ML18230A818
| ML18230A818 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 06/09/1977 |
| From: | Harris S Carolina Power & Light Co |
| To: | Office of Nuclear Reactor Regulation, State of SC, Public Service Commission |
| References | |
| Download: ML18230A818 (102) | |
Text
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Y DOCKET FII.K CAROLINAPOWER & LIGHT COMPANY Before the SOUTH CAROLINAPUBLIC SERVICE COMMISSION Docket Nos. 18361 Application for General Increase 18387 ln Rates and Notice of Filing Change of Rates
South Carolina Public Service Commission DIRECT TESTIMONY OF SHEARON HARRIS 1
2 A.
5 Q.
7 A.
Please state your name, address and occupation.
Shearon Harris.
My office address is 336 Fayetteville Street,
- Raleigh, North Carolina, and my occupation is Chairman of the Board, President and Chief Executive Officer of Carolina Power
& Light Company (CP&L).
How long have you been associated with Carolina Power
& Light Company and what positions have you held with the Company?
I joined the Company in December of 1957 as Associate General Counsel and I became a Vice'President in 1960.
I served as General Counsel from the latter part of 1962 until May of 1963 at which time I was 10 12 13 14 A.
15 17 18 19 20 21 22 elected President.
I was designated Chief Executive Officer in January 1969 and in March of 1970 I was elected Chairman of the Board.
Would you briefly review some of your experience in the utility industry and in the business community.
I have served as Chairman of the Edison Electric Institute, which is the trade association of the investor-owned electric utility industry, Chairman of the Board of Directors of the National Association of Electric Companies, Chairman of the Southeast Regional Advisory Committee of the Federal Power Commission, member of the Board of the National Association of Manufacturers and of the Executive Committee of the Business Round Table, and as an officer or active member of various other industry boards and committees.
I am presently serving as Chairman of the Executive Advisory Committee for the National Power Survey conducted by the Federal
Power Commission, Chairman of the Electric'ower Research Institute
'\\
and serve on the Board of the United States Chamber of Commerce, and as a Trustee of the Committee on Economic Development.
I am also a
member of the Business Council.
5 q.
6 7
A.
Would you describe generally the service area, the operating system and electr'ic facilities of CP&L.
CP&L provides electric service at retail and wholesale throughout a
8 service area of about 30,000 square miles, covering the northeastern r
area of South Carolina much of central and eastern North Carolina 10 and the Asheville area.
The population of CP&L's service area is approximately 3,000,000.
At the end of March 1975, our retail customers 12 numbered approximately 663,000.
About 86 percent of our revenues are 13 from retail service.
At the end of 1975 the Company's generating 14 capability was about 6,800,000 kilowatts derived from seven coal-fired 15 16 steam electric plants, the Robinson nuclear unit, Brunswick nuclear unit No. 2, thirty-three internal combustion turbine generators and four hydroelectric plants.
During 1975 the Company's generation by 18 energy source was 72.5 percent coal, 22.4 percent nuclear, 3.8 percent hydro, 19 20 21 22 23
.1 percent residual oil,.4 percent No.
2 fuel oil and
.8 percent natural gas.
In 1976 the Company estimates its generation by energy source will be approximately 67 percent coal, 30 percent nuclear, and 3 percent hydro.
The capability of our system including net power available on a firm commitment basis is about 7,000,000 kilowatts.
We also own and operate.
24 25 an integrated transmission network and distribution system throughout I
the service area.
The Company's facilities are interconnected at
various points with the systems of neighboring utilities in order to provide for an interchange of power.
Our system and operations are more fully described in the 1975 Annual Report, which is presented here as "CP&L Harris Exhibit No. l."
When was CP&L last granted general retail rate relief for its South Carolina operations?
7 A.
The Company was last granted general retail rate relief in South Carolina in a case filed in October, 1973, by order of this Commission dated January 15, 1975 in a proceeding that was based upon a test 10 period ending December 31, 1973.
11 Q ~
What has happened since the rate proceeding to the Company's credit 12 13 A.
14 15 16 rating?
In February of 1975 Moody's Investors Services, Inc., one of the nation's major rating agencies, downgraded CP&L's bonds from A to Baa.
I know of no other time in the history of the Company that a major rating agency has assessed the quality of the Company's securities as below investment 17 grade.
18 Q
19 A.
20 21 Would you elaborate on the effects of the lower bond rating.
The consequences of this lowered bond rating are far-reaching and continuing.
Many financial institutions and investors are now prohibited by their charters or by established policy from investing 22 4
23 in CP&L bonds.
For example, pension funds for many public employees 5
are precluded by law from purchasing the Company's bonds as a result 24 of our low bond rating.
Some institutions have been precluded from investing in our securities because of the low earnings coverage 26 of fixed charges which has been experienced.
During 1974 hearings in Docket No. 17,134 Company witnesses predicted many harmful results should the Company's A/A bond rating be reduced.
The results have been even more adverse than then anti-cipated.
