 by $1,297,000, and 1978 by $1,118,000 for overhaul and 11 fueling costs. Costs were also provided in 1979, 1980, and 1981 in the 12 amount of $966,000, $1,572,000, and $339,000, respectively, for overhaul 13 and refueling activities.
14 Account 531, Maintenance of electric plant, was adjusted for 15 overhaul and refueling costs. Overhaul and refueling adjustments were 16 made by reducing 1975 by $706,000, 1976 by $143,000, 1977 by $100,000, and 17 1978 by $251,000. The 1979 and 1980 trend was increased by $11,000 and 18 $734,000, respectively, and 1981, $523,000. Also, the recorded year 1974 19 was adjusted by $484,000 for an accounting correction, and in 1975, a non-20 routine expense for the retubing of the main cooling water condenser was 21 removed f rom the respective recorded year.
22 Account 532, Maintenance of miscellaneous nuclear plant, was 23 adjusted for o<erhauls and refueling and for property damage. Relative to 24- the overhaul and refueling costs, 1975 was reduced by $22,000, 1976 by 25 $18,000, 1977 by $1,000, and 1978 by $15,000. In 1980, $15,000 was added 26 to_the trend estimate and $14,000 in 1981. Trending historical property 27 damage costs and then escalating does not provide a realistic trend.
28' Accordingly, recorded property damage expenditures were removed from the 29 trending base years, and the estimates determined by our comptroller's 8-23 12-7-79
Ronald V. Knapp 1 Department were used to more accurately reflect the resource requirements 2 in the future years.
3 Q. Does that conclude your adjustments to Nuclear accounts?
4 A. .Yes.
5 Q. Mr.- Knapp, do you believe the trending methodology, with adjustments, that 6 you used to determine the operating and maintenance costs for 1979, 1980, 7 and 1981 to be a realistic projection of the future resource requirements 8 for Power Production work activities? .
9 A. Yes. : 1 - do. It is my judgment.that the trending methodology used provides 10 a projection of the future resource requirements for Power Production work 11 activities for- the period under study, which likely is conservative and
- 12 1 on the low side.
13 It is my opinion that the level of maintenance for existing 14 facilities will increase slightly above the trended figures during the 151 next few years. This' opinion is based on two factors: (1) the increasing
- 16 -aoe of our facIIIties which requires increased maintenance to continue the
- 17. ' reliability of the equipment at an acceptable level, and (2) the impact on il8 ~ :whichlvhe - -reduction in capacity margins will: have an increasing 19 '. facilities utilization and the attendant increase in maintenance. This 120. later' factor is anticipated to be-most noticeable during the next three 21~ years 'since oniy one small. unit of capacity increase is planned between now L22 Dand 1981. -In the . absence of specific data to project these factors, how-
! . 23: -ever, the trending method used appears to provide the most realistic
~
24' approach ~at this time.
25' Q. . insofar as the' material in Chapter: 8 Is of a factual nature, do you believe 26 ~it to be-accurate?'
1
- 27! : A.: Yes,.l.do.
, p28 ;-Q. ;lnsofar, as ~ the. materia'l?in Chapter 8 represents opinion, does It represent
, :29 byou r. best ?J udgment?
130' Al Yes, Lit does!
- L
- .8-24
.12-7-79
SOUTHERN CALIFORNIA EDISON COMPANY Prepared Testimony of Ronald V. Knapp (Exhibi t No. (SCE-2) , Chapter 9)
I Q. Mr. Knapp, you previously indicated that you are sponsoring Chapter 9 of 2 Exhibit No. (SCE-2) . Is that correct?
3 A. Yes.
4 Q. Briefly, what does this chapter cover?
5 A. This chapter covers the expenses for operating and maintaining the Company's 6 transmission system. These costs include labor, material, and other expenses 7 for transmission substations, overhea. lines, underground transmission 8 . facilities, roads and rights of way, and miscellaneous transmission plant; 9 load dispatching; and transmission of electricity by others in connection 10 .with existing contractual agreements.
11.-Q. How were the figures developed for 1979, 1980, and 19817 12 A. Separate. estimates were prepared for each of the accounts in the transmission 13 expense g'roup for the years 1979, 1980, and 1981. Escalations were included 14 .for labor and non-labor expenses. Labor costs have been escalated 7% and 15 non-labor costs have been escalated 3%.
Q. -In your testimony for Chapter 8, production, you stated how the escalation
~
16 17 factors were determined and the methodology used to determine the cost 18- -estimates-~for power production. Were the same factors and methods used to
-19 prepare,the transmission' expense estimates?
20, A. -Yes.
- 21 ' Q. To develop the operation and maintenance cost estimates, I assume It'was 22- : necessary to make some-adjustment to the recorded years to develop ~a useful 1 23 trend by adjusting out unusual- conditions;that would distort the future year
. . 9-1
, .'8-17-79 w - -_ .w - _- . . -_ _- - _ _ _ - _ - __ - _ - _ _ - - _ - _ _ _ _ _ _ - _ -
_ _ _ . _ . . _. ~ _ . _ _ _ . _ . _ ._. . _ _ - - . . - _ _
Ronald V. Knapp i Q. cost estimates.
2 A. Yes, in some accounts where there were unusually high or low expenditures 3 that would affect the recorded years usefulness for trending purposes.
4' Q. Was it necessary to make adjustment to the future year cost trends?
. 5 A. Yes, in four accounts only. This was necessary to provide for known 6 significant activities for which costs would not be provided for by 7 trending alone.
8 q. What accounts did not require adjustments?
9 A. Account 560 - Operation supervision and engineering.
10 Account 562 - Operation station expenses.
11 Account 563 - Operation overhead line expense.
12 Account 564 - Operation underground line expense. I 13 Account 568 - Maintenance supervision and engineering.
14 Account 569 - Maintenance of structures.
15' Q. Were there any Transmission accounts that were not trended?
16 A. Yes, one. Account 573 - Maintenance of miscellaneous transmission plant.
- 17 A significant item of cost in this account is property damage. For 18 example, in 1978, property damage comprised 90% of the total expenditures 19 In this account. Property damage expenditures vary' yearly. Trending 20 ' historical property damage and escalating expenditures does not provide
- 21 L a realistic projection of costs. Therefore, the estimate determined by
- 22. our Comptroller's Department,. was used . to nore. accurately reflect our 23 ' resource-requirements in the estimated years.
24 Q. Please identify the adjustments you did make to transmission accounts.
25 A. Account 561 - operation load dispatching - 1978, $590,000 in costs 26 associated with the Digital Dispatch Security Monitoring System (DDSMS)
- 27
- project were transferred to this account from a plant general work order.
This cost represents indirect costs that were retained in the work order
~
. 28 9-2 7-30-79
, - .- . . . - - ~ . . . - , . ..- - __ ., - -.
l Ronald V. Knapp 1 until closing. This one time cost amounted to 28% of the total costs ,
2 charged to this account, and was removed f rom the trend period to reflect 3 a more accurate resource requireraent for estimated years.
4 Account 565 - operation transmission of electricity by others.
5 in 1978, this account included extraordinary storm damage costs for the 6 Pacific Intertie System in the amount of $929,000. This charge was not 7 reflective of a normal year. Therefore, $929,000 was removed f rom the 8 recorded costs for 1978 to trend a more accurate future year's expense.
9 Account 566 - Operation miscellaneous transmission expenses. A 10 significant item of cost in this account is Research & Development (R&D).
11 For example in 1978, R&D comprised over 33% of the total expenditures in 12 this account. The overall level in R&D expenditures has varied yearly, 13 thus, R&D costs were not trended. Projections for R&D are made to the 14 account, based on the current Corporate R&D programs. Recorded R&D 15 expenditures were removed from the recorded years and estimated R&D 16 expenditures were added for the years 1979 through 1981. Other costs in 17 this account were trended.
18 Account 567 - operation rents. In 1977, the Digital Dispatch 19 Security Monitoring System (DDSMS) project was being developed, which 20 provided greater than normal expenditures for the recorded years 1977 and 21 1978, amounting to $135,000 and $1,035,000 respectively. However, firm 22 rental costs for the future years of this project are $1,044,000 per year.
23 _The DDSMS costs were removed from the trend base period 1977 and i978, and 24 1added 'to the respective years 1979 through 1981. Monles in this account 25 were not indexed to 1978 dollars, as most rental costs are contracted for 26 -firm amounts.
27 Account'570 - Maintenance of station equipment. In recorded years-
~28 1976 and 1977, significant expenditures were made on 500 kV transformers, 9-3 7-30-79
l Ronald V. Kn:pp 1 500 kV series capacitors, and 220 kV power circuit breakers. These non-2 routine significant expenditures resulted in greater than normal expendi-3 tures and were removed from the recorded period to reflect an accurate 4 future year trend. A totcl of $750,000 was added to the future year trend 5 for 1979 to provide for $645,000 for repairs at the Sylmar 500 kV converter 6 station and $105,900 for 115 kV power circuit breaker repairs. The above 7 two items are the only known significant one-time items for the future 8 years 1979 through 1980.
9 Account 571 - Maintenance of overhead lines. 1978 recorded Labor 10 was abnormally low due to 1978 being a high storm damage year. 1978 Labor 11 was adj usted by $640,000 to normalize the effects of the 1978 storm damage 12 and to more accurately reflect our resource requirement in the estimated 13 years.
14 Account 572 - Maintenance of underground lines. In 1975, this 15 account was credited with a $46,862 material transfer from underground 16 maintenance to the plant transmission spare parts account. Account 572 17 was adjusted by adding $47,000 to the recorded amounts in 1975, to reflect 18 the actual maintenance expense. 1974 was credited for $17,000 to remove 19 the cost of underground material purchased in that year, which was trans-20 ferred out in 1975 21 q. Mr. Knapo, as the estimates and material in Chapter 9 was based on a 22 trending methodology, do you believe it to be correct?
23 A. I believe the trend estimates reflect a realistic projection of expected
-24 expenditures.
25 Q. Insofar as it represents opinion, does it represent your best Judgment? ,
l 26 A. Yes, it does.
27 Q. Does this conclude your prepared testimony?
28 A. Yes,-it does. j l
9-4 8-17-79
SOUTHERN CALIFORNIA EDISON COMPANY Prepared Testimony of Alan J. Walker Exhibit No. (SCE-2) , Chapters 10 and 11 1 Q. Will you please state your name and address for the record?
2 ' A. My name is Alan J. Valker. My business address is 2244 Walnut Grove
-3 Avenue, Rosemead, California.
4 Q. What is your position with the Southern California Edison Company?
5 A. l' am Manager of Customer Service Administration in the Customer Service
'6- Depa r t ment . -
7 Q. Please refer to Exhibit No. -(SCE-3) , entitled " Qualifications of 8 Witnesses". Directing your attention to the page entitled " Qualifications 9 of Alan J. Walker", does that portion of the exhibi t accurately set forth 10 your background, training, and experience?
11 A. Yes, it does.
12 Q. Please explain _tho activities carried on by the Customer Service Depart-
-13 ment and your responsibility thereof.
14 A. The Customer Service Department is responsible-for planning, construction, 15 operation, and maintenance of the e lectrical distribution system; responding
'16 to andl resolving customer inquiries and-requests; performing meter reading, 17 customer. service, and' field collection activities; and interfacing with 18 'the public, the community, and:our customers.
,19 The department is divided into five divisions, each headed by a 20- Division.Vice President or Division Manager; all' reporting to the Vice
-21 President . Customer Service Department. To assist the department 5.' I c e
<22 President and these Division Vice Presidents and Division Managers,_l. head
-23_ fa staff? organization responsible.for developing standards and procedures
,8-20-79 of;;_;-
=
. Al an J . Wa l ke r I in the areas of departmental budgeting and planning, administrative services, 2 regulatory activities, customer accounting, and the development and mainte-3 nance of customer information systems. This staff is responsible also for 4 the interrelationship with corporate staf fs and Customer Service Department 5 line organizations oy providing assistance and support in implementing and 6 administering those standards and procedures.
7 Q. Mr. Walker, are you testifying with respect to Chapters 10 and 11 in 8 Exhibit No. (SCE-2) ?
9 . . A. Yes,.I am.
10 Q. Was the material in those chapters prepared by you or under your super-Il vision?
12 A. The estimates, based on recorded expenditures in the years 1975, 1976, 13 1977, and 1978 were prepared under my direction. The adjustments, both 14 .to recorded expenditures and to future years 1979, 1980, and 1981 were 15 prepared under my direction from information supplied by persons with !
.16 ' expertise' in the various associated fields.
17 Q. .What do those. chapters coved 18 'A. Chapter 10 covers Distribution Expenses, and Chapter 11 covers Customer 19 -Accounts Expenses.
Have the costs associated with the distribution substations been included 20 Q.
'21 -in Table 10-A?
22 A. Yes, they-have. The costs shown in Table 10-A include distribution costs-
- 23) . incurred byLthe Power Supply' Department. A portion of the Power Supply ,
~24 Department'sJoverhead costs is. included in Accounts 580 and 590.
25- _ Accounts 582 and 592 are co:nprised entirely of distribution substation j
'26 ~ expenses under. the Power Supply Department.except for a minor- charge in
.27; ' Account 592 for Catalina operations. A portion of Power Supply Department
'21! : operation and maintenance expenses'is inclu'ded in most of the other
~ ,8-20-79 ;10/11-2.
. _ _ +
Alan J. Walker j 1 distribution accounts. This has been done to conform to the require-2 ments of the Uniform System of Accounts.
3 Q. Have costs associated with a,y other departments been included in 4 -Table 10-A7 5 A. Yes, they have. Costs from the Right of Way and Land, Engineering and i 6 Construction, Material Services, and Comptroller's Departments are in-7: cluded in the distribution accounts as well as Data Processing costs 8 in Customer Accounts Expenses, Chapter 11.
9 Q. Are there fluctuations in the level of distribution expense in some 10 accounts that warrant specific comment?
11 A. Yes. Fluctuations normally can be expected to occur from year to year 12 depending upon circumstances such as weather, new construction demands, 13 major projects, etc. In the recorded costs in 1974 and 1975, there is one 14 factor which caused considerable rearrangement of our recorded expenses.
15 As Mr. Hunt testified in our last general rate case Application 16 No. 57602, (1979 test year), the-Customer Service Department 17 initiated a new function accounting system on January 1, 1975, which 18 was. designed to identify origins by establishing area of responsibility 19 (AOR) location numbers. The combination of location number wi th an 20 activity (function number) now provides us with a far better identifi-21 cation of expenses, as well as making it possible to identify and more 22 properly translate functional-expenses to the Federal Energy Regulatory i 23 Commission's Uniform System of Accounts. This means that some costs, 24 formerly treated as overhead, could now be identified as direct 25 expense, and overhead expenses formerly recorded in one of our clear -
26 'Ing accounts were found to be more properly assigned to the other.
27 secause of this rearrangement of recorded expenses, it was 28- felt that the most accurate forecasting of future expense ustimates could l
10/l1-3
.12-7-79 o
-Alan J'. Walker l l
1 be'made using the years 1975 through 1978 as a basis, and not including i 2 the year-1974.
3 Q. Do you have comments concerning the fluctuations in the level of recorded 4 distribution expense or future estimates in specific accounts?
5 A. Y e s '. As I said before, variations in the level of expense can be expected 6 as a normal occurrence la any account due to factors such as new construc-
'7 tion demands, weather, shi f ts in customer priori ties, etc. However, new 8 projects and programs, changes in emphasis on these programs. external '
9 influences, and other unusual circumstances also combine to change the
'10 . level of expendi tures in any ' particular account from year to year.
11 Q. Please explain the more signi ficant of these influences, for example, 12 .' Account 583.shows qui te variable expenses from 1976 to 1978. How do you ,
.13 explain this irregular pattern?
~ 14 ' A. Among the items = included in this account, which covers overhead line
-15 expenses, the ' provision for uncollectible damage claims is the greatest
'161 factor contributing to these variations. In this area, 1977 and 1378 17 * .were above-average _ years.
- 18. Another major. impact on expenses in 1977, 1978, and future 19 years is the Distribution Circuit Management (DCM) Program. This is a 20 conservation'.and load management program endorsed by the Commission and ,
21' testified to in Application No. 57602,.which accounts for $1.2 million.
. 22- in 1977 and 1978. .An additional $525,000' is estimated to te spen.t
~
23- on thi s program .in - the years -1979,1980, a'nd.1981. ,
. '24 . : Q. ~Since'DCM'is estimated at a lower level of expenditure in future years,
- 25 - why does 'the level of Account-583 continue (nto 1979 to .19817 26 'A. . As,a continuation of: our conservation efforts.-in conjunction wi th the
? 27. '. :DCM Program,' an additional program, Conservation ' Voltage Reduction (CVR), '
28 wasLdeveloped -and. mandated' by ( the Commi ss ion.~ This ef fort. is estimated 10/11-4
- 12-tc-74 l ./
Alan J. Walker 1 at $1.1 million total for those three years.
2 Q. Are the figures you have quoted,the total costs of these two programs?
3 A. No. An additional $19 million must be added to DCM and $3.1 million 4 to the CVR Program in capital expenditures for the years 1978 through 5 1 81 in order to view the total impact of these programs during this 6 period. The capital expenditures under the DCM Program represent the 7 funds necessary to maintain the existing program and to further reduce 8 system energy losses. Under the CVR Program, each individual location 9 will undergo a cost-to-benefit analysis prior to capital expenditure at 10 that location. -
11 Q. Expenses in Account 584 drop in 1978, then rise considerably in 1979 12 Why is' this?
13 A. This is due mostly to the cost of patrolling and inspecting underground 14 facilities in this account which covers underground line expenses. We 15 experienced one of the most severe storm years in Company history during 16 1978. The large commitment of personnel to repairing storm damage lef t much 17 less time available for the routine inspection of these facilities. Esti-18 mates for 1979 to 1981 include a resumption of normal operations in this area.
19 Q. If f uture ' years are estimated at " normal operations", aren' t the levels 20 estimated considerably below the average rate of escalation plus projected 21 growth?
- 22. A. Yes. We forecast growth of underground customers at approximately 10% per
'231 . year.and average escalation of combined labor and other expenses at approxi-24' mately 8% per year. - Therefore, average escalation plus growth in the under-25- ground segment would be approximately 18% per year. However, we are 26: estimating expenses to increase from 1979 to 1981 at an average of only 8.8%
.27 per year. Our management'Is fully committed to the development and imple-
-28 mentation-of' productivity improvements to make this possible.
12-20-.79 10/11 -
Alen J. Valker I Q. Do any other accounts in Chapters 10 and 11 contain similar commitments 2 to productivity improvement?
3 A. Yes. Most other accounts include some elements of productivity improvement, 4 but this is also specifically quantified in Accounts 593, 594, 902, and 5 903 In each of these areas, as well as many others, steps are being 6 taken to increase our productivity in an effort to hold down costs.
7 Q. Your estimates for 1979 to 1981 in Account 585 exhibit significant in-8 creases from previous levels. Why?
9 A. This account, which covers the operation of street light and signal systems, 10 and primarily includes our group replacement of street light lamps on a 11 periodic basis, now contains a major conservation program. This effort, 12 the conversion of mercury vapor and incandescent street lights to high 13 pressure sodium vapor lamps, a more ef ficient light source, is in compli-14 ance with the Commission's 011-43 which mandates this type of conversion 15 program.
16 Our estimates for this portion of the program are $1.4 million 17 in 1979, S3.5 million in 1980, and $3.8 million in 1981. To this should 18 be added the capital expenditure estimates of $2.4 million in 1979 S4.5 19 million in 1980, and $4.9 million in 1981. Thus, the expense and capital 20 expenditures of this conversion program, over-all for the years 1979 21 through 1981, comes to a total of ove.r $20 million and the five year 22 program (1979-1984) to over $45 million.
23 Q. In Account 587, Customer i nstallation Expenses, recorded expenditures decrease 24 from 1976 to 1978, and yet you project an increasing estimate from 1979 to 25 1981. What is the reason for this?
26 A. During the recorded years, we increased the charge for appliance repair i .1 27 an effort to make this program self-supporting. This resulted in a large 28' drop in calls for repair service, but a lesser ' decrease 'in charges r sceived, 12-15-79 10/11-6
Alan J. Walher 1 which reduced our net deficit for the overall program. We are project-2 Ing the volume of service calls to grow slightly in future years, raising 3 the net cost. In addition, hydraulic test activities were transferred to 4 Account 908 in 1978, which further reduced future years' estimated expen-5 ditures to Account 587.
a 6 The cost of other activities included in this account, such as 7 the servicing of customer Installations, handling billing inquiries, and 8 investigating' customer complaints is expected to increase in future years 9_ due to customer growth and escalation. However, i t should be noted that 10 the increases average only approximately 7% per year, which is less than 11 combined growth and escalation averages which are over 11%.
12 Q. Why does Account 588, Miscellaneous Distribution Expenses, show a large 13 ine.rease in 1978, and again in 1979, but then decrease in 1980?
14 A.. The most significant items of expense contributing to this are the Auto-15 mated Mapping. Project, which was initiated in 1978, and training for the 16 Field Accounting Program. The Automated Happing Project was established
~17 to convert, and subsequently maintain, in excess of 70,000 facili yt 18- ' inventory maps from. paper copies to a digital computer file, through 19 computer-aided draf ting equipment. When the conversion effort is con-
~
- 20. ciuded in approximately 1986, the costs of maintaining and reproducing 21' inventory maps will be considerably reduced.
'22 The second Impact is training for the Field Accounting Program, 23' which will be discussed later. The training costs are' estimated at $970,000 24- ifor'1979 In 1980, ' training .oxpenses . return to a lower level, ' causing the 25 '1980' decrease In this account.
26' Q. Althou'gh the dollar amounts are not large, the percent of increase in 12 7 Account 591?-for:1977 is'significant, but the increase in 1979 is unusually 28- smal l .- Why-is'that?
.12-15-79 10/11-7'
l
-Alan J. Walker 1 i
1 A. The years 1977 and 1978 contain greater-than-normal expenditures due to 2 - two remodeling projects in this account, which covers maintenance of 3 structures. In 1977, this was remodeling for Load Management and the ;
4 Customer information System. The 1978 expenses include the rearrangement 5 of facilities in the Eastern Division to accommodate Customer Telephone 6 Representatives and' relocate other departments. These expenses return to 7 normal'In 1979 and future years.
8 ..q. Again, although the dollar totals are relatively small, the percent of
'9 increase in Account 597, Maintenance of Meters, in 1977 was approximately 10 34%. What caused this?
11- A. ;This was primarily due to two factors. First, the Commission requirements 12 on time-of-use metering and load research caused significant increases in ;
13 ' expenditures during 1977 and future years. Also, as testified in Applie.a-
' 14 ' tion No. 57602,. purchases of heavy duty locking meter rings were accelerated r
, 35- in 1976 and even.more in 1977 and 1978 in an attempt to control losses due .,
16 .to unauthorized-use and theft of energy.
17 Q. . Account:598 shows widely varying expenditures, especially high in 1978.
-18. Why 'does . this occur, and how are *,he forecasts developed?
19 JA. Storm damage and amounts accrued for property damage self insurance of 20 ' distribution plant make.up almost the entire amount of Account 598.
21 1.evels..of expenditures change considerably due to the severity of storms 22 -. en' countered. ' As 'l mentioned earlier,- 1978 was a particularly harsh storm ,
> 23! year, and expenses rose accordingly. In order to levelize these high and
,24 . low years 'and fai rly -compensate for both, we based our forecast on a five-year
'25, average of actual losses from 1974 to 1978, adjusted to 1978 cost levels.
26l ': Future years were then. escalated appropriately for each year.
~
j2 7j Q. fMr.- Wal'ker, let's turn to' Customer Accour.ts. Expenses , Chapter- 11.
+ 28 3 :In the years 1976 to 1979, the' average annual Increase In Account-902,
~
c12-15-79 -
- 10/ I'l-81
l Alan J . Vo lker i
I Meter Reading Expenses, is approximately 11%; but future years' 2 increases are considerably less. Why? I l 3 A. Actually, the 11% average increase per year corresponds favorably 4 with the average escalation of 8% and customer growth rate of 3%.
5 However, as I mentioned previously, this is one of the accounts where t 6 we have established a specific commitment to productivity improvement.
i 7 Therefore, we are reducing the funds which have been requested by 8 straight 1Ine trending by 3% in 1980 and by 5% in 1981. I think this is a 9 concrete example of our determination to slow down the rise of costs in 10 the future. -
l 11 Q. The costs in Account 903, Customer Records and Collection Expenses, have l
12 risen more rapidly from 1976 to 1979 than they are projected to do in 13 1980 and 1981. Pleas
- explain.
I4 A. Expenses associated wi th the development, implementatlon, and maintenance 15- of the Customer Information System caused heavy increases in 1977, 1978, 16 and 1979 Although the development of future phases of CIS will require l
17 ongoing commitment of funds, in latte:- 1979 and 1980, less expensive 18 ' equipment and terminals are replacing the older, costlier units which 19 - will cause a significant reduction in costs for 1980 and 1981.
20 Offsetting much of these savings, though, are the increased 21 costs of preparing customer bills in 1979, 1980, and 1981 due to required 22 -rate structure changes. This includes the development costs, the intricacy 23 of the newer rate structures which require more data processing time to~
24 compute, and the~ new expanded bill format which takes longer to print.
25 Also, customer growth during this period adds to the expense.
26 Q. Then, how do you estimate an average annual increase of only 5.9%?
27 A. Our stated _ productivity ' improvement goals, which cover reductions in
'28 costs f rom the adjusted historical trend line, are over $600,000 in
._12-15-79; 'l0/11-9:
Alcn J. Walk 2r
! 1980 and almost $1 million in 1981. This makes it possible to help 2 reduce the rise in our cost of operation.
3 Q. In Ac :ount 904, Uncollectible Accounts, there is a significant increase 4 in 1979 and future years. How are these estimates prepared?
5 A. A five year average of the net writeof f as a percent of base revenue was 6 calculated. This average writeoff percent was then applied to the estimate 7 of base revenue, as reflected in Chapter 7, for the years 1979, 1980,and 1981.
8 Q. Now, Mr. Walker, Accounts 580, 590, and 901, Operation Supervision and 9 Engineering. Maintenance Supervision and Engineering, and Supervision of 10 Customer Accounts Expenses show a similar jump in 1979 wi th much lesser 11 increases in 1980 and 1981. What is the reason for this pattern?