At that time, the Company was anticipating a spread between the cost of marketing A and Baa bonds of about 35 basis points.
In April of 1975, after the downrating of CP&L's bonds in February, the Company sold
$100 million in first mortgage bonds at a cost to the 10 12 Company of 11.24 percent.
The most nearly comparable sile by a company with an A/A rating was that of Florida Power and Light Company at a cost of 9.08 percent, 216 basis points lower than CP&L was required to pay.
We pointed out in the 1974 case that a Baa rating was certainly not one which would attract investor interest in 30 year 13 14 bonds.
When we attempted in April of 1975 to issue bonds to mature in 30 years, we found that the interest in such bonds rated lower 15 16 than A by either of the major rating agencies was almost nonexistent.
Consequently, we had to shorten the maturity date from the normal 17 30 years to only nine years.
18 19 20 21 22 23 24 25 26 We also pointed out in 1974 that a lowering of the Company's bond rating would result in a prompt reduction in the rating of the Company's preferred stock issues imposing substantially higher costs in raising this type of capital.
This result has followed and the Company's preferred stock has also been downgraded by Moody's.
In March of 1975 the Company sold preference stock at a cost of 11.2 percent.
This compared to preferred stock sold in the same period by companies with A ratings for costs in the range of 10.25 percent to 10.36 percent.
Our Company was unable to issue preferred stock at that time because 27 of low earnings coverage of preferred dividends and interest charges.
Not only has the lowered"rating resulted in higher costs for long-term financing, it has substantially increased the cost which 9
10 ll A.
the Company would otherwise have to pay for short-term financing.
The Company's'ommercial paper rating was reduced from Prime 1 to Prime 2 at the same time the bond rating was reduced by Moody's.
To have its securities rated at below investment grade is exceedingly costly to the Company and its ratepayers and will continue to be so for as long as this lower rating is in effect.
Would you please state the objectives of the Company's present rate filing.
Our overall objective is to improve the seriously deteriorated financial 12 condition of the Company so that we can regain, and once regained thereafter 13 14 maintain our credit worthiness and continue to provide reliable service to our customers.
Nore specifically, we are seeking increased revenues so that 15 16 18 19 20 21 Q.
22 23 24 A.
25 26 (a) the Company's earnings coverage of fixed charges can be restored and maintained at a more reasonable level of at least 2.5 times, (b) a fair and equitable return may be earned on the common equity investment in the Company, and (c) 'the Company can continue the normal maintenance program that was reinstituted after the interim increases of 12 percent became effective on retail sales in the fall of last year.
Would you please explain why the Company considers it important that its earnings coverage of fixed charges be increased and maintained at a level of at least 2.5 times?
Because this is the minimum coverage which in the opinion of the Company will enable its bond rating to be restored to A/A.
This is an opinion widely shared in the financial community.
1 Q.
Would you please relate the Company's recent coverage experience.
2 A.
The Company's earnings coverage of fixed charges fell below 2 times 3
for the 12 months ending October 1974, and notwithstanding the full effect of rate increases (based on 1973 test periods), it continued to remain below 2 times through July, 1975.
This compares with earnings coverage of as high as 4.32 for the year 1968.
As a resu1t of interim rate relief in the States of North Carolina and South Carolina last fall, the Company's earnings coverage increased to approximately 2.48 10
.times for the 12 months ending March 31, 1976.
This increasing trend is expected to level off soon even though we continue to collect all 12 13 14 15 16 17 18 W
19 20 21 of our requested increases subject to refund.
While our earnings coverage may exceed 2.5 times for a brief period, it can certainly not be maintained there for an appreciable period unless the total rate relief requested in this filing is allowed. It is very important to note that the results for this period. are influenced greatly by the interim increases that have been in effect in North Carolina and South Carolina since last fall and by the full increases sought in both states which have been in effect during some part of that period.
These revenues have been confirmed by the North Carolina Commission.
Should we not be able to recover our full requests
- here, our effort to regain and maintain our credit rating would be greatly frustrated..
Q.
You have stated as a second objective in your rate case an increase in the rate of return to a more reasonable level.
Is it your po'sition that the rate of return found fair and equitable in the last rate 4
case is inadequate?
A.
I must answer that by first pointing out that because of attrition and a continued high rate of inflation, it has been impossible for the Company to earn the rate of return found by the Commission to be fair and reasonable.
The Commission's last rate order, based upon 10 a 1973 test period, concluded that the approved rates should permit CPGL to earn a 12.5% rate of return on its common equity, which rate 12 13 of return the Commission found to be fair and reasonable.
During the year 1975 the Company's actual rate of return on its portion of common equity applicable to South Carolina retail operations was 10 percent.
15 This is substantially less than the rate of return which the Commission considered as just and reasonable in its order of January 15, 1975.
16 17 18 19 20 21 22 23 24 25 As shown on the Company's revised Exhibit H, when appropriate adjustments are made this rate of return becomes less than 3 percent.
A more specific answer to the question is that I do not consider the former rates of return allowed on common equity to be adequate under the circumstances presently existing.
In the first place, during the past year it has been possible for purchasers of the Company's debt securities to obtain returns in excess of ll percent.
Interest rates on long-term obligations have declined somewhat recently but will undoubtedly return to the high levels of last year as the demand for capital intensifies in the future. It is simply not realistic to
5 Q,
6 A.
expect to attract equity capital on reasonable terms when the equity investor can from time to time obtain near1y comparable returns on other investments that are not faced with the challenges or the risks that
, confront the utility industry today.
What are some of the risks to which you refer?
First, I will mention the deterioration that is occurring in the quality of earnings.
A debate continues in the financial community over the extent to which earnings containing a high allowance for funds used during construction (AFDC) are of a lower quality than 'earnings that 10 ll are less dependent upon such allowances.
In my opinion, while earnings resulting from AFDC are inferior, so long as AFDC does not comprise 12 13 an unreasonably large proportion of total net earnings the overall quality of earnings is not significantly affected.
However, since AFDC provides 14 15 16 no cash flow, the risk exposure to investors in a company's securities increases when AFDC accounts for substantially all of the earnings of the company.
CP&L has passed that point, and in fact the large amount 17 18 of AFDC included in CPSL's net income and the resulting small percentage of the Company's cash needs generated internally contributed to the 19 20 downgrading of its securities by Moody's.
A study of the'5 major electrical utilities dated April 29, 1975, by Mitchell Hutchins, Inc., a research 21 22.
23 24 25 firm highly respected in the financial community, showed CP&L as the only Company where AFDC exceeded net earnings available for common stock during the year 1974.
This situation resulted from the large amount of construction work in progress upon which the Company realized no cash earnings.
As of the year end 1974, CP&L's construction work in progress amounted to
$826 million or 75 percent of net plant in service.
By May 31, 1975 construction work in progress,had increased to
$ 948 million or approximately 86 percent of net plant in service.
Thus, for every dollar of net investment of plant in service, the Company had, approxi-mately 86$ invested in construction work in progress upon which it received no cash earnings.'t the year end 1975, construction work 10 11 12 13 in progress still amounted to
$643 million, notwithstanding the fact Brunswick No.
2 and related facilities, which accounted for $403 million came into service on November 3, 1975.
AFDC increased to in excess of 100 percent of net earnings available for common -stock for the 12 months ending November,
- 1974, constituted 97 percent of earnings available for common for the 12 months 14 15 ending August,
- 1975, and continued at an exceptional 79 percent for the 12 months ending December 31, 1975.
This means that in 1975, without 16 AFDC,.CP&L'had earnings of only
$.57 per share.,
17 18 19 20.
The fact that the Company's operating revenues have not been producing sufficient earnings to service common stock is a risk factor which prudent investors must certainly consider in determining whether to invest in our stock or other securities.
21 Q.
What are some of the other risks associated with owning electric 22 utility equities at the present time?
e23'.
The delays and changes often involved in the licensing of generating 24 25 26 27 28 plants are unpredictable and costly.
Uncertainties relating to environmental requirements, and potential costs associated with such requirements constitute risks.
The more likely probability during these times of high energy prices and often vocal consumer reaction that governmental or regulatory action (or inaction) willprove harmful
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is a risk which investors obviously consider.
The possibility of adverse governmental and regulatory action constitutes risks which 3
today's equity investors consider.
4 g.
What rate of return are you requesting in this proceeding?
5 A.
We are requesting rates that would produce additional revenue of 6 '22,486,985 annually.
Based upon the 1975 test period, this would yield a return of 12.18%
on common equity.
Because of attrition and continued inflation, we would expect to actually earn less than 9
this indicated test year return.
10 As our expert, Dr. John Langum, testifies, the Company should actually earn a rate of return on common equity of 14.5%.
This is the rate which he finds fair and reasonable and it is also the rate which the Company feels is )ustified.
12 13 Our original application in this case 14 was prepared to seek a return on equity of this amount.
However, subsequent 15 decisions by the Company with respect to the normalization of certain 16 tax deferrals have resulted in a decline in the rate of return which the 17 requested rates would produce.
18 Q.
What consequences do you foresee from a failure to obtain the rate 19 relief requested in this proceeding?
20 A.
A failure to obtain all of the relief would have serious adverse 22 23 effects of an immediate and long-lasting nature.
Unless our A bond rating is restored by Moody 's, it will be difficult, and perhaps impossible, to raise the amounts of capital required to continue our 24 25.
26 27 presently planned construction program.
Even if it is regained, it cannot be considered secure without the total increase -requested in this proceeding.
Consequently, should we fail to obtain the rate relief requested
- here, we would have to immediately review our construction program with a view toward reducing it further.
Should we receive significantly less than the total relief requested, our bonds could be downrated even further perhaps to a point'here our ability to obtain capital would be totally restricted.