12 A. These accounts include not only the cost of supervision but also various 13 expenses associated with department, division, ano district staffs and 14 support groups; lost time due to inclement weather; preparation and 15 processing of work orders; and engineering and service planning. They 16 also include the cost of certain programs and projects of general benefit 17 to more than one expense account, or to expense as well as capital 18 expenditures. The majority of these costs are distributed, through 19 clearing accounts, to expense Accounts 580, 590, and 901 and work orders 20 on the basis of direct labor charges.
21 The years 1977.and 1978 were lowered considerably from 1976 22 levels by the department staff reduction. Another influence on the less-23 than-normal expenditures in 1978 was the heavy storms. Since direct 24 labor charges to storm functions and work orders were extremely high, 25 more of the allocated costs which would have gone to Accounts 580, 590, 26 and 901 were charged to capital expenditures a s the storn damage 27 reserve. This held down 1979 allocatecas to Accounts 580, 590, and 901.
28 Additional expenses which will tend to raise allocations to 15-79 10/11-10
Alan J. Walker l
l 1 these accounts in the years 1979 through 1981 include unusually high 2 costs of lost time due to inclement weather in 1979, the Field Account-3 Ing Program, and the new Material Management. System.
4 The Field Accounting Program is a system to simpli fy, and ,
5 provide direct input through local computer terminals, the information 6 for accounting and timekeeping on construction crews. This program, 7 after implementation, will reduce field accounting and clerical costs.
8 The new Material Management System, through its associated 9_ computer input terminals, provides on-line access to material information 10 and transactions which will reduce material stockouts, enhance material 11 forecasting, and also reduce field accounting and clerical costs.
12 Q. Mr. Walker, insof ar as the material in Chapters 10 and 11 is of a factual I3 nature, do you believe it to be accurate?
u 14 A. Yes, I do.
15 . Q. Insofar as it represents opinion, does it represent your best judgment?
16 A. . Yes, i t does.
>17. Q. Does this conclude your prepared testimony?
18 A. Yes, it does.
12-15-791 10/11-11 t-
SOUTHERN CALIFORNI A EDISON COMPANY Prepared Test imony of Edward A. Myers , J r.
Exhibit No. (SCE-2) , Chapters 12 and 13 (Part)
Exhibits Nos. (EAM-1) ,
(Part) , (EAM-2) , (EAM-3) , (E AM-4)
I Q. Please state your name and address for the record.
2 - A. Edward A. Mye rs, J r. My business address is 2244 Walnut Grove Avenue, 3 Rosemead, California.
4 Q. What is your position with Southern California Edison Company?
5 A. Vice President. My areas of- responsibility include Conservation and 6 Community Services, Corporate Communications, and Revenue Requi rements.
7 Q. Please refer to Exhibit No. (SCE-3) for identification, entitled 8 " Qualifications of Witnesses". Directing your attention to the page 9 entitled "Quali fications of Edward A. Myers, Jr.", does that portion of 10 the exhibit accurately set forth your background, training, and 11 experience?
12 A. Yes, it does.
13 -Q. What is the purpose of your testimony?
14 A. My test imony presents Edison's management , staff and line commitment to 15 conse rvat i on. As used- in this test imony, the term "conse rvation" covers 16 both' load management , or capacity-saving activities , and conservation , or 17 energy-saving activities. My testimony addresses the propriety of 18 expenses for conservation activities, as contained in Chapter 12, presents 19 an overview of conservation programs planned for the test year, and 20 outlines -impending requirements of state and/or federal regulatory bodies.
21 My testimony also relates to those minimal 'nonconservation advertising 22 fand. pub?Ic information function expenses contained in Chapter 13, matching 23 them to guidelines set forth by this Commission.
.12/13 (Part )-l
'8-31-79
Edward A. Myers, Jr.
1 Q. Mr. Myers, does Edison have e conservation policy?
2 A. Yes.
I 3_ Q. Could you please describe that policy?
4 A. Yes. For over ten years, our conservation activit ies have cont ributed 5 to' more efficient use of electricity. I Edison's conservation policies are reflected throughout the 6
7 body of our total Application. The Company has long recognized the need
- 8 to respond with vigor and imagination in an effort to moderate the current 9 and projected demand for elec.tricity which, even if partially stemmed, i 10- sill require increasingly larger expenditures for future generation and 11 transmission facilities.
12 Additionally, Edison recognizes that energy supplies are
'13 becoming increasingly n: ore expensive and scarce. To minimize facility
- 14. :and fuel expenditures to the extent possible, Edison has undertaken
.. extensive energy conservation programs designed to accomplish three basic J
16 . object ives : (1) to increase the efficiency of electricity usage by all 17' customer classes, (2) to reduce energy waste through education and eNample,
! 18- 'and (3) to moderate the growth of system peak demands. In addition to these 19- basic objectives, three other Company policies have considerable influence 20 on our conservation program planning: (1) to meet necessary' growth in an
.21 orderly and- financially feasible manner, (2)- to develop greater dependability
~
22 and persistence of conservation achievements such as through the application
'23 ' of' reliable point-of-use cont rol ~ hardware, and (3) to meet the need for
' 2i ' increased productivity achieved when the cost effectiveness of each
- 25 ' conservation program is optimized. Lacking a concise universally-accepted
- 26. definition of cost effectiveness,' Edison considers- a program to be cost ,
27- ' effective when it can be implemented for less than the cost of'providing 28 new supplies. 'As I testified'in previous proceedings, it is also our
~
12/13 (Part)-2
..8-3,1-79;
> ~b -- , e + n - w=- -
Edward A. Hyars, Jr.
1 policy to complement, to the extent possible, the programs of others 2 without being duplicat tve. These conservation policies are supported by I 3 senior management's ongoing commitment to conservation as evidenced by 4 executive and line officer involvement oa various oversight committees 1
5 described hereaf ter.
(
6 The first example is the Corporate Comnpinications Advisory 7 Committee which was formed in 1971 and originally chaired by Executive I
8 Vice President Howard P. Allen. Comprised of key line and staff officers, 9 it is charged with reviewing and approving all formal internal and 10 external corporate communications policies. This Committee approves the l
11 planning and implementation of public awareness and advertising of 12 conservation activities and regularly mon? tors the results.
.13 Second,. In 1975, the Peak Demand and System Capacity Factor 14- Management Committee was estabIlshed by the Chairman of the Board and is 15 currently chaired by Senior Vice President. David J. Fogarty. It consists 16- of 'all lir.e officers with operating responsibility, as well as supporting
.17 staff officers. .The Committee is charged with delineating conservation i
18 and operating policies and procedures which will reduce Edison's future
-19 ; construction commitments and optimize fuel Inventories, while maintaining 20' a viable financial position. In this connection, it reviews all customer
-21 load management and load limiting conservation programs as well as l- 22 programs internal to the Company involving power-saving techniques. The
- 23. Committee regularly monitors the results.
'24- Third,'we- formed an Energy Services Connittee censisting of
,25 - . department heads from all affected areas of Company operations to
.56) 9 expedite' the analysis and approval of alternative means of satisfying i
227 customers,'. needs for_ energy- services other than electricity, which services 128. 1would be'provided.under. filed rates from the Company's electric power
_ '12/13(Part)-3
- 8-31-79, -
r
Edward A. Hyars, Jr.
I system. The Committee chairman is accountable to the Executive Vice 2 President and is responsible for developing economic and engineering
. 3 analyses and proposing energy services facilities, inc!uding on-site 4 generation facIIIties, and either Company or customer-owned alternative 5 energy systems, including wind and solar power. The Committee also 6 approves parameters for negotiations with the customer for such 7 installations.
8 Fourth, a Rate Committee consisting of Company IIne and 9 financial officers oversees the development of conservation-related rates, 10 including marginal cost-based rates, time-of-use rates, seasonal rates, 11 standby rates, and other innovative rate approaches.
12' Edison accepts the responsibility to convince its customers that 13 conservation is more essential today than ever before. Conservation is 14 one ef fective technique to minimize the impact on customer bills of the 15 costs of construction for generation and transmission facilities required 16 to meet our customers' future elect ric requi rements. Further, conse rvation 17 is an effective means to minimize the purchase of costly fuel oli to 18 operste generation facilities.
19 Certainly, our policy is influenced by requirements of and 20 directives from various state and federal regulatory agencies, but it is 21 guided primarily by existing decisions'of this Commission. For example ,
22 In Decision No. 84902,- this Commission indicated its intention to make
"...the vigor, imagination, and ef fectiveness of a utility's conservation
~
23'
' 2 4'-
. ef forts a key quest ion in future rate proceedings. . .". This is precisely 3.25 our conservation-policy': the ascertainment , stimulation, and implementation
- 26 of vigorous, imaginative, .and ef fective conservation efforts.. We 27 -appreciate the valuable: assistance of the Commission's conservation staff 28- Land of other interested parties in this endeavor.
~
- 29 )- We h' ave prepared this Application proposing an increase .in the
'8-31-79
Edwtrd A. Nyers, Jr.
I over-all resource commitment to conservation programs. We seek to improve 2 upon the historical levels of conservation achievements which were made 3 possibic by the conservation expense allowance levels authorized in the 4 general rate decision effective January 1979 It is anticipated that 5 each of the proposed programs will further increase the efficiency of 6 electricity usage, moderate system peak demands, and reduce energy waste.
7 The proposed programs for test year 1981 will expand successful 8 longstanding activities, introduce new conservation concepts, and sustain 9 a needed conservation awareness program which underlies all succassful 10 efforts to stimulate the consuming public to practice conservation. Our 11 programs reflect a growing reliance on an educated, motivated public, 12 encouraging the selection and installation of efficient appliances, 13 providing for expanded energy audit interfaces for all customer classes, 14 and voluntary acceptance of t ime-of-use rates and/or hardware. Further, 15 our proposals anticipate certain impending requirements of this Commission, 16 the California Energy Commission, and the National Energy Acts, providing 17 for appropriate actions if, as, and when required.
18 Q. Please discuss each FERC account designation in Chapter 12 and the 19 activities included in each account.
20 A. Chapter 12 contains conservation activities which are accounted for in 21 FERC accounts 907, 908, 909, and 910.
22 Account 907 is " Supervision" under the current definition in the 23 Uniform System of Accounts, and includes labor and expenses incurred in 24 the management and supervision of the conservation activities carried
'25 on by the Conservation, Communications and Revenue Services Departments, 26 plus an allocation of centralized departmental administrative 27 support activities related to conservation activies and Customer 28 Service overhead costs associated with our field conservation forces 12/13(Part)-5 8-31-79
1 Edwsrd A. Myers, Jr.
and their efforts in customer conser/ation.
2 Account 908 is designated " Customer assistance expenses". As I 3 defined'ln the Uniform System of Accounts, this account includes labor, 4 materials used, and expenses incurred in providing instructions or 5 assistance to customers, the object of which is to encourage safe,
.6 efficient, and economical use of the utility's service. This account 7 contains the bulk of the expenses incurred in developing and carrying 8 out our conservation programs. Exceptions are those advertising 9 L expenses supporting general public awareness of conservation and the 10 advertising components of specific conservation activities which are 11 contained in Account 909, as I will explain later.
,12 Specifically, Account 908 includes the labor and administrative 13 costs of staff and field personnel who plan, implement, and monitor our ;
14: customer conservation programs, together with related material and 15' program costs.
16 Account 909 is titled " Informational and instructional 17 advertising expenses". Under the Uniform System of Accounts, the labor, 18' ~ materials used,'and expenses incurred in activities which primarily
- 19. -convey information as to what the utility or others, such as federal
.20 aad: state regulatory agencies, urge or suggest customers should do to 21 conserve electric energy or capNity are included herein. - Gene ra l ly ,
22 Account 909 covers conservation media advertising and other appropriate r
~
23 communication costs related to conservaticn such as allocated labor 24 :and expenses of certain Corporate Communications personnel for their
. -25. relevant conservation activities; expenses for development and placement 26} 'of conservation advertising' for general circulation; preparation and.
27 distribution 'of conservation booklets, brochures, and bill stuffers; 28 construction, installation,'and-maintenance of. fixed and mobile
.12/13 (Pa rt)-6.-
- 8-31-79'
=_- . - . _ - . _. - - . - _ _ - - _ _ -
Edward A. Hyars, Jr.
I conservation displays and exhibits in Edison offices and at public 2 gathering places. This account also includes all related communications 3 activities which serve to provide customers with continuing informatico, 4 both to achieve immediate reduction in use of electricity or a shift 5 in time of use, as well as to establish and maintain a broad public 6 base for a better understanding of the need for personal and corporate 7 conservation efforts.
8 Account 910 is " Miscellaneous customer service and information 9 expenses". This account includes the labor, materials used, and 10 expenses incurred in connection with customor contact and informational 11 activities which ara not includable in other customer information expense 12 accounts. At the present time, and'looking forward to test year 1981, it 13 is not anticipated that any of our conservation expenses will be charged 14 to this account.
15 Q. What level of funding for ' conservation was authorized in base rates by 16 Decision No. 897117 17 A. A funding level of $20 million was authorized.
18 Q. What level of results corresponds with this level of funding?
19 A. Estimated 1979 results for customer-oriented conservation activities, 20 the first' full year the funding level would be in effect, are an energy 21 reduction of approximately 1.2 billion annualized kilowatthours and a demand
'22 reduction of approximately 201 megawatts. ' Recorded results for 1978, 23 contained in Exhibit'No. (EAM-4)- were an energy reduction of approxi-24 mately 700 miliIon annualized kilowatthours and approximately' 184 megawatts 25 ' of demand : reduct ion.
-26 In addition to these 1979 projected and 1978' recorded results which 27- relate to Chapter 12 funding, Edison. conserved 900 million kWh during 1978
' 28 ' and ~will conserve an estimated I'.5 billion kWh' during 1979 and through such
'12/13 (Pa rt )-7~ ,
1 8-31-79
Edwtrd A. Myers , Jr.
4 I programs as Conservation Voltage Reduction (CVR), Distribution Circuit Load 2 Management (DCM), and High Pressure Sodium Vapor (HPSV) Streetlight Conver-3 sion, which are not chargeable to Chapter 12.
4 Q. Do the expenses' presented in Chapter 12 represent Edison's total i 5 conservation effort?
6 A. No Chapter 12 represents only the expenses for FERC Accounts 907 through 4
7 910, consistent with the Uniform System of Accounts guidelines. These 8 accounts represent expenditures for conservation to be achieved on the 9 customer's side of the meter. The 1981 test year costs associated with 10 conservation on Edison's side of the meter for programs such as Conservation II Voltage Reduction, Distribution Circuit Load Management, HPSV Streetlight
- 12 . Conversion, as well as Conservation Research and Development are accounted
-13 for in other chapters consistent-with the Uniform System of Accounts
-14 guidelines and are addressed by other witnesses.
{ f l5' Q. How is the effectiveness of conservation programs measured?
116 .A. We have utiliz'ed several methods of measurement in the past and plan to 17 continue and improve upon these. We have been working with the staffs of 18' the CPUC and 'the CEC to develop appropriate criteria and methodology to 1 .19_ _ . measure _ the effect iveness of conservation programs. To t hi s end , we a re 20 - utilizing 'several neasurement . methods Including: (1) direct activity
- 21 ~ reports by our field people of actual energy-use reducticits by our 22- . customers, (2)' surveys, (3) installed hardware, (4) testing results 23 and ext rapolations theref rom, (5) partial " report. card"-type customer 24 billing, and (6)_ recorded sales results. Also, Edison has developed 25 ~ Lan econorretric. methodology to measure conservation. Our approach 26- utilizes econometric techniques to isolate and identify estimat'ed
'27 ; electricity. savings due to conservation. In the Edison service territory.
28 The model provides' for variables such as weather,- income, price, etc.
^ t 12/13(Part)-8'
~-
y ,} g s+'-y- - - n-r-- -e- , -,,e , w , , t- w m- g ,-
Edward A. Myers, Jr.
I Since our initial effort in this regard in January 1978, we have maintained 2 and refined the technology involved, reflecting the advice of regulatory 3 staffs and consulting econometricians. Details of the econometric model 4 and other measurement techniques are shown in Exhibit No. (EAM-3) .
5 Q. Mr. Myers, referring to Table 12-B, why did the average residential annual 6 use per customer increase at a higher rate in 1978 than in other years 7 subsequent to 1973?
8 A. This increased usage was caused by several interrelated factors. One 9 important f actor was a three percent increase in the number of residential L
10 customers. Many of these added customers purchased new homes located in 11 some of the warmer areas of the Edison service territory (Riverside County, 12 San Bernardino County, east San Gabriel Valley, etc.), thereby adding air Other additional customers were master 13 conditioning load to the system.
14 metered mobile home parks and apartments, previously billed on Edison's 15 commercial General Service rates, who during 1978 were given the option and 16 elected to be billed on the new Domestic Service Multi-Family Accommodation -
17 Submetered Rate to take advantage of lifeline rate availability. Af ter the 18 . rate change, these customers were counted as doraestic customers, therefore, 19 Impacting the increased residential customer kWh usage. Another cont. lbuting 20 factor was the unusual weather conditions for 1978, which were more extreme 21- than in 1977. -These conditions . reflected additional heating and cooling 22 ' requ i reme n t s .
23 Q. Mr. Myers, has Edison accumulated the energy savings and the capacity 24 reduct ion f rom its: conservaton programs in the past? t 25 A .~ Yes. We have measured the results from our programs since 1973 If we add
- 26 up all the savings that we have reported for conservation programs on 27- Edison's side of the meter, 'It totals to over 2.8 billion kWh and over 28 500 MW. This t,ranslates to 4.5 million barrels of oli and a plant the
'29 size of. San Onofre Unit 1E in deferred capacity. However, we know that 12/13 (Part)-9 8-31-79;
Edward A. Myers, Jr.
I many of these results overlap, do not persist, and are not additive. As 2 we have previously testified, the only proof of long-term conservation 3 results are the realized departures from the original estimates of 4 sales and capacity requirements.
5 Q. Has Edison measured its persistence of conservation savings?
6 A. Our existing measurement methods have been employed to determine the 7 results of conservation programs implemented during a specific year. In 8 addition, w have life-cycled results of hardware programs over the 9 e s t imat ed 1 > ,'c of t he ha rdwa re. As stated earlier in my testimony, the 10 only dependable results for which we could either defer building plant il or reduce purchases of expensive fuel oil are those results which become 12 permanent (for example,' hardware in place). The most meaningful benefits 13 are those resultIng from our load management programs whereby Edison 14 can depend on reductions in demand from load management hardware during 15 times of capacity shortage. We also believe that the results of our 16 commercial, industrial, and agriclutural audit program are reliable to 17 the extent that more than 50% are due to hardware changes and that both 18 the hardware and behavioral actions have been validated in the field.
19 Additionally, recent developments in computer capacity will allow our 20 conservation analysts to develop a data base as input for our persistence 21 measurement plan.
22 Savings from behavioral actions are the most delusive of the 23 results reported for our programs. In developing a plan to measure the 24 persistunce of behavioral actions, we welcome the advice of the Ccmynission 25- staff and others.
26 Q. Is~a data base being developed for persistence and other measurement i
27 ~ -activities?
28- A. Yes. End-use equipment saturation, demographics, square-footage, and -
12/13(Part)-10
Edwsrd A. Mysrs, Jr.
I other data are being collected by Edison individually and in cooperation 2 with state agencies, in 1980, we will initiate the development of a plan 3 for data collection and analysis to determine persistence of savings. In 4 future years, this data base will be utilized to give Edison and the 5 Commission a better handle on other conservation measurements.
6 Q. Has Edison determined the over-all potential for conservation in its 7 service territory?
8 A. For each conservation program in test year 1981, Edison planners have 9 estimated the potential savings for that particular program utilizing 10 available marketing data and unit energy savings determined by engineering 11 calculations. However, determination of the over-all potential is a 12 difficult, if not impossible, task.
13 The ultimate potential lies in the hearts and minds of each 14 Individual customer; in realizing this potential, each customer must 15 perceive either crisis or selfish benefit.
16 There is great appeal, and it is relatively easy to e,rbitrarily 17 assign a percentage to recorded usage, but to analyze and develop programs 18 with real feasibility is a difficult Job. To this end, we are working 19 very hard and expanding our efforts.
20 We have abided with arbitrary quotas, but for many years, our 21 concentration has been on getting customers to develop a positive attitude 22 toward conservation and to voluntarily respond to our conservation 23 p rog rams. Our own goal is to maximize each individual's conservation 24 potential wherever and whenever possible within our existing resource 25 commitment. Toward this end, we have focused on installed hardware, 26 an ongoing barrage of messages, and one-on-one communications.
27 The facts are that the Company has reduced by nearly one-half its 28 growth projections for peak demand and kilowatthour consumption f rom the 12/13 (Pa rt)-i l 8-31-79
Edward A. Mycrs, Jr.
i I growth rate projected prior to the oil embargo in 1973 We recognize that 2 this lower growth rate is a result of many factors which are difficult 3 to isolate and even more difficult to quantify. We also recognize that I
4 the programs sponsored by regulatory agencies and others have had a 5 positive effect on lessening our growth rate, and we appreciate this 6 support.
7 Q. Ple&se describe the specific conservation program Edison has planned for '
- .8 1981.
i 9 A. For its 1981 Con.ervation/ Load Hanagement Program, Edison has combined ,
10 successful ongoing programs and new activities to establish a base $25 ;
. 11 million annual effort. Ar additional $14 million is also included for
. 12 programs which, at this writing, appear to be stated as mandatory by 13 either the California Public Utilities Commission, the California Erergy 14 Commission, and/or the National Energy Acts. In our base program, efforts 15 .will- be divided between two primary market targets, residential and l16. nonresidential, in two areas - conservation and load management. We 17 separately address our expanding cogeneration and solar activities, it 18l .is estimated that the customer-oriented base and supplemental conservation
-19 programs, as described in this chapter, will, if successfully implemented 120- In ~ the 1981 test year, lower anticipated annualized kilowatthour sales
~
~21 by approximately.2,021,457,900 kWh and reduce system demand by 252.6 MW.
22 JThe' ten r.iajor categories comprising the 1981 base program are:
23 l1. Nonresidential Conservation 24 - 2. Nonresidential Load Management
'25 3.; Cogeneration
~s5: 4. Residential Conservation
- 27. ' 5. Residential Load Management-
- 228- .6. Solar 12/13(Part)-12
,8-31-79
Eckard A. Myers, Jr.
- 7. Public Awareness 2 8. Adve rti sing 3 9 Measurement 4 10. Management in Conservation and 5 Load Management Activities
'6 The de* illed descriptions of the individual plans and programs included 7 in the ten major activity categories are contained in Exhibit No. (EAM-1) 8 and will be described by Ms. Margo A. Wells of Edison's
- 9. Conservation OlvisIon staff.
- 10 Q. Please explain the increase in base funding required for your proposed 11 1981 programs compared with the funding level authorized by Decision 12 No. 89711.
13 A. Tbc increase in base funding from the $20 million aathorized by Decision 14 No. 89711 to the $25 million required for our proposed 1981 programs is 15 responsive to Ordering Paragraph 8 of Decision 'No. 897i1. Paragraph 3 16 di rected Edi son to ". . . cont inue programs designed to produce conservation ,
17 increase ef forts to developing conservation oriented rates based on marginal costs, and apply vigor and imagination to developing new,-innovative', and
~
-18
-19 cost e f fect ive conservation programs". The requested base -level of '
20 funding . reflects- the orderly growth in Edison-originated programs. Our
- 21 Application also reflects an additional .14 million conservation dollars 22- to cover the estimated cost of increnental programs mandated subsequent 123 to Decision No. 89711 in Application No. 57602. Our total request for 24' customer conservation is $39 million. .
25 .Q. Please Identify the specific programs you consider incremental to the base funding and explain how they are " mandated".
76.
27; A. Exhibit 1No. (EAM-l)- contains a chart showing Edison base programs 28 plus Incremental mandated 'or'potentially mandatable programs.
~,_
.12/13 (Pa rt )'-13)
i l
. Edwsrd A. Myers, Jr. 1 I Specifically, mandated programs include the Residential Conservation 2 Services program (RCS) mandated by NECPA; the Residential Load Management 3 Standard mandated by the Load Manage. ment Standards adopted by the 4 California Energy Commission; the End-Use Surveys required by Title 20 of 5 the California Administrative Code which are utilized by the CEC in the 6 Biennial Report / Common Forecast Cycle; maintenance of the Standard 7 Industrial Classification (SIC) Coding for nonresidential customers; below 8 market rate financing for Insulation and solar water heating systems; 9 expanded promotional activities for solar in both new construction and 10 retrofit of existing dwellings; and an apartment cogeneration project.
11 These specific programs result in costs incremental to those presented in 121 Application No. 57602 and cannot be accommodated within the present level 13 of base-funding if we are to sustain and expand the utility-sponsored
.14 effort acknowledged in Decision No. 89711.
'15 . Q. What . level of results do you estimate from these supplemental mandated 16 . programs?
17 1 A'. . Our estimate of the level of results associated with the supplemental 18 mandated programs . in test-year- 1981 is a ' reduction of approximately 19- -19,178.900 kWh on an annualized basis.
' 20 ~ q. -What. level.of total results do you estimate from your proposed 1981 E< :21 progra ns?
, 22 A. Exhibi t No. -(EAM-1) presents the estimated results of all of our 23 : proposed-1981 test-year programs which are summarized as follows:
-12/13(Part) 38-31-79 G
Edward A. Mysrs, Jr.
I Customer Conservation Annua 11 zed 2 Base 2,002,279,000 kWh 252.6 MW Annualized 3 Supplemental 19,178,900 kWh --
Annualized 4 Total 2,021,457,900 kWh 252.6 MW 5 Edison System Annual / Actual Conservation Total
- 1,692,000,000 kWh --
6 7
- Includes Conservation Voltage Reduction.
8 Q. Is the request for 1981 conservation programs funding a request for the 9 authorization of specific programs or a request for a level of funding?
10 A. The programs contained in our Application are representative of our 11 present thinking as to an appropriate level of base conservation funding,
'l2 and for the Commission's determination, an estimate of the funding impact 13 of supplemental / mandated programs.