The nation's governmental and corporate debt capital requirements are such that A or lower rated long-term debt funds willbe often unavailable at any price. I think it fair to say that should we not regain our A/A bond rating, or should we regain it and fail to maintain it, our ability to raise necessary capital will be impaired to the point that more 10 11 12 13 14 construction delays will be necessary.
Should our bond rating deteriorate to a Baa/BBB the situation would become most perilous and substantial cutbacks in our construction program would immediately follow.
Should our rating drop even lower than Baa/BBB, our construction pxogram would come to an immediate halt and mass future shortages of 15 electrical energy in our service area would be assured.
There is no 16 'ajor electric utility in the United States which Moody's rates below 17 19 Baa.
- Thus, a reduction in CP&L's rating to Ba by Moody's would effectively eliminate the ability of CP&L to raise funds in the capital market.
20 Q.
21 In past rate proceedings, certain intervenors have insisted that rates should not. be raised in order to construct plants for future use.
Would 22 23 A.
25 you please comment on this position.
In requesting adequate
- rates, we are not requesting that today's rate-payer finance plants that will be used in the future.
What we-are requesting is that rates be set so that our present costs, including the cost of a reasonable retuin on capital, be covered.
,The rates which we are proposing are rates which are fair based upon our pr'esent plant in service.
No lesser rates would be fair or adequate even if we did not have a construction program.,
The reason our construction requirements are emphasized is that unless our investors earn a fair rate of return, based upon today's plant in service and today's level 8
'0 Q.
11 A.
12 13 of costs, our credit rating will not permit us to borrow.the necessary funds with which to continue construction activities which are essential in order to have power available in the future.
Will you please briefly review your Company's present construction program.
Our construction program, which is subject to continuing review, is shown on Harris Exhibit No. 2.
During 1975 our construction program underwent substantial downward revisions. It is now tailored to the i~
l
=
15 16 amount of capital which the Company reasonably hopes to attract assuming appropriate rate relief.
Based upon present construction plans and the Company's revised load forecasts, the Company's generating reserve margin 17 18 19 20 Q.
21 A.
22 will drop to 4.9 percent in 1981, a negative 2.4 percent in 1982 and a negative
.8 percent in 1983.
It will return only to a positive 2.1 percent in 1984.
What is the percentage of reserve capacity which your Company is planning?
Up until 1974 the Company had a goal of 18 percent reserves.
This was based upon reserve levels recommended by the Federal Power Commission and 23 considered adequate by the Company.
However, during 1974 it became
- 24 25 evident to the Company that it would be unable to attract adequate capital to provide these reserve levels. It was therefore necessary to reduce j
s 6
7 A.
the level of planned reserves from 18 percent to 12 percent.
We anti-cipate no difficulty in meeting this reserv'e criteria thro'ugh the year 1980.
As pointed out in my answer to the previous question,
- however, the Company will be unable to provide even this minimum level of reserves after 1980 if the demand increases at the rate expected.
What is the Company's demand forecasts for the next 10 years?
We expect demand to increase by 7.4 percent annually during the next 10 years.
This compares with an annual increase at a compound rate 10 of 10.4 percent over the 10 years ending in 1974. It is obvious that the construction now planned by the Company is a minimum construction 12 13 14 Q.
15 16 A.
17 18 19 20 21 program which will not maintain the Company's 12 percent reserve goal in certain future years unless the growth in demand increases by no more than an average of 6.5 percent over the next 10 years.
Could it be that your growth forecasts are in excess of what should reasonably be expected?
Our forecasts are based upon two studies one conducted within the
- Company, and one conducted by a highly qualified outside consulting
- firm, Whereas, in past years we have tended to approve a mid-range of the upper and lower forecasts that have been proposed, our latest approved forecast accepts the lowest rate of growth suggested as probable by the studies.
It would certainly seem imprudent to ignore 22 what these studies tend to show.
In August of 1975 we had a peak 23 24 demand of 5060 megawatts, which is in excess of the 5001 megawatts we were projecting for 1975. It is the peak demand that determines the 25 amount of capacity which we must have available.
1 e.
2 A.
3.
What growth are you experiencing in KWH sales' Our sales growth was slower in 1975 than expected although with respect to certain classes of customers it was in line with our projections.
As I have pointed out, our peak demand forecast 7
A.
10 q.
ll 12 A.
13 14 15 did turn out to be conservative.
What" has been your sales increase to date in 1976'?
Through March of 1976, usage by our customers increased by almost 13% over that of the first quarter of 1975; Should this continue, our 1976 sales forecast would prove overly conservative.
How has your Company's load factor been affected by recent kilowatt-hour sales experience?
As peak demands have continued to increase while kilowatt-hour sales remained relatively flat, we have seen a natural deterioration in our load factor.
This has not been in the interest of the ratepayer or'he Company.
17 A.
18 Would you please describe your Company's future capital requirements.
Although our construction program has been reduced considerably, the capital requirements remain enormous.