14 Edison has accepted the responsibility of evaluating 15 conservat ion programs. We determine their effectiveness with help frun 16 the state and other inputs. We have been involved in conservation efforts 17 since 1971. We believe we have the experience and qualifications to 18 appraise each program, and we certainly have the desire to succeed in 19 conservation. Certainly, any program which is not effective must 20 be amended or terminated. Howeve r , if any programs are terminated or 21 reduced, new programs must replace them in order that the approved level 22 of expenditure be maintained.
23 Also, we accept our responsibility, as prudent managers, to seek 24- out and act upon opportunities for increase productivity and are mindful 25 that we are accountable to regulatory bodies, the public, and our 26 s tockhol de rs . We view our base request from this perspective as
.27 authorization for a Icvel of funding rather than a request for the 28 authorization 'of specific programs.
12/13(Part)-15 8-31-79'
Edw2rd A. Mya rs , J r.
I insofar as mandated programs covered by our supplemental request, !
)
2 authorization of specific programs would be desirable la all cases and 3 even necessary in some cases.
4 Q. Does this complete your testimony on Chapter 12?
5 A. Yes, it does.
6 Q. Please discuss the Advertising and Public Relations Expense contained in 7 Chapter 13 and explain why this testimony appears in this position in the 8 case.
I 9 A. In Decision' No. 86794 in' Application No. 54946, the Commission set forth
-10 guidelines regarding our advertising and public information expenditures.
-11 Guided by this decision, we reviewed all of our advertising and public
, 12- relations activities, allocating conservation activities to Accounts 907, 13 908, and 909 in Chapter 12 and allocating approved types of nonconservation 14 activities in Chapter 13 to Accounts 920, 921, 923, 926.1, 930.1, and 930.2.
15 This testimony and accompanying Exhibit No. (EAM-2) describe the 16 conservation-related and nonconservation-related advertising and public 17- Information pursuant to CPUC guidelines.
18 Q. What did Decision No. 86794 offer as guidelines for information advertising?
.19 A. . Decision No. 86794 stated:
L20 "All institutional advertising shall be. disallowed for 21 ratemaking purposes. Furthermore, all other advertising, 122 except that which is listed below, shall also be disallowed 23 for ratemaking purposes.
12 4 "a. Financial . adve rt ising.
"25 "b. Safety messages.
26 "c. . Essential customer services information such as J27 changes 'Irt location of offices,. telephone numbers,
28 payment agencies,-and announcements of regulatory
.12/13(Part)-16
Edward A. Myers , J r.
1 proceedings before this Commission or other 2 regulatory agencies.
3 "d. Results-o.-iented, specific conservation advertising; 4 this must , however, be accounted for separately as 5 a conservation expense."
- 6. To help clarify this allocation, Exhibit No. (EAM-2) ,
7 Table 1, has been prepared with the cost breakdown and samples of our
-8 ~a dvertising activities, both conservation and nonconservation. The 9 . conservation advertising activities as specified in item d are covered 10 in Chapter 12. Expenses for nonconservation activities, as stated in
.11 Items 'a, b, and c, are covered in Chapter 13
- 12. .Q.~ W hat .about public relations?
_ 13 ' A. LAt Edison we have no Public Relations department, per se. The advertising
- 14. .activit ies approved- by Decision No. 86794 are accomplished within the
'15 Corporate Communications Department and the Conservation and Community
'16 Services Department.
17: Q. What other guidelines have been provided by the Commission?
-181 A .' With.. respect -_to public ~.relat ions , ' the Commission provided the following
- 19_ policy clartfIcattons in Decision No.
- 86794:
" ...it1shall be.the policy _of'this Commission henceforth 20-
'21 -to exclude from' operating expenses-for rate fixing purposes
-- 2 2 ; . all amounts claimed for public relations expense for which
,23 it:cannot be shown:
Providss normal llaison with,.and. channels of
~
24 _
a-f25" communicati'on for, represent'atives 'of the press,
-26 radio,i elevision.
t : and.~other media.~
c27 1 ' ' b .- Results in reduction of operating ~ costs and more 28- ' ef ficient' service to the: ratepayers.
.12/13(Part)-17
, :8-31-7W .
= -
_n
Edwsrd A. Hyars, J r. .
I "c. Encourages the more efficient operation of the 2 utility's plant, the more efficient use of the l
3 utility's services, or the conservation of energy 4 or natural resources, or presents accurate information ,
l 5 on the economical purchase, maintenance, or effective 6 use of cler.trical or gas appliances or divices.
- 7. "d. Presents factual discussion of specific topics dealing 8 with plant siting, safety, and environmental impact.
5 9 "In future proceedings involving this and other utilities, we 10 shall expect the utility to justify, ard our staf f to verify, 11 public relations costs in detail and to supply, for the record, 12 Information on each aspect of the utility's public relations 13- program so that we may make Judgments regarding the 14 reasonableness of each activity and of appropriate reasonable 15 . allowances."
l16 Exhibit No. (EAM-2) , Table 2, shows examples of our
~
- 17. - "public relations" activities and the allocation of costs associated with 16 those activities.
(19 We considert ' hese nonconservation public relations activities
- 20- ' essential to public understanding'and support of Edison's efforts to
'21 provide, adequate. electric service to its customers. Our philosophy for 22 -both conservation and nonconservation communications programs has been J23' a'one-on-one approach. Toward this end, we have substituted large group /
'.2% ^ lecture-series' for workshop-type meetings and have developed oral, visual, 25 . and written communicatlons to specific segments of the public in and j i
- 26 - -around our service territory. . incorporated are factual discussions of 1
' 27_. Company concer.ns relating to siting, alternate energy sources, and 28 environmental I.mpact,-each of.which meets the Commission guidelines.
l 12/13(Part)-18 l i
8-31-7si ,
Edward A. Mycrs, Jr.
I Provision is also made for personnel to respond to inquiries 2 by TV, radio, and press on all newsworthy activities in our 14-county, 3 50,000 square-mile territory.
4 We think the programs we have allocated to nonconservation 5 communications activities accounted for in Accounts 920, 921, 926.1, 930.1, 6 and 930e2 represent minimum staff for these critical times when public 7- understanding is so vital to both the utility and regulator.
'8 Q. How do you measure the effectiveness of your advertising /public relations 9 activities, both conservation and nonconservation?
10 A. There appears to be no direct method of measurement for energy reductions 11 or other public response attributable to advertising or other public 12 relations activities. As an alternative, Edison took a benchmark survey
'l3 in 1976 of a statistical sample of all customers to determine awareness 14 and attitude about such topics as the energy issue, conservation, research
.15 and development, utility rates, and Edison as a company. This survey 16: established a means by which,- through tracking surveys, a gauge of public 17 awareness of the conservation ethic as wcll as the need for and effective-18' ness of any specific advertising or publicity could be determined.'
19 Exhibit No..(EAM-3) contains a summary of our most recent results.
20 .The results of this and other surveys, as well as reports from field
.21 customer contact personnel, will- help us to be more responsive to consumer
~
_ 22' shifts in attitude and priorities. Further, it is utilized to help tailor our. communicat ions ef forts to our customers ' -needs.
~
-23
- 24 Q. ' Does. Edison ut ilize' copy testing?
=25 A. Benefiting' from suggestions provided by lIntervenors in earlier proceedings 26 to assure that advertisements communicate. the intended messages in a
-27 clear and understandable manner, pretests arefconducted by our
~ 28 . advertising agency. The results of these pretests .have been most 12/13 (Pa rt)-19 l:
8-31-79-.
. - . .. -- -- - _- - - .-.- .. .- - ~ . . . ~ -....
Edward ' A. - Myers , J r.
1 ' encouraging. As an example, the pretest of our augmented summer capacity
- 2 crisis campaign revealed that .92% of the target audience said that af ter
, ?3 seeing the advertisemen:, they would try to follow the suggestion to "Give
.4 their Appliances the Af ternoon Of f".
, 5. Q. To the- extent the material -in Chapter 12 and advertising and public l ~6l awareness components of Chapter 13 of Exhibit No. (SCE-2) as well
'7 as supplemental Exhibits Nos. (EAM-1) , (EAM-2) , (EAM-3) ,
t 8 'and (EAM-4) . is of a factual nature, do you believe i t to be 9 ' accurate?
t
.10 A. Yes, I do.-
11 ~ Q. To the extentthat the ' material is in the nature of opinion or judgment ,
-12 does . it -. represent your best Judgment?
c j <l3 - .A. Yes. it does.
F 71 4- 'Q. :Does this conclude your~' prepared testimony?
15 ^A. Yes, It--does, j.
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12/13 (Pa rt).-20 "8-31 < - -
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SOUTHERN CALIFORulA EDISON COMPANY Prepared Testimony of Margo A. Wells Exhibit No. (SCE-2) , Chapter 12 (Part)
Exhibit No. (EAM-1) , (Part) 1 q. Psease state your name and address for the record.
2 A. Margo A. Wells. My business address is 2244 Walnut Grove Avenue, 3 Rosemead, California.
'4 q. What is your position with Southern California Edison Company?
5 A. Supervisor of Conservation Staff Services. My area of responsibility 6 includes the monitoring, evaluation, and reporting of the effectiveness 7 of'the Company's conservation and load management programs.
8 Q. Please refer to Exhit,s t No. (SCE-3), for identification, enti tled 9' " qualifications of Wi tnesses". Directing your attention to the page 10 entitled " qualifications of Margo A. Wells", does that portion accurately 11 set forth your background, training, and experience?
12 -A. _Yes, it does.
13 q. What is - the purpose of youh testimony?
14 A. ' The purpose of my testimony is to present detail on Edison's proposed 15_ 1981 base conservation plans and programs within the ten major activity 16 categories presented in the testimony of E. A. 'Myers,' Jr., which are 17 properly charged to-Chapter.12 and contained in Exhibit No. (EAM-1) .
'18' "q. What is included in the' Nonresidential Conservation activity category?
'A. 'In th'e Nonresidential Conservation Activity category, Edison will continue 19 its very successful commercial, industrial, agricultural, and public
{ 20 21 authortty energy au'dit program which was inttiated in 1973 22 . The audit effort wilI be augmented by: mai1Ing a New Customer.
23 Conservation Booklet containing self-help audit information to new
.i 12 (Pa rt)-1 K8-31.-79:
';Msrgo A. Walls
.I commercial / industrial customers shortly af ter service is requested; 2 recognizing and presenting Eneroy Management Awards to businesses and 3 Industries who have made outstanding conservation efforts; utilizing a 4 mobile display that showcases conservation hardware applications for 5 customer inspection; offering an electric water heater thermostat 6 turn-down service; initlating a series of campaigns designed to encourage 17 electrical contractors, refrigeration mechanics and technicians, wholesale 8 suppliers, and HVAC contractors to promote conservation hardware with 9 Edison customers at the time of equipment servicing; and promoting 10 - conservation hardware through a coupon-incentive campaign.
~
11 ~ Edison will lend Impetus to its Agricultural and Water Pumping
-12 -Tes t' program by ' offering a ' Pump Tes t and Adjus tment program which requi res 13 deep well turbine pump customers 'to have a contractor at the pump site to
~
11_4 make' the appropriate. adjustments at the time of the Edison pump test.
15 Edison will 'also offer a free feasibility study for utilizing heat 16_ recovery equipment in milking parlors with electric water heaters.
17 Q. What is included in the Nonresidential Load Management category?
i-18 -A. . in the Nonresidential Load Management category, directed at its commercial, '
l 19 industrial, agricultural, and public' authority customers, Edison will 20 continue:Its evaluation of off-peak systems and utility-activated load 21- - cycling systems for _ contribution to peak' demand reductions. The 22- .submetering and analysis .of nonexperimental and experimental time-of-use
- 23 rate designs will also' be continued.
24 ' q.1 WhaC is Included lIn the -Cogeneration category?
, 25~ fA. In' the Cogeneration category,' Edison will continue to encourage
-26, :the. installaiton' of cost-effective on-site generation by commercial
- 27 f _and(industrial customers, which can-be operated In parallel with "28- the Edison system for,the benefit;of'alI ratepayers.
. 12(Part) 2 -
8-31 ( .-
Margo A. Walls
~1 The potential for residential cogeneration and customer-owned 2 auxiliary generation is also being investigated. Edison has begun to 3 assess the market potential in this area and to further define the 4' potential for peak shaving by customers.
5 in addition, Edison is also working with several customers who 6 are planning 'to develop cogeneration projects using biomass, landfill 7 . methane recovery, or solid waste conversion.
8 q. What is included in the Residential Conservation category?
-9 A. In the Residential Conservation category, to reach the more than 2.7 10 million residential customers, Edison utilizes programs keyed to the 11 concerns of individual households to disseminate appropriate conservation 12 suggestions and information relevant to hardware applications.
13 Such efforts will include a revised new customer booklet 14- containing self-help audit information; a computer audit activity (SAVES);
15 an in-home audit activity (Sherlock) supported by small group meetings 16 '(Conservation Workshops) where the "how-tos" of conservation will be 17: demonstrated and discussed; a master meter apartment / mobile home park-18 : activity to stimulate cooperative owner / tenant conservation efforts; a
.19 . toll-free : Conservation information Line that provides nonEnglish-speaking 20 customers an opportunity to communicate with a talking computer that can 21 respond to conservation / load management questions in any programmable i22. foreign language; an evaluation of the cost / benefit of expanding
-231 communication efforts with Spanish-speaking customers; participation .in
- 241 ' the National Energy Watch program aimed at encouraging the installation 25 of conservation features' in both the new and retrofit housing. markets; an -
26~ animated mobile van show designed:to be shown at shopping mails, fairs, 27: and shows to attract and. entertain audiences while conveying conservation /
2 28- . load ' management information; a series of public service television
, ~ 12 (Part) 8-31-79'
l Margo A. Walls-l- programs, related to conserving energy in the home, to be produced and 2 .made avallable to cable, community, and network television stations; and 3 Conservation Corner, a hardware / device showroom.
4 Ongoing conservation hardware-oriented activities will include 5- Home insulation, an activi ty to encourage home and apartment owners to 6 upgrade attic insulation; and Wrap Up 11, which will continue to offer 7 electric water heater customers free water heater insulation blankets and 8- low-flow shower heads. New programs feature De-Light, a program whereby 9 Edison will work with youth organizations to promote the use of low
'10 wattage light bulbs; Secondary Refrigerator Reduction, a program designed 11 to remove inefficient refrigerator / freezer equipment from the marketplace;
-12 Energy Efficient Appliance program, a number of activities designed to 13- expand public awareness on the availability of energy efficient 14 appliances including refrigerators, freezers, and air conditioners that 15 . exceed state appliance efficiency standards; and Off-Peak Refrigerator 16 -Development,'which will involve the production and merchandising of a new
'17 ' . energy efficient refrigerator.
'18 The Residential Activity for 1981 will also include a number of 19 ' technical support and energy-use research activi ties such as - Appliance 20 Retrofit Research, Efficient Appliance Use Testing, Research on Consumer
-20 Energy Use Patterns, and a Heat' Pump Water Heater Test.
- 22. Q. What is -included in the Residential Load Management category?
23' A. In~the Residential Load Management category, Edison will emphasize
- 24) ~utili ty-activated load cycling experiments, time-of-use rate experiments,
- 25. new meter developments,1a. swimming pool pump deferral effort, several 126 off-peak cooling tests, and a consumer education load-shifting campaign 27' ._ utilizin' gL the _ theme '.'Give Your Appliances the Af ternoon Off."-
228: Q. What is inclu'dedLin the-Solar category?
12 (Pa rt)-4
- 8-1 Margo A. Walls
'l A. In the Solar category, Edison's objective is to (1) encourage builders of 2 new housing developments who have elected to install electric water heaters 3
to also install solar water heating systems, and (2) to make solar end-use 4 device information available to existing homeowners with electric water 5 heaters to encourage retrofit solar applications. Further expansion of this 6 activity is pending a decision in Oli No. 13, as well as Oil No. 42.
7 Edison is also investicating rate designs to enhance customer 8 solar and wind generation project acceptance.
9 q. What is included in the Public Awareness category?
10- A. In the Public Awareness category, Edison's efforts encompass eight major 11 components directed at reinforcing consumer awareness of the vital need 12 for conservation and load management. The components of this activity
- 13. Include such important functions as maintaining timeliness of 14 conservation / load management communications materials (slides, brochures, 15 bill inserts, movies,. exhibits, displays, speeches, etc.) which are used
~
16 .with educators; students; professional organizations; federal, state, 17 and local governmental agencies, leaders, and officials; resale 18 customers; and the general public at large. An activity of equal 19 _. Importance is Edison's maintenance of media contacts in order to respond 20 to conservation / load management inquiries and to place timely articles 2.1 'and news releases containing conservation / load management suggestions for 22 our cus tomers.
23 ~ Q. What is included in the Advertising category?
~4 2 'A. In the Advertising category, Edison's activities include (a) the L25- -development of. thematic general public awareness conservation' advertising
'26 for placement in newspaper, television, and radio media to reinforce the
-27 conservation ethic and provide specific conservation suggestions for 28i saving electric energy, and (b)' advertising' directed toward -support of
' 12 (Pa rt)-5
'8-31 t i
1
. l Margo A.' Walls 1 and consumer acceptance of specific conservation / load management programs.
2 - Q. : What is included in the Measurement category?
-3 'A. In the Measurement category, Edison's activities include reports, special 4 studies, research, and personnel necessary to quantify results from 5 specific conservation / load management programs. It also includes
-n 6. .econometric measurement which employs multiple regression analysis to 7' isolate the impacts of major economic variables on the, consumption of 8- electricity.
9 .Q.. What is included in the Management of Conservation / Load Management 10 Activi ties : category?
11 A. -The' Management of Conservation / Load Management Activi ties category
~12 includes the expenses and' associated' costs incurred by management and
, administrative personnel who are responsible for evaluating the over-all
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' 13 - .
=14 cost-effectiveness of the -Conservation / Load Management Program and making LIS recommendations ' for n6dification or termination of program components 16 - found to be noneffective. Also included with this activity is the .
17' ' training of Edison employees to further advance their skills, in implementing conservation / load management activi ties.
~
18 z
' 19 i - Q. To.the extent that the material you . sponsor in Chapter 12 of Exhibit
- =20 ' Nos. (SCE-2) and - (EAH-1.)
Is .of 'a factual nacure , do you believe
! 21: . it: to be accurate? -
222 JA. Yes,-1ldo.
23: ..Q To the extent that 'the material is in the nature 'of opinion or Judgment, 124{ does it1 represent your best; Judgment?
25' A. !Yes,rit,does.
126 ' Q. Does' thisi conclude' your prepered . testimony?
a "27_ ~A. - Yes,'It'.does.
e 12 (Part)-6l .,
8-31-79) -
r-SOUTHERN CALIFORNIA EDISON COMPANY Prepared Testimony of Ray W. Scofield Exhibit No. (SCE-2) , Chapter 13 (Part) 1 Q. Please state your full name and address for the recorc'.
2 A. My name is Ray W. Scofield. My business address is N44 Walnut Grove 3 Avenue, Rosemead , Cal i forni a.
4 Q..What is your position with the ' Southern California Edison Company, 5 Mr. - Scot ield?
6' 'A. I am an Assistant Comptroller.
Please refer - to Exhibi t No. (SCE-3) for identification, entitled 7 Q.
8- '.' Qualifications of Witnesses". _ Directing your attention to the page 9 entitled 'fQualifications of Ray W. Scofield", does that portion of the 10 exhibi t accurately set forth your background, training, and experience?
l [1] A. It does.
' 12 ' Q. Are you-testifying with respect to Chapter 13 of Exhibit No. (SCE.2) 13- for identification'in this proceeding?
14 A. Yes, except for nonconservation advertising and public'information expense, IS' - which is covered by Mr. Myers; abandonment costs associated with cancella-16 tion of planned major projects, which 'Is covered by Mr. Whyte; and
- 17 research'and development expenditures, which is covered by Mr. McCrackin.
18 Q. Was Chapter 13 prepared by you or under your supervision except for those 119 - portions covered by Messrs. McCrackin,' Myers, and Whyte?
- 20 - A. Yes, it was.
-21 'Q. What subject 11s; covered in Chapter 137 L22- ' A. Administrative and general expense.
(23i Q. . What: types of expenses are charged to ad'inistrative and-general expenses?
- 8-17-79 13(Part)-1 ,
m
i Rcy W. : Scoflo1d i 1
l 1 A. Charges to this classification include salaries, wages, supplies, and I 2
expenses of officers and general office employees of the Company properly
-3' . chargeable to operations but not chargeable to a particular operating 4 function;-the fees and expenses of consultants and others for general 5 services; the cost of insurance or reserve provisions to protect the 6 Company against losses of property and against injuries and damage claims;
-7 . employee. pensions and benefits; franchise requirements; certain research 8 - and development work; trustee registrar, and transfer agent fees and
- 9 expenses; general advertising; rents for property of others; and expenses
~
i10 - 1 incurred;in the operating and maintaining of general plant, such as the
~
111 <
general office building and. telecommunication equipment.
12' : Also included are credits for- the amounts of administrative and 137 : general. expense capitalized in Account 922 and employee benefits expense
'14 Teapitalized in Account 926.
15 q. cReferring to Tables 13-A and 13-B, Exhibit'No. (SCE-2) , will you c16 ' describe their-contents?
2 il7 Ai rTableil3-A shows administrative and general ' expenses, by accounts, for 18 the years 1976-through:1981. The first three years are re: corded data, 19' whileLthe latter three years are' estimated. The two columns-to the far
.- 20 right reflect the elimination of A- & G expense relating to SONGS 2 in.
21 1981.> Table-13-B:shows the estimated years with Account 927, Franchise
'22 . Requirements, revised to~ eliminate the effect'of any ECAC revenue.
23: :q. What --is- the total estimated administrative and general expense for each 24j of the years 11979 through 19817 25 - A.D The. estimates are $149.9 milllon'for. 1979, $170.2 million forl1980, and-126- ;$187.5 million for 1981.
- 27 'q. LPlease describe how you wentrabout developir.g~ the estimates for 1979
~
J 28? -through~1981.
~
I1 29 R A. .First,- letlmo point'out that1.the administrative and' general expense group 2
3.0~ : of accounts ^isc nonhomogeneous;in ' nature and, further, in'several of the:
31 iaccoun'ts,:many:of;the elements of expense hear no. relationshipi to each e '*
l13(Part)-2.
gl2v5-79 ,
~
S 4
Ray W. Scofloid 1 other. In my opinion, this makes over-all trending impractical, but it 2 was possible to develop certain basic trends within accounts. Mv basic 3 methodology is described in the text accompanying Table 13-A. I believe 4 the record would be easier to follow if I discuss the significant ex-5 ceptions on an account-by-account basis. .
6 Q. All right; what was the approach used for Account 920, Administrative 7 and general salaries?
8 A. First, it is essential to recognize that the number of regular employees 9 in the Company decreased by over one thousand between 1973 and 1975 As 10 nearly 87% of all A & G labor is recorded in this account, the use of a 11 1974-1978 trend abnormally depressed the base trend, while, conversely, 12 a 1976-1978 base trend developed estimates which appeared unrealistically 13 high. I decided, therefore, to use 1975-1978 for my basic trend.
14 Second, I noted that in the areas of Data Processing, Law, 15 Material Services, and Revenue Requirements, the growth trends have and 16 are expected to increase at faster trend rates than other areas of 17 expense in this account. Conversely, officers' salaries are projected 18 at a lower trend rate than the base trend. Separate trends were 19 developed for each of the areas mentioned, all on the basis of 1974-1978 20 recorded data.
21 Other exceptions in this account include Corporate Communications
~ 22 labor to be -covered by Mr. Myers, the inclusion of Edison labor relating 23 to anti-trust cases, and the labor required to operate a new of fice 24 building to house our engineering personnel following its completion 25 in 1980. The latter expense will be more -than offset by lower rentals 26 estimated in Account 931.
27 Q. Did you prepare the estimates .for Account 921, office supplies and 28 expenses, in a'similar manner?
I 8-17-79 ,
13(Part)-3 m _
. _. = - - .
Rty W. Scofield i
1 A. Yes, although the areas of exception are not completely identical.
2- The only significant differences, however, include a downward adjustment 3 of - the 1978 recorded amount for Of fice Services, as their non-labor 4
expenses were abnormally high due to the prolonged strike in the paper
. 5 Industry. It should also be noted that the growth in Data Processing 6' labor reflected in Account 920 is partially offset by an expected lower 7 _ level of non-labor expenses in this account.
8' Q.
Mr. Scofield, would you please explain the nature of Account 922, Adminis-
-9 trative expenses transferred - Credi t?
10 A. :Yes. First, the amount of administrative expenses capitalized is based on
,11 an established percent of the charges to Accounts 920 and 921 which reflects 12- -the portion of administrative expenses associated with construction.
13 The percentage'to be capitalized is reviewed periodically in 14 accordance with Electric Plan *. Instruction 4-B in the Uniform System of
-15' ~ Accounts. As the result of such studies, the percentages have been 32.32%
16 -for 1976, _33.82% for 1977, 32.28% for 1978, and 29.7% for the expected 17 years 1979 through_1981.
-18 .Q. Mr. Scofield, looking at Account 923, Outside services employed, to what 19 do you attribute-the deciine.in 1978 and 1979 folIowed by an upswing in 20 1980 and 1981?
21 _ A . Let me comment first that the basic trend has been virtually level during 22 the recorded period and 'is so projected for . the estimated years. The J23 downturn in 1978 and _1979 was caused first by the transfer of pension
-24 -management-fees from the account to Account 926 beginning in 1978. For
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257 _1979, legal expenses relating to employee relations were projected at the l 1
- 26 11ower 1976-1977 level, r .1978 expenditures were abnormally lhigh due to
'27 'the= strike bf U.W.U.A. employees.
- 28 The increases'_for.1960-1981 are primarily due to the estimated
- u. ,. .
,8-17-79L 13 (Pa rt) '
Ray W. Scofleid I' costs of $977,000 for a third party management audit, spread 25% in 2 3980 and-75% in 1981. Such an audit was ordered in Decision No. 89711.
3 Further, the San Diego Gas and Electric Company Decision No. 90405 4 states "We also agree that reasonable costs for conducting a management 5 audit are recoverable in rates as we believe such audit will be beneficial 6 to the ratepayers." ,
7 Q. Would you explain the nature of the expenses included in Account 924, 8 Property insurance?
9 A. This account contains the anticipated insurance premiums to protect the
-10 Company against losses and damages to property used in its utility opera-11 tions. Additionally, it includes the amounts reserved by the Ccmpany 12 against certain losses not covered by specific insurance policies. The 13 estimate for the latter has been based on the five year average (1974--
1978) of recorded. losses adjusted to more current price levels.
~
'14 15 The larger than usual in::rease in 1981 includes $855,000 for
~16- San Onofre Unit 2 on the assumption it will'become ooerative as of July I, 17 1981.
18 _There were no other basic trends used in this account as each 19 of'the numerous individual policies were evaluated and' estimated by the
'20 _ Company's Insurance Division.
21 q. -is Account 925, injuries and-damages, somewhat similar in nature to 22 ~ Account 9247 23 A. .Yes, Account 925 includes the anticipated cost of insurance premiums to
~24 ' protect' the Company against injuries and damage claims of others. It also 725- contains the amounts reserved for the losses incurred through claims and 26-
- sults for injuri.es and damages not covered by insurance. The latter was
'27- , estimated on the basis of.a least. squares trend of recorded losses.for the ,
28 past five years-(1974-1978).
!8-17_-79 .
13 (Pa rt)-5 -- -
RSy W. Sc field l' The substantial increase estimated for 1980 relates to an anti-2 trust suit in a District Court for which substantial costs are being 3 incurred in 1979, are expected to peak in 1930, and to begin to decline 4 in 1981.
5 The only items subject to trending in this account were the 6 labor and other expenses for the operation of the Company's Safety 7 Olvision.
8 q. Why does Edison believe it would be reasonable to pass those anti-trust 9 Iltigation costs thrcugh to its customers in its rates and charges for 10 service?
11 A. This litigation involves a number of contentions by certain resale custo-12 mers which essentially boil down to claims of anticompetitive conduct by 13 Edison to the detriment of such resale customers. Specifically, those 14 -customers are using this IItigation as part of their effort to obtcIn ad-15 _vantageous sourcas of power directly from sources that are now, or other-wise might Ilkely be, available to Edison to serve all of its customers.
~
16 .
17 They are also seeking in this, and in related litigation before regulatory 18- ' bodies, . to obtain more favorable rate treatment which, among other things,
'I9 would.incidde-the reallocation of costs as between the two regulatory
- 20. Jurisdictions, narely, retail and resale.
- 21 If such resale customers were to be successful in such litiga-22 tion, It is likely that lower cost sources of bulk power would be made 23 available_directly_to such resale customers, rather than through Edison's 24 operations, meaning that Edison's retail customers could be significantly
- 25 prejudiced in terms of the rates' they pay for service. Similarly, if
'26 differentl methods of cost allocation'between jurisdictions were adopted,
- 27. as a result.of such litigation, methods more favorable to resale customers,
, 28. this: too would result :In detriment to retall customers in the form of -
8-30-79: 13(Part)-6 i
Rey W. Scofield 1 . higher rates and charges for retail service.
2 Since such IItigation is heavily involved with these issues, it 3 seems only fair that customers standing to benefit from these iltigation 4 efforts and expenses of the Company should share in those costs.
5 _ q. Mr. Scofleid, are there other considerations on this matter that should 6 be made?
7 A. Yes, in my Judgment. Recent trends of the law have made pubile utilities, 8 particularly electric public utilities, far more exposed to this kind of 9 litigation.and expense than !n the past. It has become, as a practical
-10 matter, part of the cost of doing business for a large electric utility, 11 particularly one with both retail and resale operations. Many of the 12 contentions that have to be dealt with in such litigation are the direct
.13 result of regulatory action by one or the other or both of the regulatory 14 bcdles regulating the utility's rates and other operations.
15- If this commiss!on determines to adopt a particular rate policy
' 16 - vis-a-vis one or more retail customer groups, that determination very
-17 possibly can become involved in such litigation. " Price squeeze" alle-
- 18 gations are perhaps a prime example. _If one regulatory commission had 19 Jurisdiction'over both retail and resale rates, there might, and probably 20 would, be no " price- s~queeze" problem at all. However, with dual Jurls-21_ -diction,
- given the recent developments of the law in this area, " price 22l _ squeeze" allegations and anti-trust litigation become almost inevitable.
23 Therefore, it .seems entirely appropriate = that the expenses of such liti-I
- 24 gation,'iparticularly'where dual. regulatory jurisdiction exists, should 25 be looked upon'as part'of the ongoing cost of doing business, where such l26 . litigation cannot. be reasonably avoided without the potential of disad-
-27 vantaging ratepayers either in the utility's cost.of bulk power supply or '
- 28' -In terms of the utillty.'s abillty to achieve reasonable earnings results,
- 8-30-79 <
13-(Part)-7
Rcy W. Scofield I
I 1 the failure of which would inevitably prejudice the utility's ability to j I
2 continue to raise the huge amounts of new capital needed to finance plant '
3 construction required to meet increased ratepayer demands for service, 4 with the ultimate result of deterioration in such service.
5 q. Referring now to Account 926, Employee pensions and benefits, to what do
'6- you attribute the substantial increase in 1979, which appears to carry
- 7 forward to a lesser degree in 19807 8 A. As background, the major employee benefits are basically related to one 9 or more of the following factors
- numbers of employees, wage and salary 10 levels, and years of service. The continuing increases of all of these 11 factors result in rising employee pension and benefit expense. The sub-12- stantial increase in 1979,- however, was related to the Company's nego-13: tlations with the labor unions and the resulting change in several of the 14 ' benefits. The over-all benefit package is opened for renogotiation every 15 five years. in Decision No. 89711, the Commission effectively allowed 16 approximately $7 million in test year 1979 for this purpose.
17 '. The major benefits include. Pensions, Group Life insurance, the 18 Employee Stock Purchase Plan, the Family Dental Plan, and Long Term Disa-19 .bility. These benefits were estimated by our Employee Benefits personnel 20 on the ' basis of recorded trends adjusted for 1978 changes, estimated
' 21 : salary increases, and estimated changes in number of participants.
22 Labor and other expenses.in this account were trended on the
. 23' basisLof the recorded years on either 1974-1978 or 1975-1978 bases and L24 consist primarily of the Medica 1' Department, the Employee Benefits 25 Division of.the Employee Relations Department, Personnel and Employee
-26 Development, .and Employee Consnunications. No.n-labor expenses used in the 27' . tiend are approximately 80% medical,' and the use of 1975-1978 resulted in 28 a lower estimate for the -future years.
4
. 8-30-79 - 13 (Part)-8 t
. . .. ~_
Ray W. Scofield 1 One item of expense was added to this account in 1978, pension 2 management fees, which was formerly included in Account 923 3 This account also includes the credit for Employee Pensions and 4 Benefits cap!'talized. The rate of such capitalization is determined
'S annually on the basis of the ratio of total wages and salaries and wages
- 6. and salaries charged to construction. The recorded ratio for 1978 was 7 29.7%, and this rate was used for the estimated years.
8 Q. Please explain the nature of the increases in Account 927, Franchise 9 Requi remen ts.
10 A. This account includes the amounts accrued for the payments to municipal 11 and other' governmental authorities in compilance with f ranchise, ordi-12 nance, or similar requirements. For e'stimating purposes, it is purely a 13 function of revenue and will rise accordingly, whether such revenue is 14 derived from base rates or from energy cost adjustment clause factors.
15- Table 13-Al shows this account excluding the effect of any ECAC revenues.
16 q. What was the basis for the substantial increase in Account 928, Regulatory 17 Commission expense, beginning in 19787 18 A. The: substantial-Increase beginning in 1978, which peaks in 1979, and 19 declines somewhat in 1980 and 1981,'primarily results from the costly 20 " discovery" process relating to anti-trust type litigation involving the 21 . Company before the Federal Energy Regulatory Commission. None of these
- 22. expenditures was anticipated in our prior general rate case and, there-23 fore, none of the 1978 recorded nor the 1979-1980 anticipated expenditures 24 is' included in our_present rate structure.
' 25 : Non-labor expenses,' excluding the anti-trust case, are based-26 ion'a simple average of_the past two years, 1977-1978,'as any trending 1
s27 method produced an estimate which appeared unreasonably high.
28 . Q.' : What Isi included'in Account 929, Duplicate charges - Credit, and why is
- 29_ _the figure not a negative amount in 19787' 1 3(Part) 112-20-79 "
Ryy W.'Scoficid !
I 1 A.- The Company uses this account to record the value assigned to the kilo-2 watthours used during the construction of a new generating unit. However,
{
l 3 in June 1978, the value of the kilowatthours generated at the Cool Water 4 Generating Station was charged to this account, resulting in a net debit I S- to the account for the month and for the year. Excluding this, the ac-6 count would have shown a negative $32,000 for the year.
1 Q. ' Are you responsible for the estimates shown for Account 930.1, General 8 advertising expenses?
9 A. No. Although the grouping in the Uniform System of Accounts requires this 10 account to be included in Administrative and General Expenses, the 11- estimates have been provided by wi tness E. A. Myers, Jr. , and has been 12' covered by.him-in his testimony.
13 -Q. Turnir.g to Account 930.2, Miscellaneous general expenses, to what do you 14>
attribute.the rather substantial. fluctuations, both up and down, during 15 the recorded and estimated years?
16 A. First let me comment that, by definition,'this account was established
'l7 by the regulatory authorities to accumulate those costs "not provided 18 ~ for elsewhere" In the : Uniform System of Accounts. By its very nature, 19 . i t':I s ' possibly ' the leas t . l ikely cand idate for , t rend ing.
'20' With regard to the specific question, the write-off of major 21' abandoned projects, historically over a five year amortization period,
~
.22 has resulted ln most of the fluctuations to which you referred. Other 23 than the Kalparowlts project, the' write-off for which wili be completed 24- lIn 1980,-we are. proposing a different' approach for estimating costs 25 associated with the cancellation of generating projects which are in 26 ithe planning stages.~ ' Witness ,M. 'D Whyte discusses this approach in his 727 ~ prepared testimony.
28 ' Additionally, the;yearsL1976 and beyond reflect the" continued
..~L8-30-79 I3 (Part)-10
l u
Ray V. Scofield I emphasis on research and development, although it needs to be recognized 2 that this account reflects only those research and development expendi-3 tures of a general nature which are not identifiable with other specific 4 operating accounts. Witness F. A. McCrackin provides the estimates and 5 covers them in his testimony end exhibit.
6 The two areas of e.Mpense I have Just mentioned constitute be-7- tween 70% and 80% of the dollar amounts included in the recorded and es-8 timated years.
9 The estimates relatinc to Corporate Communications have been
-10 provided by witness E. A. Myers, Jr. , and are covered by him.
11- One other area of expense, the net amount of A & G expense paid 12' to or received from others, involved two variations from the basic trend 13- ' procedure. First, beginning in 1978, we have been required to separate
'14 out the employee benefits segment of such expenses and record them in 15 Account 926. Second, because detailed 1974 information was not readily 16 .'available.for trending purposes, I used 1975-1978 as my historical base.
17-
- The balance of the.other misce!Ianeous general expenses in this 18 - account was projected to- Increase en average of less than 5.4% annually 19 between 1978 and 1981.
20 Q. What. types of rents are included in Account 9317 J21i -A. ^ Generally speaking,--there are two types- of rents included in this account.
- 122 One is' additional office-space. ' A large number of our engineering per-
- 23- .sonnel:have occupied rented space In.ar office building near the General 24 Office'since'1973. Secon'd is the rental of telephone cables and radio 25 . and microwave systems.
265 The decrease'in this. account beginning in-1980,-is.due to L27 ~ 'scheduleil completioniof a'new office building-to house the engineering 1281 ,
(personnei mentioned above..
- . [ ,5 >
.8-30-79: 1
.13(Part)-il:
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I w m o W f v e 'ea 4
l Rcy W. Scofield 1
1 l.Q What is incidded in Account 932, Maintenance of general plant?
-2 A.' .This account includes both the maintenance of general office buildings
.3 and the maintenance and repair of telecommunication equipment, including
- 4 cables, microwave, and telephone and power lines.
5 Two new items of expense have been added to this account. One 6 is the maintenance of the new office building for engineering personnel s
-7 .I previously mentioned and-the other is maintenance at our general store 8 -In Alhambra, which previously had been recorded in a clearing account.
Does that conclude your explanation of the amounts shown on Tables 13-A
~
9- q.-
10 and 13-87 1 1. - A.- .Yes, it does.
- 12 J . q. Mr. Scofield, to the extent the material in Chapter 13 is of a factual
'13 ' nature, do you believe it to be accurate?
-14' . A. Yes,.I do.
^
15 : Q. .
Insofar.-as it- is in the nature of opinion or judgement, does it represent c 16. -your best -Judgement?
- 17 JA. -Yes,.it does.
' :18 . Q. - Does this1 conclude your prepared testimony?
19,--A. Yes , J. i t l does.
W I
- A g.
l g.
- 13(Part)-12
=12-7-79; ,e ,
1
SOUTHERN CALiFORN1A ED1 SON COMPANY Prepared Testimony of M. D. Whyte Exhibit No. (SCE-2) , Chapter 13 (Part)
I Q. .Please state your full name for the record.
2 A. My name Is M..D. Whyte.
3 Q. Mr. Whyte, have you previously testified in this proceeding?
4 ' A. .Yes, I have.
5 .'Q. Mr. Whyte, are you also testifying with respect to Chapter 13 of Exhibit No . ' (SC E.-2) - ?
71 A. Yes, l am t'estifying on that portion of Chapter 13, Table 13-A, line 13
. 8 L. /which refers to the abandonment costs associated with cancellation of planned
'9c major projects.
10 Q. Please describe that portion of Table 13-A, line 13, in Chapter 13, deal-11 ing with the abandonment costs associated with cancellation of' planned 12 ~. major projects .
.13[ A. Edison pursues several projects. to meet the anticipated increase in
'14' customer demands. Some of these, projects are cancelled in the planning -
- 15 - andilicensing'. stages due to' reasons which are not within Edison's control.
-16_' The expected; losses due to such cancellations are $5.68 million in 1979,
-17( ;$6.897 millioniin 1980, and $6.955 million in 1981.and are included in 18 . Table .13-A,11ine(13, in~ Chapter 13 19jQ.(Please-list'the!projectsincludedin.estimati.ngcancellationlosses.
~
L 20 L A. : Future ' projects in . the : r'anning stages and_ included : ir. the resource plan -
- 21 are l identified -_Ir, Chart .3-B, Chapter 3 As of. August 1979, Edison has-f 22. fcommi tted funds" to' pursuej the~ following projects included In' the resource
[231 plan,:which can be or' have been cancelled: Balsam Meadows Hydro, California--
~
23-791 13 (Pa rt)-l 6 v
M. D. Whyte 1 Coal, Palo Verde Units 4 and 5 (cancelled on July 16,1979), and Thermal l 2 De N0x (AQMD Rule 475.1). In addition, Edison is pursuing the Harry Allen / )
1 3 Warner Valley coal projects and the Cool Water Coal Gasification Project.
4 Q. Mr. Whyte, insofar as the material presented with respect to the abandonment 5 costs associated with cancellation of planned major projects, as presented in 6 Table 13-A, line 13, in Chapter 13 of Exhibit No. (SCE-2) , is of a 7 factual nature, do you believe it to be correct?
8 A. Yes, I do.
9 Q. Insof ar as i t represents opinion, does i t reflect your best judgment?
10 A. Yes, it does.
11 Q. Does this conclude your prepared testimony?
12 A. Yes, it does.
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, Prepared Testimony of James S. Pignatelli Exhibi t No. (SCE-2) , Chapter 14 i q. Will you please state your name and address for the record?
2 A. James S. Pignatelli. My business address is 2244 Walnut Grove Avenue, 3 Rosemead, California.
4 q. What is your position with the Company?
5 A. . I am Manager of Taxes.
16 LQ. - Please refer to Exhibit No. (SCE-3) for identification, entitled 7 " qualifications of Wi tnesses". Directing your attention to the page 8 entitled " Qualifications of James S. Pignatelli", does that portion of the 9 exhibit accurately set forth your. background, training, and experience?
10 A. It does..
Il q. Are you testifying with ~ respect to Chapter 14 of Exhibi t No. (SCE-2) 12 - for. Identification?
13 A. Yes, I am.
14 " q.' Was the material in Chapter 14 prepared by you or under your supervision?
15- -A. It was.
- 16. Q. Will you indicate briefly the contents of Part~I of Chapter 14 relating 17- to ad valorem taxes, as shown in Tables 14-B, 14-C, 14-D, and 14-E?
18 - A.-
These~ tables contain recorded and estimated data for ad valorem taxes
- 191 . chargeable to l California electric operations resulting from the taxation 20; Lof Company properties located in the states of ' California, Arizona,
?21 .New Mexico, and. Nevada.
.22; ~ q. i . Will; you .please explain the estimated ad valorem taxes charged to e 23 . California electric operations for. California properties, as shown in 14-1 8-2-79.
JEmes- S. Pignatalli l
1 1 Table 14-B7 l
2' A. Ad valorem taxes for 1979, 1980, and 1981, on properties located in 1 3 California, are based upon the best information available regarding the i 4 measure of fair market value and other factors used by the California
-- 5 State Board of Equalization in determining taxable assessed values. In
-6 determining estimated ad valorem taxes, system average tax rates were 7 estimated. For this purpose, the system average tax rates for fiscal tax 8 years 1979-80, 1980-81, and 1981-82 were assumed to remain at the same 9 level as the system average tax rate for fiscal tax year 1978-79.
10- California ad valorem taxes are based on a July 1 through 11 June 30 fiscal year and are charged .to expense in a calendar year on the 12 basis of 50% of the lien date tax of one year and 50% of the lien date 13 tax of the prior year. The assessment ratio for California property is 14 25% of market value, as provided by law.
15 Q. Will you please explain Column 13. " Miscellaneous Adjustmentsd, shown in 16 Table 14-87 17 ~ A. This column ellminates taxes which are not chargeable to electric 18 operations. Included are capitalized taxes, gas and water utility taxes, 19 nonutility taxes, taxes applicable to certain fuel oil . handling facilities, 20 .and miscellaneous items. The taxes applicable to the fuel oil handling 21 facilities are included in-the fuel expenses covered in Chapter 8.
22 Q. WillLyou please explain the estimated ad valorem taxes charged to 23 California electric operations for Arizona properties, .as shown in 24 Table 14-C?
25 A. 1The Arizona Department of ~ Revenue is responsible for determining the 26 assessed value of. utility properties located in Arizona. The assessment
.27. ratio is 50% appiled to the " full cash value" determined by the Arizona.
. 281 -Department of. Revenue. As .In the case of ~ California, estimates are made 14 __8-2-79
James S. Pignatelli 1 based upon the best information available regarding factors used in 2 determining full cash value and regarding tax rates. For purposes of 3- these estimates, tax rates applicable in the various taxing jurisdictions 4 where the Company's properties are located, or to be located, are assumed 5 to remain at the same level as they are for the latest tax year for which 6 information is available; namely, 1978 As shcwn in Column 7 of Table 7' 14-C, the " Average Tax Rate Per $100 of Assessed Value" shows a deciine
- 8 during the period covered in this table. This is because
- although we 9 have assumed the individual tax rates applicable to where property is 10 located semain unchanged from 1978, the additions of new taxable value 11 are occurring in areas where the tax rate is lower than the average.
12 q. . Will you please explain Column 9 " Capi talized Taxes", as shown in Table 13, 14-C7
'14 A. This column summarizes taxes applicable to the Company's share of Palo 15 Verde Nuclear Generating Station Units 1, 2, & 3, which remain under
- 16 construction through the years covered in this table.
17' q. Mr. Pignatelli, will you please explain the estimated ad valorem taxes
~
~ 18 charged to California electric operations for New Mexico properties, as 19 shown in Table 14-D?
'20 -A. The New Mexico Property Appraisal Department establishes the assessed 21- value of the Company's properties located in New Mexico. Assessed value
, 22' of operating properties is equal to 33-1/3% of taxable historical cost 23 less depreciation. Taxable assessed value of property being constructed 24 l equals- 16-2/3% of .i ts' recorded cost at the time of assessment.' The 25- -average tax rate applied to assessed'value for the estimated periods-
'26' . included in Table 14-D is assumed to reFSin at.the 1978 level.
127; Q.' Will you please explain Column 7, " Capitalized Taxes" as shown in Table
'28 14-D?
14-3 8-17-79 .
Jtmes S. Pignatelli
~
1, A. This column summarizes ad valorem taxes applicable to construction of
. 2 pollution control devices at the Four Corners Generating Station in New o
E .3 Mexico.
4 ' . Q. Will you please explain the estimated ad valorem taxes charged to
.5 California electric operations for Nevada properties, as shown in Table 4 6 14-E7 i
- 7 A. - Assessments are mada in Nevada in much the same manner as in California, 8' however, using a 35% assessment ratio applied to market value. Taxes 9 charged to expense are based on 50% of one year's lien date taxes and 1 10 .50% of the prior year's lien date taxes, as in California.
11 Q. _Mr. Pignatelli, in line 4,." Average Tax Rate Per $100 of Assessed Value",
shown in Table 14-E, I note the tax rate for 1978 and subsequent years is
~
I ?. .
4 13 - $2.86,. compared with higher rates in 1976 and 1977. Will you please i
14 explain this?
A.. Provisions were enacted into law during 1979, which changed the maximum 15' 16' ~ Nevada tax rate from $5.00 per $100 of assessed value to $3.64 per $100 17 of assessed value. 'Our estimates-reflect this change. The 1979 change in 18 , Ethe law impacts the rate applicable to 1978 cad subsequent years.-
19.' Q.< Mr. Pignatelli_, how does the California State" Board of Equalization
' ~ ? 20 - . determine' market value for the company's properties in California?
A. . The Board :uses a " uni tary" value approach.- It determines the market' 21 -
, ?22 'value:.of the property the Company ow;.s or uses' within the State -of t
.23; :Callfornia. Unitary' assessed value is-251 of established unitary market iU 24- lvalue. iln' addition, certain properties of the Company are not part of the.
- 25- '!u ni t" . =These are assessed separately.and added to the unitary assessed t, .
E
- 26: 'value-to determine total-taxable assessed value, in' developing market-
, ~27" Tvalue, the' Board takes tinto consideration,. among other factors,--historical .
28 Jcost less depreciation;l capitalized earnings, stock and debt,'and
- ..;g
' 58-17 '
James S. Pignatelli 1 reproduction cost new less depreciation.
2 - q. Do the totals, as shown in Table 14-A, agree with the ad valorem taxes 3 previously discussed, as shown in Tables 14-B through 14-E7 A.- Yes, they do.
~
14
'S . Q. Please indicate briefly the subject matter covered by Part li of Chapter 6 14.
7 A. . Part .E covers all taxes of the Company chargeable to California electric 8 operations, except ad valorem taxes which were covered in Part 1. ,
9 q. Mr. Pignatel'li,-referring to Table 14-F of Chapter 14, will you please 10 explain the computations made in determining the California Corporation 11 Franchise Tax?
12L A .' California Corporation Franchise Tax is computed on the basis of the 13 operating revenues, expenses, and adjustments which are allowable or
- 14 ' required by California law in computing taxable income. The tax is 15 determined by multiplying the resultant taxable income by the existing
~
116 : tax rate.
17 : Q. . Will you please explain;the adjustments you have made to the amount shown
'18 on line' 7,'" Net Operating income Before Taxes Based on income"?
19 A. The first item, " Liberalized . Depreciation in Excess of Book Depreciation",
20- ' reflects 1the dif ference between the depreciation which is allowed for 121 California Corporation Franchise Tax purposes and that which is charged 22 against " operating income. The' difference results primarily from the use 23 of. declining' balance ' depreciation for. tax and straight line remaining life -
24, method for book l purposes'. Additionally, for tax return purposes,'the-25- 1 declining balance method of depreciation-Is utilized for nuclear fuel in 126- . the . reactors. ; For operating 11ncome, .the fuel is. amortized over i ts li fe 127 lon a uni t-of-production method for. batches owned, and lease costs are-
'28 ' charged to fuel expense - for batches .on -financial . leases. .
14-5 2-79 r -- t*-r eawA--w--enrse 1--ew-awv,. ww- ,--s-w -ww- ,
Jtmes S'. Pignatelli I " Interest Charges" are the allovable tax deductions for interest 2 on outstanding bonds, debentures, and short-term debt applicable to l 3 electric operating income. That portion of debt interest applicable to 4 Allowance for Funds Used During Construction (ADC) has been eliminated l
5 from total interest deductible in corputing income taxes on utility 6 operations for recorded years 1977 and 1978 and for estimated years 1979-7 1981. For recorded year 1976, interest on debt included in the 8 computation of income tax on Other income was based on the percent of 9 . nonoperative CWIP to total plant including DJIP. In 1977, the procedure 10 for establishing the ADC rate was changed in conformi ty with new 11 procedures . established by the Federal Energy Regulatory Commission. The 12 new procedure:provides for the calculation of both the debt and equity 13 components of ADC charged to construction work during the year.
14 Consequently, for the years 1977-1981, the interest included in the e
- 15 -computation of income taxes on Other income was the interest component 16 of the ADC charged to construction' work orders during those years.
17 .- This allocation .is appropriate based on the fact that the Company's
'18 nonoperative CWIP is not in rate base. It would be inappropriate to 19 . provide the tax benefit of the interest deduction associated with 20- plant which is not in rate base .to the ratepayer who is neither paying
~
21 for the facility nor' carrying costs associated with the facility. Only 22' when plant is placed-In service and the ratepayer assumes the obligation
- 23. ' of providing for'the carrying costs through rate of return is it appro-24 priate to flow the tax benefit ' associated w* th the interest deduction 25 -through to him.
25 LAdditionally, in order to make the -Co6apany whole, interest 27; fallocation is required because the Company employs 'a net ADC rate. It 28 therefore capitalizes the carrying costs' associated with construction work 14 9-4-79
James S. Pignatelli 1 in progress at a rate which reflects the tax benefit resulting from the 2 tax deduction of interest. As a result, the ratepayer pays a lesser 3 amount in future periods, to cover plant depreciation, income taxes, and 4 return, than he would if a gross ADC rate was used. If a utility employs 5 a net ADC rate, as Edison does, and is p, vented from allocating the tax 6 benefit of the interest deduction to nono,- rating income, then the 7 ratepayer receives the tax benefit of the interest deduction twice. First, 8 the ratepayer realizes the tax benefit in the year the interest expense is
.9 incurred and tax expense in cost of service is thus reduced, and
, . 10 secondly, he receives the benefit in all future periods when he only pays 11
. the net -af ter tax ADC as a component of book depreciation. This is
- 12. obviously an inappropriate result because the ratepayer receives, in total,
, a reduction in rates which exceeds the tax benefit which the utility 13 14 actually recognizes on -its tax returns.