$6.3 billion will be required over the next 10 years.
$826 million is necessary for the years 20 21 1976-78, and a substantial portion of this must be raised through the public sale of capital stock and first mortgage bonds.
22 23 As a result of inadequate
- earnings, the Company's last three common stock issues had to be sold below book value.
This means that 37 percent of the common shares now outstanding has been sold below 2
3 book value and although there has been an improvement in the price of our stock as the stock market generally has improved, it continues to sell below book value.
The dilution in the value of common stock owned by investors at the time of those sales has been substantial.
The Company must again sell common stock in the fall of this year.
Should these applications not be allowed in their entirety, and should the Company be forced to make refunds of amounts already collected, we would not expect a successful stock sale.
Mr. Harris, one of the three objectives of this rate case,'hich you mentioned at the beginning of your testimony, was that the Company be 12 able to continue normal maintenance.
Would you elaborate on this, please.
13 A.
Yes.
A part of the rate increase requested is to continue our normal maintenance program which we were able to reinstitute after interim 15 retail increases became effective last fall.
Normal maintenance 16 17 18 20 21 A.
22 is now underway pending the outcome of this general rate request.
Unless all of the relief requested in this fi.ling is a11owed, it wil1 be necessary for us again to defer some maintenance expenditures.
Why did your Company ever depart from what you term a "normal maintenance program"?
ln 1974 it became apparent that the rate relief sought in applications filed in October 1973 would not be sufficiently timely nor adequate to restore earnings to a level where the Company's securities would be attractive to investors and could be sold on reasonable terms.
Consequently, in order to preserve the Company's financial integrity and to be able to continue to finance its construction program, we went beyond our on-going cost control program and inaugerated an emergency expense curtailment
- program, which was designed to delay or eliminate costs.
This program was called to the Commission's attention during testimony in rate hearings in 1974.
The program eliminated some reasonable and proper expenses and deferred some essential expenditures pending an improvement in the 9
10 Company's financial condition to a point.where its A bond rating would be less insecure and it could market common stock and other securities on reasonable terms.
However, notwithstanding vigorous cost reduction 12 efforts the Company's coverage of fixed charges dropped below 2 times to 1.92 times at year end 1974.
In February 1975, the Company's bond 14 15 16 17 rating was reduced from A to Baa by Moody's Investors Services, Inc.
and we have not recovered financially to a point where delayed and
'I badly needed expenditures can be resumed without further threat to our financial stability.
In early 1975 it became necessary to further reduce our level of maintenance to partially compensate for revenues 19 lost when the North Carolina Commission restricted collections under 20 21 22 23 24 the fuel clause, and for the further purpose of attempting to raise our earnings coverage of fixed charges to a level where we could continue to market securities without having to pay exorbitant prices.
That level of maintenance continued until our interim retail rate increases were placed into effect last year.
1 Q.
To what do you attribute your Company's present financial condition and the fact that it has been unable.to earn the rates of return allowed by this Commission?
4 A.
10 12 13 14 16 There are four major cost factors, all of which are beyond our ability to absorb or defer, that have led to our present depressed financial condition.
The first factor is a continuing high rate of inflation which affects electric utilities to a greater extent than industry generally.
Our present rates, as the Commission is well aware, were based upon costs in a 1973 test year.
A second factor which I will mention and a most major factor is the cost of capital.
The cost of capital obtained on a long-term basis has continued to increase.
The
$100 million in First Mortgage Bonds which we issued in April of 1975 was at a cost of 11.24%.
This compares to an average cost for bonds issued in the former test year of 1973 of less than 8%.
At the end of the last test period, the average interest rate of,the Company's First Mortgage Bonds was 17
~6.78%.
By December 31, 1975 this had increased to 7.72%.
On December 31, 18 19 20 1973 the average dividend rate on preferred stock was 7.24% on the preferred stock outstandin In March of 1975 we issued preference g
stock at a cost to the Company of 11.21%.
As I have previously mentioned, 21 22 23 we were unable to issue preferred stock at this time because our earnings were insufficient to meet the earnings coverage requirements of our charter.
The average dividend rate on preferred and preference stock 24 25 is now 8.06%, having risen 11% over the average dividend rate on December 31, 1973.
The cost of servicing common equity has 'also increased significantly as we have been forced to sell additional common stock at below its book value.
En our last rate case, I testified that in November, 1973 we were required to sell 3,000,000 shares of common stock at a "distressed price."
That stock sold for
'$21.25 per share, and netted to the Company proceeds of. $20.31 per share after underwriting discounts.
Since that time, we have sold 4,000,000 shares of common stock "in January 1975 at a price of 10 13
$14.75 per share, 31% less than the
$ 21.25 per share of,the November 1973 issue.
The net price was'nly
$14.00 per share.
In October 1975 we sold 5,000,000 shares of cpmmon stock at
$17.'875 a share, 23% less than the
$ 23.34 book value.
The net price was only $ 17.215 a share.