-15 L " Removal Costs" represent the current deduction of the costs of 16 - dismantling, demolishing, or- removing assets in the process of retirement.
17 For book ' purposes, these costs are charged to the depreciation reserve.
J 18 'However,- the income tax laws of both the Federal Government and the State
'19 of Cali fornia~ permit the . current deduction of these items.
12 0 "A&G Expense Capitalized" represents differences in amounts 21- capitalized for book and tax purposes. These differences are 'the result 22 . of. certain statutory deductions allowed for income tax purposes, the major 23( Item being pension costs.
L24 " Taxes' Capitalized" are use taxes, employer payroll-taxes, and
' 25 Lad valorem taxes which have been capitalized as additional costs'to 26- property during' construction but;which are. statutory deductions in the
- 271 (year Incurred for tax' purposes.
28; The. "Ad Valorem Tax Adjustment" results from the - fact that a
'14-7.
7 9-4-79;
James S. Pignatelli i deduction for the current year's lien date tax liability is allowable for 2 tax purposes in the calendar year. On the books, with minor exceptions, 3 one-half of the current year's lien date tax liability plus one-half of 4 the previous year's lien date tax liability is charged against operating 5 income. This adjustiner.t is necessary because the fiscal year to which the 6 lien date app 11es runs from July I to June 30.
7 " Energy Cost Adjustment Clause" reflects the adjustment necessary 8 to reverse the net over/under collection recognized in operating income.
9 For tax purposes, revenues are recognized as taxable income in the year 10 billed; likewise, fuel and purchased power expenses are recognized in the 11 year incurred. Consequently, the over/under collect.on adjustment to book 12 income must be reversed to accurately reflect taxable income. In order to 13 properly match income tax expense with book income, deferred tax account; . 0 14 is. utilized for the Energy Cost Adjustment Clause. The deferred taxes are 15 calculated utilizing the effective 52.68% tax rate for years 1976-1978 and 16 50.86% for years 1979-1981.
17 The result of these adjustments, plus other miscellaneous adjust-18 ments, is a taxable income figure for California Corporation Franchise Tax.
19 This taxable I ' cane is then subject to the statutory rate of 9.0% for years 20 1976-1979 and 9.6% for years 1980-1981. In addition, income taxes are paid 21 as result of operations in Arizona, New Mexico, and Utah, but these are 22 minor in amount.
23 q. Mr. Pignatelli, will you please explain the Navajo Nation taxes to which 24 the Company is exposed?
25 A. The Navajo Tribe of. indians has enacted three separate taxes to which the 26 Company is exposed because of its ownes hip of facilities upon the Navajo
~27 Reservation and its purchased of fuel and energy. from entitles operating 28 - .on the reservation. These taxes, the Sulfur Emission Tax, the Business 14-8 12-8-79
James S. Pignatelli 1 Activities Tax, and the Possessory Interest Tax all will impact the 2 Company if ultimately held valid by the courts.
3- While no meaningful estimate of these taxes can as yet be made 4 in terms of a dollar impact, the Company requests that the Commission 5 consider these -taxes and the potential for using a mechanism similar to 6 the ECAC procedure to allow the Company to recover any costs which may 7- affect operations in the test year.
8 Q. Please explain how you developed the Federal income Tax figures which 9 appear on ' Table 14-F.
10 A. The Federal income Tax is computed by beginning with the taxable income
.11 for California Corpcration Franchise Tax. purposes and making additional 12 adjustments which are applicable for Federal taxable income purposes only.
-13 A difference currently exists between the depreciation amount for 14 California and Federal- purposes. This results because liberalized 15 depreciation was allowable for Federal purposes beginning in 1954 and for 16 State of California purposes beginning in 1959 and because California has
' 17 - adopted dif ferent lives applicable to property placed in service af ter 11 8 1970 than those utilized under the Federal Asset Depreciation Range system.
19- Additionally, California and Utah' Corporation Franchise Taxes and Arizona
~20 and New Mexico income Taxes are used as deductible i tems in computing 21 : Federal income tax. The adjustment for " Preferred Dividend Deduction" 22L Jis allowable for Federal' purposes only.
23 The result, af ter application of these adjustments, is " Taxable 24 Income _for Federal income Tax". For . yea rs 1976-1978, the statutory 25 Federal- tax rate of 48%, allowing for the surtax exemption, and for . years L26 1979-1981, the statutory Federal rate of 46%, allowing for the graduated
'27 . rate ~ benefit, are applied to the taxable income to develop the Federal 28 tax liabili ty. . From the tax thus obtained, the " investment credi t" is 14-9 8-2-79;
l J:mes S. Pignatelli ,
I deducted leaving " Total Federal income Tax". The Investment Credit i
, 2 reflected on Table 14-F utilizes current year flow-through with regard to
- 3. the 4% credit subject to the Company's Section 46(e)(3) election. The 4 additional 6% credit, subject to the Company's 1975 election of section 5 46(f)(2), has been ratably flowed through based on the period of 6 depreciation utilized for results of operations for the plant generating 7 the credit. Additionally, no reduction to rate base has been made for 8 -the. unamortized investment tax credit. This is consis tent wi th the 9 eligibility requirements of the Internal Revenue Code.
10 Q. Referring now to employer payroll taxes, Mr. Pignatelli, please explain 11 lu>< you have made your estimates for .the years 1979-1981.
12- A. Employer payroll taxes cor.sist of Federal Insurance Contribution Act Taxes 13 and Federal Hospi tal Insurance Taxes, Federal Unemployment Tax Act Taxes, 14 and State Unemployment Insurance Taxes. Estimates of these taxes for the 15 . years 1979-1981 are based on -Federal and State statutes with respect to
,16- tax rates and taxable bases and estimates of the number of-Company 17 employees and .their wages subject to such taxes.
18 ~Q. .Mr. Pignatelli, insofar as the material contained in Chapter 14 Is factual 11 9 - in. nature, do you believe it to be correct?
20 A. Yes, I do.
21 _Q. : Insofar. as the material represents opinion, does it- represent your best 22 . judgment?
123 A. Yes,- It' does.
I24 - Q. Does this conclude your prepared -testimony?
25' A.' Yes,-It does.
i
.14-10 i8-3-79
S0JTHERN CALIFORNI A EDISON COMPANY Prepared Testimony of Larry 0. Chubb Exhibit No. (SCE-2) , Chapter 15 1 Q. Will you please state your nane and address for the record?
2 A. Larry O. Chubb. My business address is 2244 Walnut Grove Avenue, 3 Rosemead, California.
4 Q. What is your position with the Southern California Edison Company?
5 A. I am Valuation Supervisor responsible for the Rate Base / Depreciation 6 Division in that Company's Valuation Department.
7 Q. How long have you held that position?
8 A. Since February 1977.
9 Q. Please refer to Exhibit No. (SCE-3) for identification, entitled 10 "Quali fications of Wi tnesses". Directing your attention to the page 11 entitled " Qualifications of Larry O. Chubb", does that portion of the 12 exhi bit accurately set forth your background, training, and experience?
13 A. Yes , i t does.
14 Q. Are you testifying with respect to Chapters 15,16, and 17 of Exhibit 15 No. (SCE-2) for identification, entitled "Results of Operations"?
16 A. Yes, I am.
17 Q. Were those chapters prepared by you or under your supervision?
18 A. Yes.
19 Q. Turning now to Chapter 15, will you briefly indicate the development of 20 the Company's Electric Plant Account 10l?
21 A. The Company's Electric Plant in Sarvice, Account 101, conforms with the 22 Uniform System of Accounts as prescribed by the California Public Utilities 23 Commission and the Federal Energy Regulatory Commission. The Company 15-1 7-31-79
Larry O. Chubb I adopted this system in 1937 and hos made modifications in accorda,ce with 2 revisions published through January 1, 1974.
3 Q. What other Electric Plant Accounts are associated wi th Account 1017 4 A. There are five others. Electric Plant Purchased or Svid, Account 102, is 5 currently not active; Experimental Plant Unclassi fied, Account t'3, was 6 established to provide a separate identity for experimental or -arch 7 and Development type plant. The Cc.npany transferred the applicable 8 amounts from Account 101 as of January 1, 1973, in accordance with Federal 9 ~ Energy Regulatory Commission Order No. 483. Account 103 is referenced in 10 Chapter 16. Accounts 105, 106, and 107, Plant Held for Future Use, 11 Completed' Construction Not Classified, and Construction Work in Progress, 12 respectively, are discussed in Chapter 17.
13 Q. - Turning to Table 15-A, will you indicate briefly what that table reflects' 114 'A. Table 15-A .is a summary of the growth of Electric Plant in Service, 15 Account 101, from 1976 through 1978. Balances at the beginning and end 16 of.each year,' along with gross additions and reti rements, are shown.
17- Intangible and tangible plant are shown separately.
18 Q. Mr. Chubb, insofar as the material in Chapter 15 is factual in nature, do 19 you believe i t to be correct?
20 A. Yes,ll do.
21 ' Q. Insofar as the-material represents opinion, does it reflect your best 22 judgment?.
23 -A~. . Yes, it does.
15 7-31-79
a y SOUTIERN CAllFORNI A EDISON COMPANY Prepared Testimony of Larry ^. Chubb Exhibit No. (SCE-2) , Chapter 16 1 Q. Turning now to Chapter 16, enti tied " Depreciation Expense and Reserve",
2 was this material prepared by you or under your supervision?
3 A. It was.
4 Q. Please indicate briefly what Chapter 16 covers.
5 A. This chapter covers the depreciation expense and reserve for the recorded
~
6 years 1976, 1977, and 1978, and estimated years 1979, 1980, and 1981 7 Q. Will you briefly review the background of the method of depreciation used 8 in preparing the estimates which are included in this chapter? 3 9 A. Depreciation expense is computed using accrual rates based on the straight 10 line remaining life method in compliance with the Commission's Order in 11 Decision No. 49665 on Application No. 33952. Decision No. 49665 included, 12 as Appendix A, a copy of a memorandum of understanding reach .d by the 13 Company and the Commission's staff which outlined the procedure to be used 14 by the Company in its annual review and computation of depreciation 15 expense. Since January 1, 1954, the Company has submitted its annual 16 review of accrual rates and compotation of depreciation expense to the 17 Commission for review according to the procedures of the memorandum.
18 Q. In preparing the depreciation studies underlying the data in Chapter 16, g 19 what procedures have been followed?
l 20 A. The pro- dures outlined in the Commission's Standard Practice U-4 have 21 been followed.
32 Q. Turning now to Table 16-A, will you indicate what that table shows?
23 A. Table 16-A shows ~ the depreciation acoruals charged to expense for the 16-1 12-20-79
Larry 'O. Chubb 1 recorded years 1976,1977, and 1978, and estimated years 1979, 1980, cnd 2- 1981, plus an allocation of the accruals for common plant. Table 16-A )
3 also shows accrials fcr the other depreciable categories, in addition, 4 the impact of San Onofre Nuclear Generating Station Unit No. 2 (SONGS 2) 5 1s indicated in Table 16-A. Column 6 includes the total 1981 accruals 6 with both SONGS I and 2 in operation. Column 7 shows the accrual due to 7 SONGS 2 only, while Column 8 shows the 1981 accruals without the inclusion 8 ~of SONGS 2.
r 9- Q. Please indicate what Table 16-B shows.
10 A.. Table 16-B shows the depreciation accrua! rates for the estimated years 11 1979, 1980, and 1981. Rates shown for 1979 are the current accrual rates, 12 adopted by the Commission in its Decision No. 89711 on Application Nc.
13 57602, for the test year 1979. The Company proposes to continue applying 14 the.;e' rates for the estimated year 1980. The accrual rates for 1981
=15 - reflect the results of a current salvage study, an update of the 1977 16 detailed engineer 'ng estimate of decommissioning costs for nuclear 17 -- generation, and s results of a review of average service lives ano
'18- mortality characteristics for all accounts.
19 Q. ' Were the acrual rates 'shown in Table 16-R used to compute the
- 20 : depreciation expense shown in Table _16-A for estimated years 1979, 1980, 21 andL1981, or were composite. rates used?
.22- A. Compostte rates by class and subclass of plant, derived from the account 23- ra'tes shown in Tabte 16-B, were used to compute depreciation expense 24 because' forecasts of future plant are not made on a prime account basis.
25' ' Q. Turning now to Table 16-c, will you indicate what that table shows?
-26 A. Table 16-C -shcus the computation of estimated 1981 annual depreciation
~
- ' 27.~ rates by pGnt account on .the straight line remaining life basis. - It includes the follo.#ing data by plant account: recorded gross plant in 16-2 --
12-17-79
Larry O. Chubb I service as of January 1,1979; estimated future net salvage in percent 2 and amount; and recorded depreciation reserve as of January I, 1979.
3 These figures have been utilized in deriving the depreciable balances, by 4~ account, of plant book costs still to be depreciated over the remaining 5 Ilfe of the propesty. The depreciable balance, by account, was divided 6 by the. estimated remaining Ilfe for the account to develop the annual 7 accrual shown in Column 10. The annual accrual rate, Column 11, expressed 8 as a percent of gross plant, I.,.,btained by dividing Column 10 by Column 9 1, then multiplying the result by 100.
10 Q.'- What studies were made supporting the estimated future net salvage
- 11. percentages for 19817 l
12 -A. Estimated future net salvage ratios for 1981 were developed af ter a 13 complete review of all plant accounts. Follo dng the procedure outlined 14' in the Commission's Standard Practice U-4, a 10-year historical data base 15 for retirements, gross salvage, and removal costs by plant account
~16 (excluding Nuclear Plant) was projected through test year 1981 using 17 computerized trending techniques. Salvage ratios for each plant account 18 were based on an analysis of these data and were expressed as a percent 19 of plant retirements.
20 -Q. What were 'the results of that study?
21 - A. The study showed that the net salvage expected to be reali zed when plant 22 facilities are retired has continued to decline in recent years. This is 23 attributed primarily to the fact that labor costs to remove ;.! ..t Sve 24 generally risen more rapidly than have salvage values for material. The 25 study thus demonstrated. the need to make adjustments to our capital 26 recovery rate for a number of accounts to reflect the change in net 27 salvage.
16-3 12-17 Larry 0. . Chubb 1
1 q. How were Nuclear Plant net salvage estimates developed for the proposed ,
2 1981' ratios?
3
. Net salvage estimates for San Onofre Nuclear Generating Station Unit No. 1 4 (SONGS !) were based on an update of the engineering study conducted by 3, NUS Corporation in 1977 on nuclear decommissioning alternatives. The 6 - estimate for SONGS 2 was based upon preliminary findings in another study 7 conducted by NUS Corporation to determine anticipated decommissioning 8 costs for that unit. These findings indicate that the cost to
-9 decommission SONGS 2 will be approximately $65 million in :979 dollars, l'0 ' of which Edison's share is estimated at $51.9 million.
11 Q. How does a change in net salvage affect the depreciation rate?
12 A. L'et salvage is the amount received for materials less the labor cost to 13- remove plant when it is retired from service. If the net salvage expected 14' to be received at the time of plant retirement is large, less capital 15 needs to be.recevered each year, i.e., the depreciation rate can be lower.
16 Conversely, if the anticipated net salvage is small, a higher depreciation 17 rate is required to recover the original capital invested in plant. For 18 many years, the labor cost of removing retired plant in a number of
- 19 . accounts has-exceeded the material salvaqe, producing a negative net 20 salvage which is recovered over_the service life of the plaic through an 21~ ; appropriately higher depreciation rate.
12 2 Q. Will you please tell us,what studies were made supporting the estimated 23 average service lives for 1981 and how these were made?
- 24- A. -A review was made of.the average service lives and dispersions for all Estimates -of average service _ life and dispersion were made by
~
J 25- iaccounts.
26- one of three ways, all of which are prescribed in the Commission's
- 27 Standard Practice U-4. First is the forecast method which is utilized 28 where-no significant retirement experience exists, such as is the case-16-4.
12-17-79:
Mr & W 7
Larry O. Chubb I with large steam units. The forecast method is used for most of the
- 2. production accounts. The second method used is judgment. This is used 3 for those accounts where facts are known about the service life of an 4 account beyond what computerized life analysis studies would indicate.
5 The third method used invelves the use of computer programs to simulate 6 plant reccrds. Three such simulation programs are utilized in our 7 analyses. They are the simulated plant balances method (Bauhan method),
8 and two simulated plant retirement methods (Garland and Brennan methods).
9 These programs select the Iowa-type or H-type curve and average service 10 life that most closely simulates the values of either plant balances or 11 retirements at the end of specified periods. The result of these studies 12 combined with what is known about the account and its recent history and 13 near future are used to make an assessment of the average service life 14 and curve type that best describes the account.
15 Q. What were the results of your life analysis study?
I6- ~ A. Our analysis Indicated that while most accounts do not show significant
-17 enough trends to warrant changes in service life and/or dispersion, eleven 18 accounts do warrant such a change. These changes have been reflected in 19 the determination of accrual rates within this chapter. Specifically, ten 20 accounts indicated a general lengthening of average service life and/or a 21 SI'if t towards lower mode curves. Only one account indicated a shortening 22 of average service life. An increase-in average service life will 23 generally lead to an increase in remaining life' which has the effect of 24 reducing the accrual rate. The changes Indicated as a result of the life 25 -analysis study for the ten accounts mentioned had the net effect of 26' offsetting eccrual rate increases that-would o*herwise have occurred due 27 to the salvage study results.
16-5 12-17-79 0
a
. Larry O. Chubb I Q. ;Will you please tell us now what is indicated on Table 16-D?
2 :A. Table 16-D shows the depreciation reserve, by class and subclass of plant, 3 for'the recorded years 1976 through 1978 and estimated years 1979 through ,
4: 1981. The weighted average reserves, shown on the bottom line of the 5 table, are those used in coeputing rate base.
6L 'Q. Turning now to Table 16-E, will you indicate what that table shows?
- 7 A. . Table 16-E is a sunmary of the depreciation reserve and the depreciation 8 acc uals for electric plant in service other than automotive, helicopters, 9 garage equipment, tools and work equipment, power operated equipment, fuel 10- transportation faci.lities, and experimental plant, as recorded for the ;
11 ' years 1976 through! !978 and as-estimated.for the years 1979 through 1981 12 Also shown are composite depreciation rates for those same years, expressed the accrual: on beginning-of-year gross depreciable plant as 13 in two ways:
14- ' a percentage of beginning-of-year gross depreciable plant, and the totcl
. year's accrual as a percentage of average gross depreciable plant for the
~
15 21 6 ' year.
L
~
- 1'7,14 it . Chubb, .' insofar
- as - the material in Chapter 16 is of a factual nature,
' ilb 7 odo'you-believe it to be-accurate?
- ;19; -A. Yes, I do.--
- 20 - Q. L insofar as - it represents opinion,.does it represent your best Judgment?
2( 'A. Yey, it dres.
f a
16-6
. 12-17 -
K
, /
SOUTHERN CALIFORNIA EC .50N COMPANY Prepared Testimony of Larry O. Chubb k Exhibit No. (SCE-2) , Chapter 17 i
1- Q.- Mr. Chubb, you'have previously testified herein?
2 A. Yes, I have.
'3' . Q. . Are you also testifying with respect to Chapter 17, entitled " Rate Base",
- 4. of Exhibit No. (SCE-2) ?
-5 A.. Yes. ;
6 Q. Please turn to Chapter 17 and briefly indicate shat that chapter covers.
7 A. Rate base computations presented in this chapter have been developed on a L8. ~ weighted average original cost basis. Aporopriate adjustments for average-9 : year conditions are included. Recorded figures have been used, where 10 applicable, for the years 1976 through 1978. Rate base for estimated 11; years 1979,.1980, and 1981 has been developed *. wn the most current 112 budgeted plant additions _ data and estimated dates of completion that were .
4 13 available at-the time'this: study was prepared.
14- Q. ' Turning'now to Table:17-A, would you indicate briefly what that table 15 7 shows?.
~161 -A. .~TableL17-A summarizes System . Electric Rate Base developed for the years
- 17. --
1976 through 1981. weighted average rate base totals are: $3.751-billion 18 -- -for 1976; $3.876 billionifor'1977;'$4.092 billien for,1978; $4.216 billion for-1979; $4.529 bili ton for 1980 and $5.381~ billion for 1981. -Table'17-A 119-20 . also shows separately the weighted' average rate base for San Onofre Unl*
21 .No. 2;(SONGS 2), assuming an operating'date of July 1, 1981,-In the amo ,t 22 aof $573 million and an adjusted .wolghted rate. base for the system excluding 23 -
SONGS 2 for 1981, off$4.808 billion.
i 17-1
?l2-17-79 e
. Larry O. Chubb l l
1 I q. Would you indicate briefly what the Fixed Capital component of rate base 2 contains?
3 A. The ' Fixed rapital component of rate base is composed of Electric Plant in 4 Service, Nuclear Fuel, Construction Work in Progress in Operation, and
, l
. 5 'roperty Held for Future Use. The Electric Plant element is comprised of 6 Balance Sheet Accounts 101 and 103 The Nuclear Fuel elecc.-* of Fixed 1
7 Capital consists of Edison-owned nuclear fuel assenblies including accumu-i~
8; late ( amortization. Amounts receiving Allowance for Funds Used Juring 9 Construction are excluded.
4
- liO Construction Work in Progress in Operation for recorded years !
11 1976, 1977, and:1978, and for estimated years 1979, 1980, and 1931, con-12 - tains that portica of plant under construction which is comolete and in 13'- operation and for which no calculation of Allowance for Funds Used During
- 14? Construction, or ADC, is' being made.
15 .Fraperty Held for Future Use is land obtained for future produc-16~ tion, transmission, distribution, and general plant facilities. then 17 ' distribution substation si tes in this . category ;will not be used for con--
' 18 . struction forl three or more years af ter the . rate' base year under study, t
- 19 ' they are excluded. Property Held for Future Use, of course, does not 20 1 receive ADC.
'21 Added to these elements are Net Additions on a weighted average
-basis.
-22 The resultant sum comprises Total Fixed Capital.
- q. What adjustments were made - to Fixed Capital? '
23
.24 7 A; - Adjustments 1to Fixed Capital have been -made in accordance with e.e 25J Convaission's rate-making practice. Reductions are made for ."Cus t,.,ners' 26 - Advances'.for Construction"'and, in accordance with. FERC Order No. 490, 27.. 1" Contributions In Aid of~ Construction" were included with Electric Plant
.28 Land Affset-in the Depreciation Reserve' in; appropriate amounts as of ,
~
39-2-79 2;
Larry O. Chubb
-l January 1, 1974.
2 q. What components comprise the "Vorking Capital" section?
3 A. -The Working Capital section of rate base includes amounts required for 4 Fuel Stock-FossII, Material and Supplies, Fuel Prepayments, and Working 5 Cash. The information used in developing figures for the Fuel Stock-Fossil 6 category is based upon maintenance of a 90-day fuel supply and has been
-7 - escalated to reflect 1980-1981 fuel cost estimates.
~8 f q._ What'Is the reason for including a Working Cash requirement in rate base?
9 A.- A Working ~ Cash requirement is-included in the rate base so that investors
~
10 may be compensated for that portion of the capital which they have supplied 11 to cover the lag in collection of revenues.over the lag in payment of bills 12- for goods and services and other costs of operation and for which they
'13 woul'd not otherwise be compensated.
14 q. iWhat is the basis used to develop Vorking Cash for the years 1976 through 15: ~ 19787
.16 ; A. Working Cash allowances are based on the method used by the Calif ornia 17: -Pubitc Utilities Commission staff-in recent Edison rate proceedings. The 18L . average revenue lag has been developed from a computer. analysis of the s
= 19 Company's recorded experience of lag in revenue collections by class. The
- 20. average expense' lags have been developed-from the Company's recorded ex-21 perience in_ paying its expenses.. Working Cash computations for the year i-22' 1981' are set forth on_ Table 17-B.
23 q. What was yourLsource for the Depreciation Reserve. amounts in Table 17-A7
~
~ 24 -A. The figures are obtained from Table 16-D of Chapter 16. These amounts are D
25' weighted _ averages.
- 26 ' q. Would. you briefly describelthe remaining' reserve -deductions?
Along with Depreciation ~ Reserve, deductions-are also made in rate base for
~
271 -A; L Taxes-Accelerated Amortization a'nd Taxes Deferred-FERC Jurisdiction. Alas 19-2-79 17-3
. r m.
Larry O. Chubb l
1 deducted is the Unfunded Pension Reserve, which is that portion of the l 2 Company's pension liabliity to retired employees which is not separately 3 funded.
4 q. Mr. Chubb, insofar as the material in Chapter 17 is of a factual nature, 5 do you believe it to be accurate?
6 A. Yes.
7 q. Insofar as it represents opinion, does it represent your best judgment?
8 A. Yes, it does.
9 Q. Does this conclude your prepared testimony?
10 A. Yes, it does.
9-2-79 17-4
SOUTHERN CALlFORNIA EDISON COMPANY Prepared Testimony of Rodney L. Larson Exhibit No. '(SCE-2) , Chapter 18 l' Q. Please state, your name' and address for the record.
2 ' A. My name is Rodney L. Larson, and my business address is 2244 Walnut Grove 3 Avenue, Rosemead, California.
4 Q. What is your position with the Southern Ca1ifornia Edison Company?
5 A. Supervising Regulatory Cost Engineer.
6 Q. 'Pleese refer to Exhibit No. (SCE-3) for identification entitled 7 " qualifications of Witnesses". Directing your attention to the page en-8 titled "Qualificaticos of Rodney L. Larson", does that portion of the
-9 exhibit accurately set forth your background, training, and experience?
10' A. Yes , i t does .
.1 1. . Q. Are you testifying in connection with Chapter 18 of Exhibit No.
~12 (SCE-2) ~7 13 - A. Yes, I am.
-14 Q. Was the material prepared by you or under your supervision?