A third factor has been expenditures which we have made," and are continuing to make in increasing amounts, for environmental protection..
15 16 17 18 19 20 Since the beginning of 1972, we have invested over
$84 million in devices to protect -air and water.
We are spending about
$ 30 million annually for systems that do not add to our capacity indeed many use substantial quantities of energy.
Consequently, the cost we experience is not limited to the cost of servicing the capital required to install the systems and devices; our cost of producing electricity 22.
for sale increases since a portion of our gener'ation must be used to operate some of the environmental devices.
We simply cannot absorb the tremendous costs involved.
When we filed our last rate case, in October of 1973, we firmly believed that the cooling system then planned for the Brunswick Nuclear Plant was not only adequate, but was acceptable to state and federal regulatory authorities.
Since that time, we have been ordered to install cooling towers at a cost of 10 ll 12 over
$72 million.
We are attempting to avoid this requirement as we feel that it is a useless expenditure of the electric consumers money.
I However, it has been necessary for us to beginiconstruction of the cooling
- towers, and whatever costs are ultimately incurred will have to be recovered through increased rates.
A fourth major factor is attrition.
Cost of building power plants and other facilities has increased dramatically, and as new facilities are brought on line and into the rate base, it is necessary that costs associated with them be recovered.
The cost of our Robinson Nuclear Unit completed in 1971 was about
$127 per kilowatt capacity.
Our Brunswick No.
2 plant, which entered commercial operation in November of last year cost about
$485 per kilowatt capacity.
While decreased 18 19 fuel costs associated with this nuclear plant means lower overall rates to the consumer than would be possible with other forms of 2O n
22 23 24 generation, the capital and other fixed costs associated with this generating plant have to be recovered through increased base rates.
As new and more expensive facilities become a part of the Company's rate
- base, the capital and other fixed costs associated with generating electricity increases accordingly.
What action has your Company taken to reduce its expenses?
2 A.
The Company continues a vigorous cost control earnings improvement 3
program which eliminates or defers expenses for items that are necessary 4
5 6
7 and proper business expenses in the sense that they are desirable and reasonable but are of the nature that they can be postponed indefinitely or delayed.
As a part of its regular business practice the Company has always maintained a cost control program in every department, and the prevention of unnecessary cost has always been an item of top priority with the Company's management.
The commitment of the Company to "frugality" is well known to all who have ever been associated with effect, however, goes beyond the Company's tradition of austerity.
ll its operations.
The expense curtailment program which is now in 12 13 14 15 16 17 18 19 For instance, no new personnel may be employed without the specific approval of me as Chief Executive Officer. I do not approve the filling of any vacant positions unless it is demonstrated that the I
new employee is absolutely essential in order to assure that necessary tasks can be carried forth.
Budget restraints have been imposed on all departments.
Moreoever, we have organized within the Company a Corporate Performance Review Department.
Among its 2O duties is the responsibility of analyzing the performance of 21 22 23 24 25 the various facets of our Company's operation and comparing them with those of other companies.
If other companies are out-performing CP&L in any area, the responsibility of this Department is to determine why. If any other similarly situated company is doing anything more efficiently and at less cost than this Company, we
want to know about it and can assure'he Commission that we wi11 implement any changes necessary that might improve our performance 3
even further.
4 Q.
Is your corporate analysis far enough along to give any indication
'5 of how your Company compares with other similarly situated companies?
6 A.
Yes indeed.'ur total operations compare most favorably with those of the industry generally and with eight similar southeastern investor-owned companies with which we have made comparisons.
For instance, the Company's total operating expenses and interest charges per kilowatt-10'1.
12 13 14 hour1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> of energy sold was less than that experienced by six of the other seven comparison companies during the year 1974.
Stated another way, we delivered more kilowatt-hours per dollar of total operating expenses and interest charges than did all but one of the other comparison companies.
A study of the 50 largest investor owned electric utilities 15 in the country shows that while CP&L was 28th from the largest customer 16 17 18 19 20 21 Q.
22 wise, in 1970, 26th in 1971, and 25th in 1972, its operations and maintenance expenses per kilowatt-hour sold were "32d. from the highest in 1970, 34th in 1971, and 39th from the highest in 1972.
Complete
~ figures are unavailable for subsequent years at the present time;
- however, we believe that the trend is continuing.
Are you familiar with the recent comparison study of electric utilities released by the National Association of Regulatory Utility Commissioners?
23 A.
Yes.
Me have received copies of the report and have analyzed it. It confirms our own studies and shows that our Company compares most 25 favorab1y" with other companies. in every area studied.
1 Q.
Would you have any objection to a management audit of your Company 4
2 by an outside consulting firm?
3 A.
None whatsoever.
I have stated publicly on any number of occasions that we would welcome such an audit.
The North Carolina General Assembly has authorized the North Carolina Utilities Commission to order audits once every five years with the expense being paid by the companies and recovered through rates.