15 A.1 Yes, i t was. '
16: Q. Please Indicate the purpose of your testimony relative to the material 17 contained _in Chapter 18, Mr. Larson.
' 8 c A.
1 The purpose of my testimony is to summarize the material that appears in 19 detailIin Chapters 7 through 17 by relating such results to the rate of 20? return on rate base shown on the table identified as-Table 18-A and to 21 : compare this result to the trend in rett ri over the last ten years. It
'22 1.s intended that the discussion of this material will confirm the validity 23 i
'of Edison's showing; identify the Impact of productivity;:and introduce
_12-20-79 ? 18-1 '
l Rodnsy L. Larson l l
l 1 The concept of attrition. Inadequate recognition of attrition has, in l 2 the past, been the major contributing factor casuing rates, as authorized, 3 to yield a lower level of earnings than that found to be appropriate by 4 past CPUC decisions. It should be kept in mind that the results here 5 are for the total system and they will be translated into the California 6 Public Utilities Commission jurisdiction in Chapter 19.
7 Q. Please turn to Table 18-A and explain what it demonstrates?
8 A. First it summarizes -,11 the material previously presented in detail in 9 Chapters 7 through 17 and expresses the resulting earned return on electric 10 utility operations in relation to the rate base for each of the years. The 11 result is referred to as the rate of return (ROR).
12 Q. What are the important rescits to be found on Tabic 18-A?
13 A. As shown, the return dellars increase by approximately $18 million from 14 the 1976 base level of $298 million to the 1977 level of $316 million, 15 reflecting increases in both retail and wholesale rates authorized in 1977.
16 However, the 1977 return level of $316 million shows an increase of only 17 a little over $4 million going from 1:<7 to 1978, the last year based on 18 recorded information. Edison projects an expected increase of $74 million 19 in return going from 1978 to 1979, but reductions of approximately $18 20 million in 1980, and another $9 million in 1981, excluding the effect of 21 San Onofre, Unit 2 (SONGS 2). The need for an increase in base rates is 22 reflected by the associated rate of return on rate' base which drops from 23 a projected high of 9.34% in 1979 to only 7.62% in 1981.
24' Q. You have indicated that the purpose of Table 18-A is a summary of the 25 results of operations for the total system. Would you please explain what 26 is shown on Chart 18-A?
27 A. Chart 18-A is-a~ graph of the rate of return from the Result of Operations 28 calculations, similar to that shown in Table 18-A, over the past ten years
- 12-15-79 18-2
Rodney L. Larson 1 and includes the projections for 1979, 1980, and 1981.
2 Q. That chart appears to be a complex chart. Could you please being by ex-
'3 plaining what the red and green lines represent?
4 A. The green line is a graph of the rate of return on rate base from the 5 monthly Results of Operations reports as recorded and/or restated. The 6 red line is based on the Resui?s of Operations report infarmation using 7 the average-year concept employed for ratemaking purposes. Ratemaking 8 adjustments are required when the accounting record is to be compared with
~
9- a test year. Such adjustments are consistent with those made in the 10 forecasted test _ year in'ormation, as for example, when a five year average 11 is employed in establishing storm damage expenses. The heavy horizontal 12- dark lines in the years 1969, 1972, 1973, 1976, and 1979 mark CPUC 13 authorized level of rate of return for each of those years. For the years
~
14 1973 and 1976, these were determined to be the 'ower limit of that needed 15 to provide the utility with a Just and reasonable rate of return on its 16- . rate base to enable Edison to attract capital at reasonable cost and not 17 Impair its financial integrity.
18- The heavy dashed black line connecting the end of these lines 19 defines an approximation of the level that might be considered the reason-20' -able level in years Setween rate cases given the CPUC adopted test year 21 rate of return criteria.
~ 2'! Q. - Please indicate what the shaded area titled " Shortfall" represents.
23' A. This dif ferential represents, in terms of a rate of return-differential, 24- ' the dif ference between what has been adopted. by the CPUC as the reasonable
~25 rate of return level and that experienced or projected under existing rates.
26- Q. Please continue.
- 27. A. Turning to Table 18-A and recognizing that over the period shown, Company 28 ; funding for conservation has been at:a level explicitly covered in rates.
12-15-79 18-3
Rodnsy L. Larson i
I and, there' ore, comparisons from year to year should be considered without 2 this c o ponent of cost. When this adjustment is made by eliminating lines 3 14 and 15, changes in year to year OSM expenses excluding fuel and 4 purchased power- costs are $36.7, $62.3, $50.8, $58.9, and $33.3 million 5 for 1976 through 1981. In other words, the increases in cost projected 6 between 1979 to 1981 of $92.2 million is actually less than the increases
.7 experienced on a recorded period between 1976 and 1978, which totals $99.0 8 million. By adding up the OEM expenses, excluding fuel, purchased power 9 .and conservation, then dividing this total expense by the kWh sales in 10 Chapter 7, it is possible to quantify the unit cost increases experiencet 11 and expected apart from the .les increase effect. .The result is that these 12: O&M expenses increased-at a compound rate exceeding 10% between 1976 and 13 1978, while the same expenses are projected to increase at only slightly 14 under 6% during the period. 1979-1981.
Jumping ahead to Chart 19-C, in
-15 Chapter 19, these same 0&M expenses are shown to be increasing at a 16 compound rate of. 9 172% for the 1970-1978 period and 7.253% for the 1974-17 .1978 period. In other words, the estimated expenses projected by Edison's
.18 OEM witnesses, when raken in total, reflect a significantly lower rate of 19 _ escalation apart.from the effect of sales growth than experienced in the L20' recent past.
21 Q. What does such a result indicate to you?
22 .A. I would say:that', in total Edison's-estimates are conservative and ?flect
- 23 .the: desires and: goal.s of-its. management relative to controlling costs.
The~ projected over-all increase of under 6% for these selected 0&M expenses
.25; Lin total is very low when compared to the assumed 7% wage increase ~and
-261 over-al'lI:-inflation exceeding ,7%. _ Such a low figure is possible only due
- 27. ~ -to the inclusion of significant.' increases in product tvity -in- the est! mates 289 for>the test year.
12-15-79' 18'-4L
4 Rodney L. Larson 1 Q. What s'hould the Commission gain from careful consideration of this summary?
2 A. I would request that the Commission take notice of the fact that:
- 3. 1. Edison's estimates in total appear to be very
'4 reasonable, in fact, even low.
5 2. Edison has consistently made a conservative 6 showing in regards to O&M in past cases.
7 Therefore, any reductions to estimates that might be deemed reasonable 8 through the cross examination of Edison's witnesses should in all pro-9 bability be offset by equally logical increases in other' areas. If the 10 Commission allows only a one way street in considering adjustments to 11 Edison's expenses and rate base they will only perpetuate the deficiencies 12 'that have resulted in past test years. Quantification of the total short-
- 13. fall will'be deferred to Chapters 19 and 20 where it can be expressed in 14 terms of the California Public Utility Commission's~ Jurisdiction.
15 Q. Chart 18-A does show a diagram in the projected period that appears to 16 break .this shortfall l' to-n components, would you please explain?
17 A. Both Chart 18-A and the associated text address shortfall in a conceptual
~
18 basis. The components are illustrated and include a combination of:
119 .1. Deficiencies in previous test-years from Commission L20 adopted levels of. cost and revenue.
21 2. Attrition beyond the test year.
22 3 Regulatory lag.
23 4. Non-average year levels of expense.
24- 5. : Rate increases granted by the Commission or 25 revenue differences resulting from changes in 26' _ customer use patterns.
'27 - 6. -Productivity increases or decreases.
l : 28 ' Q. -What table'or_ chart includes _the' detail of the projected or estimated part
< .12-15-79' 18-5
Rodnty L.~Larson 1 of this chart which extends beyond 19787 2 A. This part of Chart 18-A is expanded to a larger scale in Chart 19-A for ;
3l the CPUC jurisdiction. I l
4 .Q. Please explain what you mean by deficiency.
5 A. As defined in the text accompanying Chart 18-A, it is the effect of all 6 factors in a test year including regulatory lag which cause the rate of return to be different from that authorized by the regulatory agency. It 8 is identified on .he chart as the difference between the red ROR curve and
'9 the heavy dark line.- In 1976, the displacement appears to be approximately '
10 86' differential points in the ROR, while in 1979, it is projected to be 11 somewhat less at 26 differential basis points.
12 Q. Could you 'please explain the ' reason for this displacement or deficiency as
~
you refer to it?
14 A. Yes. The tables in the text on pages- -and compares test years
.15 ' 1976 and 1979 as adopted and as recorred (1976) and estimated for average 16; ratemaking considerations (1979)', Since 1979 is not yet recorded we have 17 -- -used our-estimate in lieu of the recorded number. .The difference between 18 _the adopted level of expenses and revenue demonstrates the optimism of the 19' CPUC, an optimP_m that' to some . extent was shared by the Company at the time 20 it made its own' higher estimates. As shown for test year:1976, the adopted
~21. (expenses excluding Fuel & Purchased Power and income Taxes were low by -
122L fapproximately $43 million, while-revenue for the CPUC jurisdiction was.
23/ overestimated by approximately $40 million. At'the same time, the rate
'24 base'on a recorded basis was somewhat less than that'used in developing
- 25 " authorized rates by $51 million.
- 26 ' iQ.- LTo'shatia're' these three errors attributed?
[27A. The-primary reason.that recorded revenue fell short of.the adopted level-
~
- 28; :in'1976 is-that the final.ratefincrease.of $45 million was not granted by 112-15 '18 '
aw i
l Rodney L. Larson L 1 the CPUC until December of 1976, which guaranteed that the authorized i
2 rate of return could not be met in the test year. The expense estimates 3 are more difficult to explain since at the time of the final decision, 4 the CPUC had the advantage of knowing what the 12 months-ended expenses 5 ' and rate base were as of October or November of 1976.
6- Q.- Was the difference due to disallowances of certain expenses?
7 A. To a limited extent that is true, but the total of all exclusions amount 8 to no more than $2 million.
9 Q. Could you make a similar analysis with respect to 19797 11 0 A. Yes, although it should be remembered that the books are not yet closed 11 for 1979 However, I have made a comparison using Edison's current 12 estimate of 1979 expense, revenue, and rate base with that authorized in 13 the latest Decision No. 89711. The results show that estimated 1979 14 revenue exceeds that adopted by the CPUC by approximately $38 million, 15 that expenses excluding Fuel & Purchased Powcr and income Taxes exceeded 16 the level adopted by approximately $38 million, and rate base exceeded the adopted level by approximately $47 million.
18 -Q. Can-the sources of these differences be Identified?
19 A. I believe that several contributing factors can be isolated. First, the 20- revenue exceeded that estimated due in part to the non-tariff scheduled
.21. sales, especially those revenues which are described as Other Operating 22 Revenues. Some of this was anticipated by the Commission in setting rates.
23- The Commission reduced the' revenue requirements by over $5 million due to
.24' ' higher levels of Other Operating Revenues which were attributed to;the
-25 reconnection charge, etc. 0ther revenue effects are due primarily to more 26 revenue'being derived'from the larger customers than anticipated. One
~
6 27- additional revenue factor which has not been adjusted 1for Is the Tax J28 A'djustment Clause Impact. By the beginning of 1979, there existed a 12-15-79 .18-7
=_ .-
Rodn::y L. Lcrson l
I negative balance in this account as a result of overcompensation in 1978. 1 I
2 In order to balance this credit, the 1979 rate level was set higher than 3 it would otherwise have been. The result is that part of the apparent 4 additional revenue in 1979 is really to cover this previous expense 5 component. Reasons for the expense shortfall is primarily due to the 6 CPUC adopting the low expense estimates of the CPUC staff. A similar 7 explanation app!!es to the rate base estimate.
8 Q. Mr. Larson, what conclusion do you draw from this analysis and you ex-9 perience with previous rate cases?
10 A. I believe they show that Edison has been conservative with respect to 11 expectations of future levels of expense and rate base, yet the CPut has 12 continued to trim even these conservative estimates which results in the 13 inevitable inability of the Company to achieve the authorized rate of 14 return in the test year. Even if the Company's estimates had been adopted, 15 the rates authorized would have resulted in under-recovery of the cost of
'16 service in the test year but the resulting de'iciency would have been less.
17 in the years following the test year, additional attrition resulting from 18 inflation seriously aggravates an already difficult situation, with the 19 result that it is practically impossible for the Company to achieve the
'20 authorized rate of return under the procedure presently used for setting 21 rate levels.
22 q. Mr. Larson, prior witnesses covering Chapter 7 through 17 have mentioned 23 the various productivity programs and efforts that have been taken into 24 account in making their estimates, would not these programs offset the 25 -attrition somewhat?
26 A. Yes, they reduce the effect af attrition to a level lower than would 27 :otherwise occur except for Edison's continued efforts in serving its 28 customers more efficientiv within the constraints set by regulatory 12-15-79 18-8
Rodney L. La rson I agencies exercising jurisdiction over various aspects of Edison's 2 operations.
3 Q. Would you recap the effect of the over-a* i productivity ef fort?
4 A. When the operating expenses are viewed on a per unit (kWh) output basis, the 5 effect of productivity can be seen. In all cases, with the exception of 6 certain production expenses, the unit costs from 1976 through 1981 show 7 an upward slope of the general productivity index.
8 Q. Would you please explain what a " general productivity index" is?
9 A. Reduced cost per unit output reflects increased productivity, however, 10 rather than use the decrease directly as indicative of the ef fectiveness il of productivity, it was determined that confusion would be reduced by 12 associating a positive or upward sloping function with productivity, 13 therefore an index which is simply the Inverse of the unit cost function 14 was used, in other words, an increase in the general productivity index 15 means increased productivity and a decrease in the index would mean that 16 productivi ty is decreasing.
17 Q. Can you list the index results for the various components of expense, please?
18 A. Yes, from Table 18-B, Production shows an over-all decrease of 2.18% per 19 year in the index; Transmission a 6.69% increase; Distribution a 4.65%
20 increase; Customer Accounts a 1.31% increase; Administrative and General a 21 3.05% increase in the productivity index.
22 Q. Would you please explain the apparent loss in productivity in the area of 23 production?
24 A. Many factors contribute to such a result, including tha fact that due to 25 deferrals of new capacity, older units are being called on to provide capa-26 city at a correspondingly higher cost. Also, programs aimed at increasing 27- the capacity factor of the more cost ef ficient fuel units result in savings 28 in the fuel area but at a cost of higbar maintenance in the short run.
. ?
12-15-79 18-9
Rodn2y L. Lcrson I Q. Table 18-B delineates the general productivity index by component, of 2 labor and the remaining 5 .rtion of the expense. Could you esplain m6at 3 conclusions can be reached based on that tab le?
4 A. The labor productivity as measured by the general productivity index exc eeds 5 3t per year and is even higher in the test years which eeplains the reason 6 for the low escalation in over-ali costs included in this showing?
7 Q. 15 the general productivity index all that is needed to demonstrate the 8 effectiveness of Edison's productivity effort 7 9 A, tp Testinony by previous witnesses indicates the planning of specific 10 programs aimed at improving productivity and the testimony of Mr. Horten 11 underscores the coenitrent of Edison's nanagement to the ef fort of produc-12 tivity improvement.
13 Q. Mr. Larson, insofar as the material contained in Chapter 18 i s fac t ua l in 14 nature, do you believe it to be correct?
15 A. Yes, I do.
16 Q. Insofar as the material represents opinion, does it represent your best 17 Judsment7 18 A. Yes, it does.
19 Q. Does this conclude your testinony?
20 A. Yes, it does.
.9-5-79 18-10
SOUTHERN CAllFORNI A EDISON COMPANY Prepared Testimony of Rodney L. Larson Exhi bi t No. (SCE-2) , Chapter 19, Parts 1 - lll 1 Q. Please state your full name for the record.
2 A. My name is Rodney L. Larson 3 Q. Mr. Larson have you previously testified in this proceeding?
4 A. Yes, I have.
5 Q. Mr. Larson, are you also testifying with respect to Parts d, 11, and ill 6 of Chapter 19 of Exhibit No. (SCE-2) for identitication?
7 A. (es.
8 Q. Directing your attention now to Chapter 19 of Exhibit No. (SCE-2) 9 were Parts 1-1ll of that chapter prepared by your or under your 10 supervision?
11 A. They were.
12 Q. Please briefly indicate what Part I of Chapter 19 shows.
13 A. Part i develops first the cost allocation between FERC and CPUC Jurisdic-14 tions and then continues a more detailed allocation of the CPUC Jurisdic-15 tional costs to the six retail customer groups. The Jurisdictional 16 separation including ECAC related revenues and expenses is summarized on 17 Teble 19-A, Sheet I of 2. Table 19-A, Sheet 2 of 2 summarizes the jurisdic-18 tional separation excluding relateo ECAC revenues and expenses. The six 19 customer group allocation is summarized on Table 19-B, Sheets 1 through 4.
20 Sheets 1 of 4 and 3 of 4 include ECAC related revenues and expenses while 21 Sheets 2 of 4 and 4 of 4 exclude these revenues and expenses. Table 19-A, 22 Sh.te t i of 2, begins with the estimated revenues, expenses and rate base 23 for the test year 1981, shown in Table 18-A, Sheet I of 2, Column 8. Before 24 an allocation of costs can be made to resale and the six CPUC retail customer 25 groups, it is necessary to exclude from system total the costs of facilities, 26 revenues, and expenses associated with non-customer group service.
27 Q. What comprises the non-customer group service?
19 (1 -l i i)- 1 12-19-79
. - - , . .--_ _ _ . _ _ _ . - _ ~ . - . - . - - - . _ _ - . . _ _ ~ . . . . _ - - - - _ . . ..
Rodnsy L. Larson 1 A. Basically, tSese are contract, interchange, nonelectric service ievenues, -
l 2 and certain special rate schedules.
I 3 Q. What special rate schedules are you referring to?
4 A. . Fringe accounts and service to Catalina Island. I i
5 Q. Will you please explain what is contained in Column 3, Pacific intertic?
~
6 A. The Pacific Intertie, as far as Edison is concerned, is the transmission
]
l 7 system used to transmit energy between the Pacific Northwest and the f
8 Edison system. The Pacific Intertie is made up of two 500 kV AC lines 9 and one 800 kV DC line from the Pacific Northwest, in addition to trans--
10 mitting power to and from the Edison system for the benefit of Edison's
-11 customers, the two AC lines are used to provide EHV transmission service 12 to the United States Bureau of Reclamation and the State of California
- 13 Department of Water Resources. The figures appearing in Column 3 are 14 Edison's portion of the Pacific intertie revenues, costs, and rate base 15 -Items that are allocated to such public agencies' transmission service 16 under the Company's EHV contract with these pubile agencies. As shown in
! 17. this column, the rate of return is projected to be 4.48X, for test year ;
.18 1981.- This represents a deficiency of approximately $1.1 million in 19 . revenue requirements given the requested rate of return of 11.18%. This 20 deficiency represents unrecoverable costs borne by Edison's shareholders.
. -21. Q. Will you please explain the.next four columns?
22 A.' Column 4, labeled "Other Electric Revenue", consists of revenue-producing 23: assets which do not. involve the sale-of electric energy. Such items would
.24 include, among others,-added facility revenue, joint pole rentals, service 25: -establishment charges, and rentals of Edison transmission rights-of-way.
- 26 'The rate of return on these facilities is' assumed to be equal to the rate 27 . of ' return .on the total system, 'scluding Santa Catallna Island. ,
28~ Columns 5 through 7 involve the sale of electric energy.under.
19(1-111)-2 l?- M-79
,aw , _ _- . , - . _ - - _ . , - . . . . . . . - _ . . . . . . . _ ~ . , _ _ . _ _ _ . . - . , - .- ,
't i
Rodney L. Larson 4
I various contracts. These would include the State Water Plan and Fringe 1
2 contracts. The revenues from these contracts are used as a direct offset 3 to system costs.
4 Q. How is the cost allocation between jurisdictions made?
5 A. First, the Total To Be Allocated, Column 8, is calculated by subtracting 6 Columns 2 through 7 from Column I.
7 Second, the amounts in this column are then assigned to the 1
8 following two systems: the Power Pool System, which is further classified 9 into Coromodity - Column 9, and Demand - Column 10, and the Distributing 10 System - Column 11. The Power Pool System consists of expense and rate 11 base related to all generation, including fuel handling facilities, and 12 all transmission facilities down to and including 66 kV lines. Such ex-13 pense items would include fuel and purchased power costs, operation and 14 maintenance costs related to production and transmission facilities, and 15 all associated overhead items, namely, depreciation, taxes, and return 16 .related to production and transmission facilities. The Distributing
- - 17~ System includes all' facilities below 66 kV. Such expense itens would 18 Include the operation and maintenance accounts for Distribution, Customer
.19 Accounts, and Customer Service and Informational, and all associated i
20' overhead items related to distribution facilities. There is an allocation j
21 to both the Power Pool and Distributing Systems of costs related to Rate
~ '
22 Base - General, Rate Base - Working' Capital, Depreciation - General, Misc.
23 -T6xes.- Other, and Administrative and General expenses.
24 Q. How is the classification of Power Pool System costs determined in Columns s,
25' 9 (Commodity) and to (Demand!'
26 JA. . The'first component,-Commodity, is made up of 100% of the Production -
'27 Fuel expense, that portion of the Purchased Power expense computed by the 12 8 energy charge, and certain items.from the Production - Other expense, as
. '19(1-111)-3 12-15-79
Rodnay L. Larson 1
I . explained below. Fifty-two percent of all Hydro costs are assigned to !
,. \
2 Commodity, including Hydro Operation and Maintenance expense, Adminis- i 3 trative and General expense, Depreciation, Ad Valorem Taxes, income )
b Taxes, Return, and the ftate Base associated with Hydro. The 52% factor
. 5 applied to Hydro has been developed from the ratio of kilowatthours 6
produced under adverse year conditions to the kilowatthours produced under 7 average year conditions.
8 Also included in Commodity are 50% of Steam Account 510 (Mainte-9 nance supervision and engineering) and 100% of Steam Accounts 512 10 (Maintenance of boiler plant), 513 ,Aaintenance of electric plant), and 514 II (Maintenance of miscellaneous steam plant). In like manner, included in 12 Commodtty are 50% of Nuclear Account 528 (Maintenance supervision and 13 engineering) an'd 100% of Nuclear Accounts 530 (Maintenance of reactor I4 plant),.531 (Maintenance of electric plant), and 532 (Maintenance of 15 miscellaneous nuclear plant).
16 q. Are ihere some' specific facilities allocated to Commodity?
r l
17 A. Yes. . Costs associated with Fossil Fuel Handling Facilities including the 38' . fuel' oil transportation and storage system and the coal and ash handling i
I9' facilities, are assigned to Commodity. These costs include the allocated 20 portion of Administrative and General expense, Depreciation, Ad Valorem 21 Taxes, Income Taxes, Return,-and the Rate Base.
_22 Q. What costs are classified as Power Pool System - Demand, Column 107 ,
- 23 A. The remainder of all Production :Other expense; Purchased Power expense; i 24 Production rate base; all Transmission expense and rate base; and the 25~ associated overhead items (nanaly, Administrative and General, n
, - 26 D'epreciation,' and Taxes - Other) related to 'the above mentioned Production
.27 .and Transmission rate base.
28 ' - q What costs are included -in Column ' 11, the Distributing System column?
19(I-111)-4 12.15-79
Rodney L. Larson I A. The Distributing System includes all Os. and associated overhead costs ,
2 related to Distribution rate base together with the operating expense 3 accounts for Customer Accounts, and Customer Service and Informational.
4 in addition, there is an allocation to the Distributing System, portions 5 of Rate Base - General, Rate Base - Working Capital, Depreciation -
6 General, Misc. Taxes - Other, and Administrative and General Expenses.
7 Q. How were income Tax and Return allocated?
8 A. Income ' lax and Return were first allocated to Power Pool and Distributing 9 System in proportion to rate base, for system total, excluding Santa 10 Catalina Island. Noncustomer group income tax and return were then 11 subtracted from the totals to arrive at the income tax and return for 12 Power Pool System, Column 9 and Column 10, and for Distributing System, Column 11.
13 14 Q. What is the next :?-o in the cost allocation procedure?
15 A. After the total to be allocated to customer groups is assigned to 16 Commodity, Demand, and Distributing System, all Commodity costs, Column 9, 17 are allocated between Resale and Other Than Resale o,'. the basis of the 18 ratio of the annual kilowatthours ai Power Pool level of each to the total 19 Resale and Other Than Resale kilowatthours at power poot level. It is 20 estimated that'for 1981, Resale will account fcre7.153% of the total sales i
21 at Power Pool level.
22 Q. How were Demand costs allocated?
23 A. Demand costs, Column 10, have been allocated between Resale and Other Than 24 Resale en the basis of a 12-month weighted average peak responsibility 25 method. Recarded data for 'y72 through 1978 was available for defining 26 the.contriaution of resale at the time of the monthly system peaks. Based 27 on a linear regression of recorded data, a percentage of Resale to total 28 net main system was developed at the Power Pool level of demand for the 19(I-111)-5 12-15-79
1 Rodnsy L. Larson l l
l 1 estimated year. In this study, it is estimated that Resale will account
! 2 for 7.882% of the demarcd at the Power Pool level in 1981, l
3 Q. What adjustments have yas made to this power pool cost of service pro-4 cedure that warrr further explanation?
5 A. As I have previously cted, the Power Pool system extends to the end of 6 the 66 kV vrd ,e level. In the past, there has not been significant ;
7 sales to customers above that level; however, currently there are signi-8 ficant resale sales at the 220 kV level, which warrant an adjustment to l
9 our previous cost of service procedure. The adjustment is needed to 10 correctly allocate 66 kV facilities to wholesale and retail sales. In !
11 1981, the adjustment requires a transfer of approximately $8 millio.'.
12 worth of rate base out of the resale cost of service into the retail cost
- 13. -of service. in' addition, 0 & M and overhead costs related to the $6
-14 million rate ba'se have been transferred.
15 Q. How were the Distributing System costs allocated?
16.[A. Primarily, the cost of the Distributing System allocated to Resale has 17; been a direct assignment of costs' associated with the Distribution
-18 facilities used to serve the Resale customers.
19 Q. 'How are the . totals for each jurisdiction developed?
'20
' A. The summation of the Commodity,' Demand, and Distributing System alloca-21 'tions to Resale appears in Table 19-A, Column 12, and To Other Than Resale
- 22. In: Column 13.
23- The Jurisdiction totals are the accumulation of prior alloca-
. 24 ' tions. . The FERC Jurisdiction Total, Colume 14 of Table 19-A, is made
.25 ,up of Pacific Intertie - Column 3,-Pooling Contracts - FERC - Column 7, 26 and To Resale - Column 12.-- The CPUC Jurisdiction' Total, Column 15. Is s27. made up of Santa CaNina ; Island' Column 2, Other Elect.-Ic Revenues -
28 -. : Column 4, Fringe - Column -5, Pooling -Contracts - CPUC - Column : 6, and To u .. . 19(1-1 IIP 6 12-1979~
. . - - - ~_ - .- .__. _. - _ _ - _ . - _ . - . - . _ . _ . . .
- - Rodney L. Larson 1 Other Than Resale - Column 13 j 2 q. Mr. Larson, please describe what is shown in Table 19-A, Sheet 2 of 2.
3: A. Table 19-A, Sheet 2 of 2, shows the jurisdictional separation excluding ;
i 4 ECAC revenues and eaperses. As shown in Column I, Operating Revenues have [
! 5 been adjusted for the e amoval of approximately $2.5 billion in ECAC
^
6' revenues. In addition, fuel and purchased power expense, uncollectibles, 7 and franchise fees have been adjusted to reflect this revenue loss. Fringe !
8 (Column 5) has also been -',;s,ted to exclude all related ECAC revenues and 9 expenses.
1
- 10 Since ECAC is not applied to resale, all adjustments were made 11 To Other Than Recale and CPUC Jurisdiction (Column 13 and 15).
- 12. Q. Turning now to Table 19-B of Chapter 19, Cost Allocation Between Customer 13 Groups, would you briefly describe that information?
i
' 14 A. Table 19-B is the allocation of costs to the six customer groups under the i
15: Jurisdiction of the California Public Utill ties Comission. The summary 16 of that allocation is found on Table 19-B, Sheets I through 4
- 17 ~ Q. Please describe what is shown in Table 19-B, Sheet 1.
18 A. Table 19-B,nSheet 1 o f 4 shows the allocation of Other Than Resale costs 19- (including ECAC revenue and expense) under the present retail customer.
20 groupings, which consist of Domestic; Lighting and Small Power; Large Power 21 customers with demands betwaen 200 - 1,000 kW; the TOU customer group with 22 demands of 1,000 kW and above* Agriculture and Pumping, and Streer t.ght-23 :Ing. The Total To Be Allocated - Column-1, is the same as To Other-Than-24- Resale - Column 13, in-Table 19-A, Sheet 1 of 2. The allocations of classi-
-fled costs in Table 19-A,tSheet l'of 2, To Other Than Resale becomes the 25: i
!26 basis of the cost allocation to the six customer groups. The six customer
'27' -group portion of the Power Pool System classified as Commodity is allocated 28: .to the customers' group on an energy or.kilowatthour basis.
The six 19(1-i l lF7
~12-15-79
_ . . . . - . _. . . _ . _ . ~ - _ ._ ..
Rodnay L. Larson i i customer group pertion of the Power Pool System classified as Demand is {
2 allocated to the customer groups on a 12-month weighted average peak 3_ responsibility method. Distributing System costs and rate base were 4 allocated to Commodity, Demand, and Customer components based on both 4
5 prior allocation of costs and direct studies which weight the number of
'6 customers among customer groups.
4 7 Q. What does Table 19-8, Sheet 2 of 4 show?
8 A. Table 19-B, Sheet 2 of 4, shows the allocation of the Other Than Resale 9 costs under the present retail customer groupings, modified to remove all 10 ECAC revenues and expenses. The Total To Be Allocated, Column 1, is the 11 same as To Other Than Resale - Column 13, in Table 19-A, Sheet 2 of 2.
t 12 q. - What does Table 19-B, Sheet 3 of 4 show?
13 A. Table 19-B, Sheet 3 of 4, shows the allocation of Other Than Resale costs 14 (including ECAC revenue and expense) under the proposed retail customer 15 groupings. The difference between the proposed and present retail custo-16 mer groupings is that the TOU customer group is proposed to contain cus-17 tomers with 500 kw demands and above, instead of 1,000 kw demands under 18 present customer groups. Commensurate with this, the Large Power c'estomer
,19 . group contains customers with demands from 200 - 500 kw unBer proposed 20 customer groups instead of'200 - 1,001 kW under present customer groupings.
21 -There is also a slight shif t of Agricultural and Pumping customers with
'- 22 demands of 500 kW and above into the TOU customer group under the oroposed 23 scheme.-
24 ~ Q.. Please describe Table 19-B,' Sheet 4.of 4, 25 A. Table '19-B, Sheet 4 of 4, shows the allocation of Othe r Than Fesale costs
.26 under thel proposed retail customer groupings, modified to removal all ECAC' revenues and expenses. The cost allocation methodology is the same 28 as t' hat'used in the previous tables.-
19(I-i l l)-8 12-15-79
Rodnsy L. Larson I Q. What results do you obtain from the cost allocation study shown in Table 2 19-B, Sheet 1 of 47 ,
3 A. Under presently effective tariff s for present customer groups at the '
4 estimated level of sales, revenues, expenses, and rate base estimated or 5 the test year 1981, the over-all composite rate of return for the six 6 customer groups under California rublic Utilities Commission Jurisdiction 7 would be about 7.6%.
8 Considered individually, the rate of return for the customer 9 groups as shown in the table would be: Domestic, 1.9%; Lighting and Small 10 Power, 13.2%; Large Power, 10.0%; TOU,' 15.3%; Agricul tural and Pumping, 11 7.7%; and Street Lighting, 4.7%.
12 Q. What results do you obtain from the cost allocation study shown in Table
- - 13 19-B, Sheet 2 of 4?
14 A. Under both the presently effective tariffs excluding ECAC revenues and 15 expenses, the present customer groups, the estimated level of sales, and 16 rate base for the test year 1981, the over-all composite rate of return
~
17 for the six customer groups under Californla Public Uti1itles Commission 18- Jurisdiction remained about 7.6%.
19- Considered individually, the rate of return for the customer
.20 groups as shown in the table would be about: Domestic, 4.3%; Lighting and 21 Small Power, 12.2%; Large Power, 8.2%; TOU, 11.4%; Agricultural and Pumping, 22- 6.5%; and Street Lighting, 4.7%.
23 Q. What results do-you obtain from the cost allocation study shown in Table 24 19 8, Sheet 3 of 4?
- 25. A. Under prerently effective tariffs using the proposed customer groups, the
~
' 26~
rates.of return for the six customer groups are approximately as follows:
27~ Domestic, s'.9%; Lighting and Small Power, 13.2%; Large Power, 9.1%; TOU, 28 14.3%; - Agricultural and Pumping, 7.7%; and Street Lighting, 4.7%. Under
-19(1-11I)-9
.12-19-79~
Rodney L. Larson 1 the proposed rates contained within this filing, the rates of return are 2 approximately as follows: Domestic, 5.6%; Lighting and Small Power, 18.0X; 3 Large Power, 13.2%; TOU, 16.5%; Agricul tural and Pumping, 11.5%; and Street 4 Lighting, 8.0%.
5 Q. What results do you obtain from the cost allocation study shown in Table 6 19-B, Sheet 4 of 47 7 A. Under both the presently effective tarif fs excluding ECAC revenues and 8 expenses and proposed customer groups, the rates of return for the six 9 customer groups are approximately as follows: Domestic, 4.3%; Lighting 10 and Small Power, 12.2%; Large Power, 7.5%; TOU, 10.9%; Agricultural and 11 Pumping, 6.5%; and Street Lighting, 4.7%. Under the proposed rates con-12 tained within this filing, the rates of return are approximately as fol-13 lows: Domestic, 8.0%; Lighting end Small Power, 17.0%; large Power, 17.5%;
14 TOU, 13.1%; Agricultural and Pumping, 11.3%; and Street Lighting, 8.0%.
15 Q. The rate of return by group varies significantly between the calculation 16 at the total cost level and that with ECAC revenues and expenses removed.
17 To what is this difference attributed?
18 A. The difference is the result of the mismatch of ECAC revenues and expenses 19 at the customer level. Since Domestic lifeline customers are subsidized 20 in their ECAC billings, the spread of ECAC expenses and ECAC revenues to 2! all customer groups do not balance by customer group. In addition, ECAC 22 treats all customers as though they received energy at the same voltage 23 level. If one customer takes service at 66 kV while another at 220 kV, 24 this treatment causes the first customer to subsidize in part, the losses 25 for the low voltage customers. These two factors combine to increase the
- 26. rate of return to non-lifeline customers and reduce 'the rate of return to 27 lifeline and the Domestic group in total.
28 Q. Would you briefly indicate the need and the application of the Net-To-Gross 19(1-111)-10 12-15-79
Rodney L. Larson
(
1 Multiplier?
2LA. In developing the gross revenue increase needed to develop a specific rate 3 of return, the first step is to develop the requirtd net revenue Increase 4I whicn is determined by subtracting the return amoun: at present rates 5 from the return amount required to obtain the target rate of return. The 6 target rate of return is equal to the cost of money plue .he attrition 17 allowance factor of 0.4%, and the net revenue is developed by multiplying l
! -the rate bate by the target ROR. The next step is to develop the gross 9 ' revenue increase nt;eded to produce this not revenue increase, considering
- 10. Incremerital tar.es, franchise fees, and*uncollectibles. This is accomplished 11 by;use of a net-to-gross multiplier. The development of this factor is 12 _shown in the text in Chapter 19.
l .13 Q. -Turning now to Part til of Chapter 19, would you describe its contents?
l
-14 A. 'Part 111 of Chapter 19, graphically and editorially describes the rate of 15 return shortfall the Company has experienced over the recorded years 1966 l- 16 through -1978 (See Chart 19-A), and estimated into 1979 through 1981. The 17 two major reasons for this shortfall is what I have called deficiency and 18 ~ a t t ri t i on. Deficiency 11s defined ~as both an over-estimate, by the-h 19- Commission, of( the Company's - test year earnings at existing rates 20 and - the- result.of untimely Commission decis ions (regulatory lag).
21 The Commission has recognized regulatory lag and has formulated a 22- regulatory ' lag plan which will help l offset part of the deficiency. On the 23_ 'other hand,.the Commission has persisted in overstating the Company's test
~
24: -year. earnings at existing rates, thereby, ~ perpetuating the deficiency 2
25' ' Problem. The Commission.could help alleviate this-problem by recognizing 26 the fact, that from fan his torical perspective, even- the . Company's test L27: Lyear: estimates. of. earnings at exis ting rates have tended- to overstate .
- 528_ (such earnings and,?thereby,
- give greater weight to the Company's Results
' 19 (I- 1 l l)- 11 L; 12-15-791 a
,,,a- ,,e,
Rodnay I.. Lcrson i of Operation's estimates. '
i 2 q. Turning to the second component, which you referred to earlier as 1
3 attrition, to what do you attribute th s impact?
l 4 A. Attrition results from increases in financing costs, expenses, and rate
- 5 base beyond the test year not accompanied by offsetting revenue increases 6 sufficient to allow the Company to earn it's authorized rate of return 7 on rate base. Attrition is primarily the direct result of factors beyond 8 the control of the Company, such factors would include; the effect of 9 general inflation, additions to rate base which reflect both inflation 10 and increased environmental costs, increased regulatory costs, and i1 increased embedded costs of senior carital made necessary by both inflation 12 in capital costs and the need to finance dditional capital additions to 13 enable the company to satisfy the increasing energy requirements Of t1e 14 public. Such costs are offset somewhat by productivity increases. Both 15 attrition and deficiency are graphically illustrated on Chart 19-8. This 16 chart shows that out of the Company's total request of $340.2 million, 17 $18.9 million was the result of the 1979 test year deficiency and $226.4 18 million was due to attrition. Out of tne total attrition amount, $171.4 19 million was due to operational attrition and $55.0 million was due to 20 financial attrition. To overcome the impact of attrition in the year 21 beyond the test year 1981, we have included an attrition allowance to be 22 added to the Company's total request for rate relief which is in addition 23 to the 15.0% Return on Cocanon Equi ty requested 'for test year 1981.
24 q. What is the basis for such an attrition allowance?
25 A. The attrition allowance was calculated based on 9 years of recorded CPUC 26 Jurisdictional cost data (1970-1978). Unit cost (mills /kWh) trends were
- 27. calculated for two different periods, namely, 1970-1978 and 1974-1978.
28 - Specific trends were calculated for (1) O&M expenses, excluding fuel, 19 (I-l i l)-12 12-19-79
Rodney L. Larson i purchased power, and customer service and informational expenses, (2) 2 depreciation expense, (3) taxes - other expense, and (4) rate base. Fuel 3 and purchased power expenses were excluded from the attrition allowance 4 because they are essentially recovered through ECAC although a component 5 of approximately $26 million is not covered by ECAC. Customer 6 service and Informational expenses were eliminated because i t was felt 7 that for this type of expense i tem, costs incurred beyond the test year 8 would be a function of what the Commission authorizes in the test year.
9 Q. Mr. Larson, you indicated that you used uni t cos ts instead of total 10 dollars in calculating the various trend rates, what was the reasoning 11 behind this?
12 A. Unit costs (per kWh) were trended instead of total dollar figures so that 13 attrition could be analyzed apart from the impac.t from the rate of increase 14 in kWh sales and revenues resulting from increased sWh sales. It should 15 be noted that a productivity component is incorporated in the attr! tion 16 allowance since productivity gains are included in the recorded costs 17 (1970-1978). The 9-year CPUC jurisdictional unit cost data and the 13 calculated annual trend rutes are shown in Chart 19-C.
19 Q. How are the' attrItlon factors calculated?
20 A. First, the historical annual trend rates shown in Chart 19-C for or.H ex-21 penses, depreciation expense, and taxes-other expense have been applied to 22 the corresponding estimated unit cost data shown for test year 1981 to 23 estimate the projected annual change in these expense items beyond the 24 tes t year. 0.1 minus the _ effective incremental tax rate is then applied 25 to those expense items deductible for income tax purposes to arrive at the 26' effective after-tax annual incremental change in return. When this incre-27 mental change in return is subtracted from the requested return and divided 28 by the test year 1981 rate base, the resultant impact on rate of return on 29 rate base >3n be cetermined. This resultant rate of return is then 12-15-79
~
Rodn;y L. Lcrson I subtracted f rom the requested rate of return to derive the attrition 2 factor. The attrition factors for the aforementioned expense items are 3 shown on page of SCE-2 . Detailed calculations are shown 4 in Appendix A attached to my testimony.
5 q. How was attrition calculated for rate base?
6 A. Attrition associated with rate base was calculated in the same manner as 7 expense, with the exception that attrition was offset somewhat by includ-8 ing the effect of increased ictura u seductions related to increases in 9 rate base. Specifically, the attrition caused by rate base is calculated 10 by applying the trend rate to the test year rate base in order to derive 11 the annual change in rate base. The test year return is then divided into 12 components, the first of which is related to the test year rate base 13 while the second is due to the incremental change in rate base to derive 14 the impact on rate of return caused by the incremental change in rate base.
15 This impact is offset somewhat by including the interest deduction related 16 to changes in rate b sse. This resultant impact on rate of return is then 17 subtracted from the requested rate of return to derive the attrition 18 factor. The rate base attrition factor for the 1970-1978 period.was 0.28%
19 and for the 1974-1978 period was -0.05%. These calculations are also 20 shown in Appendix A attached to my testimony.
21 Q. Mr. La rs on , there appears to be a wide discrepancy in the rate base 22 attrition factor calculated for these two time periods. What, in your 23 opinion, are the. reasons for this?
24 A. The 1974-1978 rate base attrition factor was influenced by a reduced rate 25 of increase in plant expenditures and by increased depreciation rates.
26 On the other hand, the 1970-1978 period reflects both the 1974-1978 period 27 and the pre-1974_ period,-which was marked by a higher rate of plant 28 expenditure increases. Future rate base trends beyond the test year would, 19(1-111)-14 12-15-79
-. -_. _- =. . . - _- - =.-.
Rodney L. Larson 1 in my opinion, be higher than both periods given the impact of San Onofre 2 on future rate base calculations. The 1970-1978 period provides the 3 better "fi t" in the trend analysis.
~4 Q. You mentioned earlier that attrition includes increased financing costs.
5 What amount of attrition have you included in the attrition allowance 6 relate d to financing costs?
7 A. I have included in the attrition allowance 15 basis points for increased 8 financing costs, which is the recommendation provided in Mr. Christie's t 9- testimony.
10 Q. Would you please summarize your attrition allowance recommendation?
11 A. Yes. The calculated annual attrition factors are summarized below:
12 Time Period 13 Source of Attrition 1970-1978 1974-1978 14 Or,M Expenses 0.54% 0.43%
15 Depreciation Expense 0.I1% 0.10%
16 Taxes-Other Expense 0.02% 0.04%
17 Rate Base 0.28% (O.05%)
18 Subtotal 0.95% 0.52%
19 Financing Costs 0.15% 0.154 20 Total 1.10% 0.67%
21 The large discrepancy between these two period is largely the result of 22 rate base. As discussed previously the 1970-1978 period is a better 23 representation of the attrition factor associated with rate base, however, 24 to be on the conservative side, an average of these two time periods 25 results In'an.' annual attrition allowance, ercluding financing costs, of 26 0.735L The averaging of these two time periods results in very little 27- attrition being associated with rate base. The effect of this procedure 28 is to eliminate the future. Impact of San Onofre in the requested attrition
. jg, 19(1-111)-15
. . --- . __ ~ . - -. - -. . . .
R:dney L. Lars n I allowance for rate base. The 0 735% attrition allowance can be compared 2
to the estimated attrition in CPUC Jurisdictional rate of return between 3- the estimated period 1979-1981 of 0.885% (1.77% *- 2). Adding the financial 4
attrition of 0.15% to both these numbers resuirs in a calculated attrition 5 allowance based on historical costs of 0.885%, a,d an attrition allowance 6 based on estimated costs between the 1979-1981 period of 1.035%. An annual 7 attrition allowance of 0.8% is recommended an< as shown from the previous 8 analysis is certainly conservative.
.9 q. Mr. Larson, how would this recommended annual allowance for attrition be 10 included in the Company's increased rate request before this Commission?
II- A. Given the policy of-this Commission (CPUC Decision No. 89711, Pages 129-12 130), that base' rate increase requests should occur at a minimum of two 13 year' intervals, for the Company to be allowed to earn its authorized rate 14 of return during this two year interval, the Company would have to be
'15 ' allowed to increase its rates by 38.0 million or, by 0.4% rate of return 16 on rate base in the test year. This is because in the year following the 17 test. year the. Company's: return on rate base would be expected to decrease 18 by approximately 0.8% due to attrition. The Company, therefore, would
'19 earn at a level'of'0.4% rate of return on rate base above the 1981 test 20 year cost of ' capital and at a rate of return' level of 0.4% below the test 21 ' year cost of capital in the year following the test year. The net result-would be that'the Company, Lover this two year interval, would be realls-tically af forded .the opportunity to earn the authorized rate of return on
~
123 24- ' rate' base.
L25 LQ. Mr. Larson, insofar las the material in Parts I, ll, and til of Chapter 19
- 26 ' ' of Exhibit No. .(SCE-3) is factual.in' nature, do~you believe it to L27 'be accurate?
- 19(1-111)-16 cl2-15 ' f g e- ) y r----
Rodnsy L. Lcrson 1 A. Yes, I do.
2 Q. And insofar as it represents opinion, does it reflect your best judgment?
3 A. Yes, it does.
4 q. Does this conclude your prepared testimony?
5 A. Yes, it does.
19(1-111)-17 12-15-79
i
- Rodney Larson l APPENDIX A Sheet I of 3 i j
OPERATIONAL ATTRITION LALCULATIONS l
l 4
RB Per kWh AF(RB) = ROR - (R0R) (RB Per kWh) + RB (Ang%) (Debt Ratfo) (Debt Cost) (t)
Where: AF(x) = Attrition factor for (1) Expense, excluding fuel, Purchased Power, C5&l, and Taxes - (E), (2) Depreciation-(Depr.), (3) I Taxes-Other, (T-0) .
AF(RB) = Attrition Factor For Rate Base l ROR = Rate of Return RB = Rate Base x = Attrition items mentioned under AF(x) 1 Ax% = Annual Trend Rate For Expense t = Combined Tax Rate = .51184 ARBt = Annual Trend Rate For Rate Base Debt Ratio = 47%
Debt Cost = 9 75%
i
( .
!. ?
f-
-e m J
12-20=79: 19 (1-1 l l }_=18 I:
1
. p y y s . _
Rodney Larson APPENDIX A Sheet 2 of 3 OPERATIONAL ATTRITION CALCULATIONS II. Calcula tions:
A. 1970-1978 Trended Data (I) AF(E) = - 10.78% - (10.7th;) (76.092) - (9.124) (9.172%) (1 ,r;;gg) 76.u32 AF(E) = 10.78% - 10.24% = 0.54%
- (2) AF(DLPR) = 10.78% - (10.78% (76.092) - (3.309) (4.9722) (1 .51184) 76.092 AF(DEPR) = 10. 78% - 10.67% = 0.11%
(3): AF(T-0) = 10.78% -- (10.78%) (76.092) - (1.207) (2.113%) (1 .51184) 76.092 AF(T-0) = 10.78% - 10 76% = 0.02%
(4) AF(RB)' = 10.78% - (10.78%) (76.092) + (76.092) (3.483%) (47%) (9.752) (.51184) 76.092 + (76.092 (3.48T1) )
- AF(RB) = 10.73% - 10 50% = 0.282 Sume ry
. AF(E) 0.54%
-AF(DEPR). 0.11%
AF(T-0)- 0.02%
Total 0.95%=
n 1 $
12-20-79: 19(I-1II)-19 a
"W 'i e -t- F -w% 7,7 , -p
Rodney Larson APPENDIX A l
l Sheet 3 of 3 OPERATIONAL ATTRITION CALCULATIONS l
l B. 1974-1978 Trended Oata-(1) AF(E) = 10.78% '(10.78% (76.092) - (9.124) (7.253%) (1 .51184) 76.092 AF(E) = 10 78% - 10.35% = 0.43%
(2) AF(DEPR) = 10.78% - (10.78% (76.092) - (3.309) (4.547%) (1 .51184) 76.092 ,
AF(DEPR) = 10 78% - 10.68% = 0.10%
(3) .AF(T-0) = 10 78%_- (10.78% (76.092) - (1.207) (4.679%) (1 .51184) 76.092 h
AF(T-0) = 10 78% - 10 74% = 0.04%
(4) AF(RB) = 10.78% - (10.78% - (76.092) + (76.092) ( .543%) (47%) (9 75%) (.51184) 76.092 + (76.092) ( .543%)
. i AF(RB) =.10 78% 10.83% = (0.05%)
Summary AF(E) 0.43%
AF(DEPR) 0.10%
AF(T-0) 0.04%
~
Total. 0.52%;
- 12-20-791 19 (l-1 I i)-20 v ..; . _ , _ , -
, - . ., - .- - - _ . . _ . - - - _ . _ .. . = - . .- ._ _ ._ . --.
SOUTHERN CALIFORNIA EDISON COMPANY Prepared Testimony of Warren E. Ferguson Exhibit No. (SCE-2) , Chapter 19 (Parts'lV - VI) 1
'l Q. - Please state your full name.
2 A. My name is Warren E. Ferguson.
3 Q. Mr. Ferguson, have you previously testified in this proceeding?
4 A. Yes, I have.
5 Q. Were Appendices B, C, and F to the application prepared by you or under 6 your supervision?
7 A. -Yes, they were.
8 Q. . Are you testifying with respect to Chapter 19 of Exhibit No. (S Cf.-2) 9 for identification?
10 A. Yes, I am. Part IV,. Part V, and Part VI of Chapter 19.
. 11 Q. Were those parts, that is, Parts IV t V, and VI, prepared by you or under 12 your supervision?
13 A. Yes.
l 14 ' Q. What do those parts cover?
.35 A. 'Part'lV covers ratemaking considerations which include the following:
C
- 16 A - Rate History, B - Revenue Stability, C - Marginal Cost, D - Value of 17 Service and Competitive Considerations, E - Environmental Factors, F -
- 1;8 Comparisons with other Utilities, G --Cost Allocation, H - Conservation and 19 Load Management, and I - Li feline.- Part V covers the Proposed Tariff 20 . Schedules, and Part VI covers Typical Bill Comparisons- between Present and 21 ' Proposed Rates.
22 Q. With' respect to Part IV of Chapter 19, please summarize the factors wt.ich 23 influenced you in connection with the changes that are now being proposed.
19 (IV-VI)- 1 i 8-3-79.
1
Verren E. Ferguson 1 A. The determinations of the proposed change s in rate schedules were based on 1
2 the requirements for additional revenues, and revenue increases were distri-3 buted to customer groups and rate schedules af ter giving consideration to the 4 various factors which I listed, together wi th r eliance on judgment and expe-5 rience in applying such factors to reach a conclusion as to what is believed 6 to be a reasonable and proper tariff schedule.
7 Q. Were all of the factors given equal consideration in your rate design?
8 A. No. In the case of certain rate designs, sone of the factors may have had -
9 little or no influence, whilc in others, one single f actor might have pre-10 dominating importance.
11 For example , the l i f.- l i ne legislation, as implemented by the 12 Commission, is an almost totally overriding consideration in domestic rates 13 and, except for the revenue deficiency from the lifeline sales which must 14 be removed from other sales, of no importance in designing nondomestic rates.
15 One consideration in this rate design which has not previously been 16 a significant factor, was marginal costs. To the extent practicable, margi-17 nal costs were considered in establishing the level of rates proposed for 18 most of the rate schedules. Also of considerable concern in both o ar rate 19 design and the allocation of revenues by customer group was revenue stability.
20 During 1979, as a result of the rates authorized in Decision No. 89711, we 21 have had a significant transfer of customers from Schedule No. A-7 to 22 Schedule No. GS-2. Although I do not believe there is anything sacred 23 about a particular rate schedule, I do believe it is important that the 24 rats design either minimize transfers between rate schedules or reflect, 25 'n the over-all sales and revenue estimate, the impact of such revenue 26 transfers.