The Commission has recently employed the firm of Booz, Allen and Hamilton to conduct a review of our Company and I would expect this firm's 10 11 12 findings to be made available to the South Carolina Commission and to the public By the time we have hearings in these proceedings this review should be well underway.
We are confident that the audit willreveal that we are managing efficiently.
Is your Company asking for a continuation of the fuel clause?
A.
Yes.
The details of our recommendations are contained in the testimony 14 of other witnesses.
Q.
Do you consider a continuation of the fuel clause necessary in view of the fact prices have stabilized?
18 A.
By all means.
Fuel costs comprise such a large portion of our operating 19 expenses that even slight fluctuations amount to tremendous sums of money.
20 If the fluctuations are downward the customers should receive the benefits.
21 If they are upward, the Company must cover its cost.
- Moreover, we are 22 sta.ll subject to immediate and extreme upward fluctuations in fuel prices 23 which cannot be accommodated through traditional forms of rate hearings.
25 Finally, the introduction of larger percentages of nuclear generation on our system means that monthly costs of fuel will vary significantly even if fuel prices remain level.
This is because nuclear fuel is so, much less expensive than fossil fuel.
In nuclear generation fuel cost will be months when we get substantial
'1 down.
However, in months when nuclear plants are out for refueling or sub)ect to other outages fuel costs will increase appreciably.
We are of the firm opinion that a fuel ad)ustment clause is a fair and equitable means of compensating 7
for fuel cost fluctuations.
Q.
Mr. Harris, would you please summarize your testimony.
9 A.
My testimony essentially is that notwithstanding rate relief previously 10 granted by this Commission, the level of earnings of the Company remain 12 13 and its financial integrity is continuing to decline.
In order to continue our "bare bones" construction program, it is absolutely essential 14 15 that our bond rating be restored by Moody's at the earliest possible moment.
11 significantly below what the Commission has previously determined fair and reasonable.
This means that CP6L is not recovering all of its costs 16 17 18 19 20 For the bond rating to be restored and maintained, it will be necessary that our coverage of fixed charges improve to a level of at least 2 1/2 times and be maintained there for an appreciable period of time.
Without rate relief, we would expect the amount and quality of our earnings to decline dramatically, especially as new plant comes into service.
Without rate 21 22 relief which we now request, our bond rating will be sub)ect to further
/
deterioration and drastic cuts will have to be made in what is already 23 24 25 26 a "bare bones" construction program.
Beyond any question, unless we obtain the rate relief requested in this application, the Company's ability to continue to provide service efficiently to its customers will ultimately suffer.
South Carolina Public Service Commission CAROLINA POWER & LIGHT COMPANY DIRECT TESTIMONY OF EDWARD G. LILLY, JR.
1
'Q Please state your name and business address.
2 A.
Edward G. Lilly, Jr.,
336 Fayetteville Street, Raleigh, Noith 3
Carolina.
4 Q.
What is your position with Carolina Power
& Light Company?
5 A. I am Senior Vice President-Finance of the Company.
Q..Please describe your educational background and business 7
experience.
A. I am a graduate of Davidson College where I received a degree 9
of Bachelor of Science in Economics.
I hold a Master of 10 Business Administration degree in Banking and Finance from the Wharton School of Finance at the University of Pennsylvania.
12 13 I am a graduate of the Executive Program of the University of North Carolina and I have completed the Irving Trust Company 14 Public UtilityFinance Seminar.
I am a member of the Executive 15 Committee of the Edison Electric Institute Finance Committee.
16 17 18 From 1952 to 1971 I was associated with Wachovia Bank and Trust Company, where I held various positions which 'were related principally to financial analysis, handling loans for corporate 19 customers and administration.
From 1963 to 1970 I served as 20 Senior Vice President and Office Executive of Wachovia's banks 21 in the Durham area.
During 1970-1971 I served as Manager of the
Investment Services Department at Wachovia's headquarters in Winston-Salem.
In March 1971, I became associated with Carolina 3
Power
& Light Company as Senior Vice President-Finance.
4 Q.
Please describe your duties as Senior Vice President-Finance of 5
Carolina Power
& Light Company.
A. I am the senior financial officer of the Company and as such I am 7
responsible for the long-term and short-term financing programs 8
of the Company.
I have responsibility for planning and implement-ing the issuance, sale and servicing of first mortgage bonds, 10 preferred
- stock, common stock and any other securities issued by the
- Company, as well as short-term financing arrangements of the 12 13 Company including the negotiation of bank loans an'd commercial 4
paper.
In addition, I am responsible for developing and maintain-14 15 16 17 18 19 20 21 22 ing the Company's investor relations program with the financial community.
I have overall responsibility for the treasury, accounting, computer services, purchasing and internal auditing functions of the Company, including preparation of budgets and forecasts and all financial statements issued by the Company.
My responsibility also includes the management of Company funds to insure that the Company has available at all times sufficient cash to pay its expenses of operation and to meet its payments for con-struction work.