27 Q. With respect to Part V of Chapter 19, please summarize briefly th, signi-28 ficant changes proposed.
19 (IV-V I )-2 9-3-79 L
Warren E, Ferguson I 'A. All of the changes proposed in tha tariffs are shown in Appendix C of the 2 application. Table 19-E, Sheet 3 of 3, Indicates the estimated revenue 3 increase proposed for each schedule, and Table 19-F, Sheets I to 15, 4 summarizes the changes proposed in the level of rates.
5 For most schedules the only changes are in the level of rate.
6 For Schedule Nos. A-7, GS-2, and PA-7., the existing energy blocks have 7 been eliminated and replaced by a sir.gle energy charge. The lifeline 8 discount for Schedule No. DMS has been increased to 15%. Schedule No. PA-1 9 has been changed to a monthly schedule from an annual rate. This has 10 resulted in several changes in the Special Conditions for that schedule.
11 It is also proposed that Schedule No. P-1 be withdrawn. That 12 schedule has been closed to new customers -since Septeinber 10, 1969 There 13 are presently less than 2,500 customers on the rate. it is proposed that 14 these customers be transferred to Schedule No. GS-1 or any other applicable -
-15 rate.
16 Decision Nos. 93146 and 90475 authorized the implementation of 17 . time-of-use rates for customers with demands in excess of 1,000 kW. By r
this application, the Company is proposing to extend Schedule No. TOU-8 to i 18 19 customers with' demands in excess of 500 kW.
20 Other. minor changes have been made In the wording of some 21 schedules to' reflect the impact of the changes proposed herein.
22 Q. Will you please turn to Table 19-E and Indicate how the $340,183,300 total 23 increase is broken down by schedule classifications?
24 A. At the estimated-1981 level of sales, the increase proposed for customers 12 5 remaining on General Service Schedule No. A-7 is $28,748,800, which is an '
r.
26' average Increase of-9.6%.
27 For< Schedule No. D, the increase is $149,932,200, which is an-28 average. increase.of 13.5%.
19(IV-VI)-3
..l- 12-19-79
Varren E. Ferguson i For Schedule No. GS-1, the increase is $19.286,800, which is an 2 average increase of 11,4L 3 For Schedule No. GS-2, the Increase is $69,729,400, which is an 4 average increase of 10.1L
'S For customers who are now on, or are proposed to be transferred 6 to Schedule No. 700-8, the increase is $43,928,900, which is an average I I
7 increase of-3.57.
8 For the other schedules which involve lesser amounts of money, 9 the increase in dollars and percentages is also shown.
I 10 The total incrcase for all rate schedules is $340,183,300, which 11 an average !ncrease of 8.43/. on total electric sales (9.0% on CPUC Juris-12 dictional) for the 1981 estimated test year.
13 - Q,- Are any changes proposed for the lifeline Icvel of usage under the Domestic 14 Schedules?-
'15 A. Yes. Slace the' average system rate has increased by more than 25% over the 16 January.1, 1976, level, I believe it is appropriate to increase rates for f 17- lifeline sales. Moreover, l believe that it will be necessary in future 18 proceedings.to propose increases in these rates. As a result, I would
, 19 recommend.that the Commission adopt a standard in this proceeding, setting 20 f the lifeline rate at approximately 75% of the nontifeline domestic rate, 21 .as we have proposed.in this application. However,'In developing the rate 22 design in this proceeding' for domestic customers, the primary increase in 123 lifeline rates is in the ellmination of the existing lifeline tail block, 24~ 'so tha't all lifeline kilowatthours are billed at a uniform rate, which is 25 .i just? .097c per kilowatthour greater. than the . existing basic lifeline rate,
~ 26 : and In' an increase in the customer charge to more nearly reflect minimum-
-27 meter _ reading ~ and billing costs.
287 Q. Are there any schejules ' for which you . propose no change?
l29 A. Technically, certain overlay schedules'are;not being changed. .These include 19 (lv-v i) 12-19-79:
Warren E. Ferguson 1 ' Schedule Nos. D-APS, DE, DM, UCLT, S, SCG-1, SCG-2, SCG-3, and TOU-8-1.
.2 However, customers served on these rate schedules will receive an increase 3 in rates since the underlying rates are being changed.
4 No changes are proposed in the cortract for fringe service wi th 5 the Ci ty of Los Angeles and in the interchange and standby contracts wi th 6 other electric utilities and for sales to the State of California for Depart-7 ment of Water Resource requirements. No change is proposed in the contract
-8. with the U.S. Department of Interior for Sequoia National Park. No changes 9 are proposed for Catalina customers.
10 For certain other customers served on special onctracts, indicated 11' in Part V of Chapter 19, no changes are proposed in those contracts, other 12 than the level of rate as therein indicated.
-13, Q. Are you not proposing to transfer Catalina customers to mainland system
- 14. electric rates?
- 15 A. Not in this proceeding. However, in Application No. 58331, one of the pro-
. 16f posals. under consideration is to transfer Catalina electric customers to 17 mainland system rates. That case has been submitted and was awaiting deci-18 sion when this application was being prepared. We do not know whether the 19 Commission will act favorably on that proposal prior to a decision in this 4 20 case. 'If they were to do so, this proceeding could result in an increase
' 21 'in rates for those customers. However, we have not included the revenue which would be derived :from those customers at proposed system rates in our 22
.:23 1 : calculations. Present and proposed revenues are derived assuming the exist-
~ 2k' 'ing-Catalina rates.
. 25- Q. Will you. please' explain the material contained in Part-VI of Chapter 197 26 A. . - Table 19-G contains comps.~isons.of. Typical Electric- Bills calculated at
- 27. present rates, including provision for the estimated Energy Cost Adjustment,
. 28 and at proposed. rates. ' Compari sons are made for. Schedu le Nos. A-7, ' D, GS-1,
~
29l GS-2, LS- 1, P- l ', PA'-1, PA-2, and TOU-8. . .The levels of use for these bill 19(lv-vi)-5 L12-19-79 ,
-Warran E. Ferguson 1
comparisons are tha industry standards established by the Federal Energy 2 Regulatory Commission for such comparisons, where appropriate, and for such
-3 other levels as deemed appropriate to demonstrate the impact on customers 4 having relatively typical sized loads. The Table, in addition to showing 5 the amount of bills calculated on present and proposed rates, indicates 6 the amount and percentage of the increases.
7- q. Mr. Ferguson, how have you handled the Energy Cost Adjustment in designing l
8 'the proposed base rates? !
9 1 A. - Revenues from the Energy Cost Adjustment Clause have been estimated based 10 upon our estimate of fuel and purchased power costs during the test year.
- ll. The revenues for 1981 are the same for both present rates and proposed 12: rates, except- for a minor increase as a result of the DMS change mantioned 13 earlier. However, in order to properly establish the revenue requirement, 14 an adjustment was made to revenues to reflect the estimated change in the 15 balancing ' account as a result of ei ther undercollections or over-collec-L16 tions of fuel and purchased power expense as a result of the operation of 17 the Energy Cost Adjustment Clause.
- 18 Q. In Decision No. 90488, the Commission di rected the Company to consider the 19- transfer of the State Water Plan revenue deficiency to base rates. Is that
-20 ' deficiency _ being recovered in your proposed base rate design?
21 - A'. No,-it is not. -When one looks at the level of fuel and purcFased power
~
22 expense-for 1981, I think it becomes clear that a relatively small error
.23 in estimeting that expense, the level of sales, or_the level of purchases 24- can_ result in a substantial change in the level of ~ dollars to be recovered
!25 as. a resul t of' those transactions. -l think i t is only necessary to look at -
126 - the-substantial increase in. oil prices in 1979 to understand the potential ,
.27 margin of error in this expense for 1981..
28 Since obviously, this estimating' error can be either high or low, (29- _it can work to-the detriment of the ratepayer,'just as much as the Company.
19(IV-vi) .
12-14 .. -
- - . - . . .-- _ . . - - - . ~- .. . = . - . . . . _- _ ..
Warren E. Ferguson i
1 And, since the Commission has already concluded that the ratepayer, having [
i 2 . received the benefits of that agreen.ent, should also bear whatever burden 3 may exist, we believe that burden is most equitably measured through the :
4' implementation of the ECAC.
5 To do otherwise can only result in either the ratepayer receiving 6' a greater detriment than is experienced by the Company or the Compeny being J7 saddled with a burden, which the Commission has already concluded should i ~8 be borne by the ratepayers.
9- Q. Mr. Ferguson, insofar as the material contained in Appendices B, C, and F
. 10 of the Application, and in Parts IV, V,.and VI of Chapter 19 of Exhibit
! - 11' No. (SCE-2) is of a factual nature, do you believe it to be accurate?
2 12 '. 'A. ~Yes', I . do.
13' Q. Insofar as ' i t' represents opinion, does i t represent your best judgment?
14 ' LA . .Yes,'It does. .
~
I a
.I e
t-4 r' _
1 119((iv-vi)-7
. 12 14-79
.,..,..,...._-,,4,..,
. . _ , . - . . . . ~ , - , . - - -
.4 - -.---
SOUTHERN CALIFORNIA EDISON COMPANY Prepared Testimony of Ronald Daniels Exhibit No. (SCE-2) , Chapter 20 I q. Will you please state your name and address for the record?
2 A. . Ronald Daniels. My business address is 2244 Walnut Grove Avenue, Rosemead, 3 California.
4 - q. What is your position with the Company?
'5- A. I am Manager of Revenue Requirements.
6 q. Please refer to Exhibit No. (SCE-3) for identification, entitled 7 " qualifications of Witnesses". Directing your attention to the page 8 entitled " qualifications of Ronald Daniels", does that portion of the 9 exhibit accurately set forth your background, training, and experience?
10- A.. Yes , _ ' I t does .
-11 q. Are you testifying with respect.to' Chapter 20 of the Results of Operation 12- ~ exhibit referred to as Exhibi t No. (S CE-2) for identification?
'l3 A. - Yes , : 1 cm.
14 q. .Was ~ the material in Chapter 20 prepared by you or under your st pervision?
-15 -A. Yes, it was..
16 q. What is1the purpose of this testimony?
- 17. . A. The purpose'of my testimony is to sumarize what has -been set forth in the
'l8 ' Results.of Operations, the Financial Characteristics, and other supple-19 mental . exhibits which have accompanied our_ Application. it is also in-
=20 tended to indicate reasons-for adopting certain positions and variations 21 from past ratemaking procedures.
22: q. ..in Part:A.of Chapter 20 of Exhibit (S CE-2) and on Chart 20-A you-
-23 in.dtcate various degrees ;of ~ shortfalls.of revenue occurring between 1970 20-1
'12-18-79
Ronald D nlels 1 and 1980. Please explain how Chart 20-A was developed.
2 A. The required rate of return has been assumed to be the rate of return i
3 authorized by the Cocrnission in those years when a test year period 4 existed. In years between test years, a straight line relationship 5 between test years was assumed to determine a rate of return for the 6 intermediate years.
7 For 1980, the required rate of return was developed by using a 8 return on equity of 15.0% with projected embedded costs of debt and 9 preferred stock applicable for that year. The rate of return cealized on 10 a recorded basis for CPUC jurisdictional sales is shown under the colu: n 11 designated " achieved". The difference between the rate of return required 12 and achieved is multiplied by the CPUC jurisdictional rate base which is 13 then multiplied by the net-to-gross factor resulting in the shortfall of 14 revenue for each period. The bar graph at the right of the chart 15 graphically presents the magnitude of the dollar shortfall from 1970 to 16 1980. In those periods which were not test years, the bar graph has been 17 divided into two portions. The solid portion represents the shortfall 18 resulting from the deficiency in rate of return when comparing th2 19 achieved with that authorized rate of return granted in the prior test 20 year period, and the cross-hatched area represents the shortfall based on 21 the incremental increase in rate of return so determined for the years 22 following the test year.
23 Q. What conclusions do you draw from Chart 20-A?
24 A.- It is apparent that, on a recorded basis, revenues have been deficient 25 every year since 1970 and, therefore, have not achieved the authorized rate
.26 - of return granted by the CPUC. Even in the test years, the shortf 11 on the 27 average, in rate of return exceeds 0.7%. While it is recc<inized that the 28 ~ Comission is desirous of setting rates at the lowest reasonable level, It 20-2 12-18-79
Ronald Dr.. niels 1 is inappropriate to establish a record in which rate of return on a record-2 ed basis always falls below authorized rate of return, in some years, the 3 rat, of return should exceed the so-called authorized level, otherwise, even 4 an unsophisticated investor would become doubtful of the Company's potential 5 to earn the return authorized by the Commission. It should be recognized 6 that the so-called authorized rate of return should fall someplace wi thin 7~ a range considered the reasonable rate of return.
8 q. With regard to Chart 20-B of Exhibit (SCE-2) , please explain the 9 purpose of including this chart.
10 .A. Chart 20-B has been included as part of Chapter 20 to illustrate the re-11 lationship between the revenue effect of the increase request in our
- .12 Application- as compared to (1) the increase in revenue requirement asso-13 clated.with the addition of SONGS 2, (2) the further increase in revenue 14 requirement which would result from the inclusion'of CWIP in rate base,
'15 and (3) the revenue effect of rates based on marginal costs.
16 Q. What-do the top two blocks demonstrate?
- 17. : A. The. top block. shows the results of operation on existing rates. for the 18: total system. As indicated on the chart, this information has been-19 : developed ..in Chapters 7 through 18 of the Results of Operations Exhibit 20_ (SCE-2) .
21
~
The~next block reflects the al kcation of expense to the CPUC 22 -jurisciational sales, it -is further Setdivided into the base rate revenues 23- - of. $1.274 billion and ECAC revenues of $2.526 billion.
24' Q. -Do the next two blocks represent the_ bases for the $340.2 million rate
- 25 request?.
.26 -A. Yes. 'The. third block from the top of the page indicates a required in-
'27 crease of $302.2 mili;on to bring the rate of return from present-rates
- 28' up to a' level 'which would produce a rate of return of 10.78% on rate M .
20-3
- 12-18
- r
Ronald Daniels
} ,
, i l
The fourth block reflects the need for an additional $38.0 I l
million increase in revenue which represents the additional requirement l
3-' to meet attr_ition occurring in the period 1981-1982. The sum of these
'4 two items produces the $340.2 million rate increase request.
5 q. Please explain the two blocks referring to SONGS 2.
6- A. 'It.is anticipated that SONGS 2 will become commercially operational on 7 ' July 1, 198I. If we were to utilize traditional ratemaking procedures 8- - and reflect the. effects of adding SONGS 2 in this filing, the revenue 9' requirements for test year 1981 would only reflect one-half year of 10 SONGS 2 operation. The block indicating one-half year shows the $79,0
,11 - million'of additional-revenue which would be necessary for test year 1981
'12 If the unit.were' included in.the general rate case.
Because of the sig .
13 nificant-addition to rate base and expenses and the impact on fuel savings,
~
- 14. It has been deter.nined that this unit should not be included as part of
.15 c the ' general rate l case request for rate relief but rather the costs asso-
- 16 .- clated therewith should be accumulated in a balancing account'with base f rates increased when the unit comes on line with offsetting reductions
~
17
- 18_ ln'( the ECAC rate t'o' reflect the lower fuel costs associated with the unit. i 19 . The block indicating ful1 year operation of' SONGS 2 = shows that 20E an additional. $108.3 million of base rate increase above the $79.0 -
121 milllon previously described would be required at the time of. comercial 22' . operation of SONGS' 2. This means that instead of- the $79.'O nillion_ going -
lInto effect on Januaryll, 1981, base rates would be. increased by_$187.3
~
23 24 _million on_ July,1, 1981. Concurrently, .a reduction-of' the L ECAC of an .
~ 25 - equal amount would be implemented. . Further discussion of the principles 26; iunderlying;this . proposal will be provided in otheri testimony' supporting 27-- .the request. to be made. by ' separate application for a balancing account =
-28J l procedure for_ dealing with this plant addition.
'29 ?Q.' -What are.the purposes'of the lower two' blocks on this. chart?
~
- ,' ~20-47 4
11248-79.
1 1
Ronald Daniels I 1 A. In recent years, much discussion has been held regarding the application '
2 of marginal costs in the development of rates to give customers appro-3 priate pricing signals. The two blocks shown at the bottom of this chart 4 give an indication of the rate changas necessary to reflect full marginal 5 costs. The block representing the total inclusion of CWIP in rate base 6 (excluding SONGS 2) provides information regarding the effect of this 7 component of capital investment in rate base. The impact of DJIP in rate 8 base has been presented because inclusion of such plant would be a method 9 of reflecting marginal cost since this plant i nvestment reflects cu rrent 10 costs of construction as opposed to the accumulated historical costs 11 included in the tradi tional development of rate base. Allowing rates to be 12 based on the inclusion of 041P in rate base would allow the settino of rate 13 levels to be one step nearer to a full marginal cost signal in rate design.
14 q. Do you have any recommendations regarding inclusion of construction work 15 in progress in rate base?
16 A. The Company has not proposed that construction work in progress be in-17 cluded in rate base in the preparation of this case. I would, however, 18 like to suggest for the Commission's consideration the potential of moving 19 in the direction of marginal cost rates to the extent of the additional 20 revenue requirements resulting from the inclusion of CWlP in rate base 21 which could permit a significant degree of marginal cost pricing without 22 any windfall to the utility, and with ultimate significant ratepayer 23 benefits. The higher rate levels would be providing the ratepayer with a 24 bette'r price signal which would then allew him to decide whether he wanted 25 additional service in the future at the higher price levels.
26 Three-key points could be satisfied by such inclusion in rate 27 base: (1) the rates applied could be significantly nearer to marginal 28 costs, thus more nearly providing the price signal the economist seeks, 20-5 12-18-79.
Ronaid Dania is l 1 (2) the rate base fcr future years would be reduced by the elimination 2 of AFUDC, and (3) the Company's financial posi tion would be improved since 3 earnings would be based on real earnings instead of a portion being 4 supplied by AFUDC.
5 Q. Chart 20-C of Exhibi t No. (S CE-2) indicates several types of 6 attri ti on. Please explain what is shown on this chart.
7 A. As described in the text of Chapter 20, the 1979 projected results indi-8 cate that the rates as approved will not produce the return authorized by 9 the ;ommission in the last general rate decision. In order that 1979 be 10 placed on an authorized return basis, it would have been necessary to 11 increase rates by $18.9 miliIon as of January I,1979. Even if 1979 12 results were to reflect authorized return, approximately $226.4 million of 13 attrition occurs between 1979 and 1981 As can be seen in the middle of 14 the diagram, this $226.4 million is composed of increases to labor, other 15 operation and' maintenance, capi tal-related (rate base) costs, and finan-16 cial' attri tion. This attrition has been offset in part by higher revenues.
17 The financial attrition referred to here is based on the increased cost of 18 new debt issues as well as preferred stock i ssues.
19 At this point, the return on equif.y is still considered to be 20 the 13.494 authol ized in Decision No. 89711. The attrition allowance 21 requested for the year af ter the test year of $38.0 miilion in test year 22 1981 revenue requirr'..ents is conservative when compared to the earnings 23 loss due to att* .clon of about $113.2 million per year between 1979 and 24 1981 absent rate relief. As indicated in the text, this $38.0 million is 25 one-half of a full year of attrition and would be recovered in each of the 26 . two years,1981 and 1982, under the Company's proposal to produce about 27 -$76.0 million. If we were to base a comparable figure on the attrition 28 occurring between 1973 and 1981, we would be proposing an increase of i
20-6 l 17-1o-74 l
I
l Ronald Daniels I approximately SSE.6 million per year for an attrition allowance.
2 - Q. Do you believe that with the implementation of the Energy Cost Adjustment 3 Clause (ECAC) and the Regulatory Lag Plan, the risk faced by the Company 4 .has declined from previous periods?
5 A. No, I do not believe that the absolute level of risk has diminished. As 6 a matter of fact, other factors have resulted in signi ficantly higher 7 risks; however, these two actions taken by the Commission have ameliorated
'8- what would have greatly increased risks of this company in their absence.
9 As has been shown in the test of this chapter, significant shortfall of i
10 revenue exists at the present time as well as being projected into the ;
11 future. The revenues being collected through the ECAC are projected to 12- ' represent approximately 66% of the total revenues collected. Had it not
- 13 been for the implementation of the ECAC with its balanc. g account, the
,14 Company would have faced a potentially severe problem in those time periods 15 when fuel prices wereLrising rapidly. Further, it is necessary for 16- companies of Edison's size to be making decisions which require substantial 17 funds to investigate innovative-solutions to. current and anticipated supply
.18 problems through installation of pilot _ plants. These include such projects 19 as coal gasification, geothermal, and solar energy. While it is true that 20 -
other organizations such as the Department of Energy have shared in some of 21 these risks Jith_ Edison,'there exists concern that the Company's judgment 22- .might be questioned when attempting a project which results in a relatively 23 high cost of production.' 'Further, under 'the provisions of PURPA, the l '24- ( Company will- be required to provide new services. the resultant- impacts 125- ef which are-difficult to asses; at this' time. An example is the simul--
.26' . taneous buy-sell arrangements with cogeneration customers.
127f -Q_. . In: Paragraph '.18 of Chapter 20, you referred to a contract wi th- the Depart-28 . = ment lof fWater Resoerces under which sales of-energy are made at a rate 7
12-19-79l
Ronald Dinlais I below the system average cost of energy. Do you have an opinion with 2 regard to the inclusion of expenses relating to DWR being included in base l l
3 rates?
l 4 A. Yats , it is essential that the expenses of making these sales in excess of 5 revenues be recovered either in ECAC revenues or in base rate revenues.
6 However, it seems to me, there is a decide.; advantage to recovering them 7 in the ECAC instead of in base rates. My reason for this recommendation is 8 that purchases and sales from DWR vary substantially from year to year 9 which makes it difficult to estimate such transacti-ons for 1980 and 1981 10 and subsequent years. If the expense associated with the sales to DWR 11 in excess of revenues recovered were included in the ECAC, a precise 12 accounting of the related expenses would occur since the actual sales to 13 DWR would be utilized in calculating the expenses charged to the ratepayer 14 through ECAC. This would also correctly recognize the fuel expense 15 associated with such sales as opposed to being fixed on test year estimates.
16 Further, a problem, such as the one indicated in Paragraph 18, could be 17 handleo through an ECAC adju tment.
18 q. Please explain the purpose ce Chart 20-0.
19 A. Chart 20-D has been included in Chapter 20 to provide a convenient illus-20 tration of the impact on the various customer groups. The blocks show 21 the average price per kilowatthour (including the ECAC provision) with and 22 without the rate increase. The dotted line labeled "ECAC" shows the amount 23 of the price per kilowatthour which relates to ECAC. For the domestic
-24 group, two levels are shown, approximately 2.9e/kilowatthour for lifeline 25 sales and 4.le/kilowatthour for the average of the group including lifeline.
26 Also shown on this chart is the rate ircrease percentage and the rate of 27 return for each customer group.
28- Q. Why is the price per kilowatthour for service to the street lighting group 20-8 12-18-79
Ronald Daniels 1 so much higher than the other groups?
2 A. In the case of street lighting service, the investment in street lighting 3 equipment requires significant revenue to cover the investment-related 4 expenses for the street lighting installations. This is the only service 5 where the Company provides the utilization equipment. As a result, the 6 fuel component of the total expense is much smaller than for other customer 7 groups.
8 q. What is the purpose of Chart 20-E?
9 A. Chart 20-E demonstrates the impact of environmental costs on a bimonthly 10 residential bill between 1969 and projected 1981. Aiso shown on the re-11 spective blocks is the amount of increase in cents per kilowatthour that 12 has occurred for both environmental expense and for all other costs.
13 Q. Does the increase of environmental costs recognize expenditures which may 14 result from current legislation regarding conversion to coal-fired genera-15 tion and limitations on burning oil from foreign sources?
16 A. No, the costs reflected on this chart are based on the mcde of operation 17 currently in effect and does not represent the potential additional environ-18 mental costs if it is necessary to install additional facilities to meet 19 stricter air and water quality standards. An example of such a potential 20 requirement would be the installation of scrubbers on all of the generating 21 plants in the Los Angeles air basin, it is estimated that the investment 22 necessary to meet such a requirement would approach $2.0 billion. This is 23 another example of the potential risks the Company faces.
24 Q. Please summarize your recommendations regarding the material in Chapter 20.
25 A. Based on the material presented in Edison's submittal, I recommend the 26 followi ng:
27 1. The Commission should accept Edison's estimates of expense 28 since it has been demonstrated that even Edison's estimates 20-9 12-18-79
Ronald Daniels I have been conservatively low in the past.
2 2. The Commission should provide for an attrition allowance 3 to recognize the deficiency in earnings which occurs in the j 4' year af ter the test year under the Regulatory Lag Plan re-5, quirement for spacing general rate increases at a minicum of 6 two-year intervals.
l 7 3. The Commission should grant a general rate increase effective 8' no later than January I, .1981, which will produce $340.2
.9 million of additional revenue exclusive of the revenue re-10 quirenent impact of SONGS 2.
- 11 ' ' 4. - The Ommnission should adopt higher expense estimates and 12 revenue requirements in arriving at the authorized rate 13 increase if, in fact, the wage settlements in 1979 and 1980 14 exceed the 7% included in the development of this case.
15 5. In order to allow Edison to participate in alternative energy
'16 - source pilot plants, a procedure should be allowed, either I 17c through implementation of ECAC or through a separate mechan-18 ism, which.would provide the Company with the cash flow
-19 necessary .to support alternative energy supply projects 4 .
22~ .- which Edison would make between rate cases.
.21 6. . Careful consideration should be given to the coupling of any
.22 marginal cost pricing policy of the Commission to the 123 ' Inclusion of CWIP in rate base.
~
l 24.10. Mr.1 Daniels, insofar as . the material contained in Chapter 20 is ' factual
=25., in nature,1do you believa. it to be correct?
'26 DA.
Yesg ! do..
- 27 -Q. 'Insofaf as
- the material 1 represents opinion, does it represent your bes t
.28 Judgment?
se 20 y;y. 12-t8-79
i l
Ronald Dinials 1 A. Yes, It does.
2 Q. Does this conclude your prepared testimony?
3 A. Yes, i t does.
f 20-11 12-18-79