Please state the nature and scope of the testimony which you will 24 offer.
25 A.
This testimony will relate to the Company's financing plans which 26 must be implemented in order to obtain the funds necessary to meet
the tremendous challenge facing the Company of constructing sufficient generating and other necessary facilities to meet the needs of our customers and to the problems facing the Company in 4
the undertaking of this financing.
Q.
Will you please explain the Company's financing plans?
A.
Despite the emphasis on energy conservation which has been stressed 7
by the Company for several years,'he electric energy demands of 8
our service area continue to grow to such an extent that the 9
Company's planned construction expenditures for the next 10 'years 10 12 will amount to approximately
$ 6.3 billion.
In the first quarter of this year, energy demand rose 13 percent over the same period last year.
We anticipate that approximately
$4.0 billion of this 13 amount must be financed through the attraction of new capital to 14 the Company from the sale of securities in the financial market, 15 16 an amount unprecedented in the history of Carolina Power
& Light Company.
The impact of this program is brought into focus by 17 comparing the additional
$ 6.3 billion plant investment with the 18 Company's net plant account of $ 2.2 billion at year end 1975.
19 Looking to the immediate future, the Company's construction expendi-20 21 22 tures for the years 1976 through 1978 are expected to amount to
$ 826,000,000.
In order to finance this three-year construction program, the 23 Company must raise a substantial portion of the
$ 826,000,000 by 24 25 the attraction of additional capital to the Company.
These funds can be obtained only through the sale of the Company's securities 26 to willing investors in the open market.
The Company now has
~
1 about 91,000 shareholders.
Over 39,000 of them, or approximately 43%, are located in the Carolinas.
We cannot expect investors to continue to invest their savings in our Company unless we can earn'n adequate rate of return on such investment and provide satis-5 factory dividends.
6 Q.
How does the Company plan to secure funds to meet its construction 7
program for the years 1976-19782 8
A.
A portion of the required funds will come from retained earnings, 10 charges to depreciation and deferred income taxes.
- However, a major portion of the funds must be obtained by the sale of additional securities of the Company.
We must sell new securities in sub-12 stantial amounts each year.
13 14 15 16 17 A brief review of the securities offered to the public by th' Company during 1975 illustrates the cost penalties which must be borne by the Company and its customers as a result of an unsatis-factory financial condition.
During January 1975, it was necessary for the Company to sell 18 common stock in order to attract capital and to improve the common 19 20 21 22 23 equity ratio of the Company which had fallen to a low level of less than 30%.
The Company sold 4,000,000 shares of common stock which resulted in a net'rice to the Company of only $ 14 per share, which was approximately 60% of the book value of the common stock at the time of the sale.
Obviously, such a sale of common equity 24 25 is extremely unsatisfactory and substantially dilutes the value of the shares of common stock previously held by the Company's share-26 holders.
During March 1975, the Company would like to have sold preferred stock.
- However, because of the continued decline in earnings avail-able for interest and preferred dividends, the coverage ratio for interest'ayments and preferred stock dividends had been reduced to the level where the Company did not meet its required Charter test
'to market preferred stock.
Thus, it was necessary for the Company to sell preference
- stock, a junior security to preferred stock, in order to attract needed capital.
Since the preference stock was basically 10 unattractive to institutional investors, it was necessary to offer the stock at a 925.00 issue price, as opposed to the
$ 100.00 issue 12 14 price which had previously been used by the Company for distribution of preferred stock, thus substantially increasing the distribution cost.
The net cost to the Company for the funds obtained through the sale of preference stock was 11.17%,
the highest rate ever paid 15 by the Company on preferred or preference stock.
16 During April 1975, the Company offered
$ 100,000,000 of first
'7 mortgage bonds.
Since the Company was utilizing the fund's to finance 18 generating and other long-life equipment installed for the benefit 19 20 21 22 of its customers, the Company wished to sell bonds with a maturity of 30 years.
- However, as a result of the bond rating of the Company having been reduced from A to Baa by Moody's Investors Service, because of the unsatisfactory earnings of the Company resulting in fixed charge coverage of less than 2.0 times, it was not possible 24 for the.underwriters to market 30-year bonds on any satisfactory 25 basis.
- Thus, the maturity of the bonds had to be reduced to nine 26 years and sold at a net cost to the Company of 11.24%.
This cost was the highest cost the Company had ever experie'need in connec-tion with its first mortgage bonds.
During the fall of 1975, the common equity ratio of the Company was again at an extremely low level of less than 30% and thus it was necessary for the Company again to sell common stock in order to attract capital and improve the common equity, ratio.
The Company 7
sold 5,000,000 shares of common stock during'October 1975 at a net 8
price to the Company of 917.215 per share or approximately 75% of 9 'ook value.
Again, this sale of common stock resulted in additional 10 12 13 14 15 substantial dilution to the present shareholders of the Company.
During the years 1976-1978, the Company will need to sell sub-stantial additional amounts of securities.
The exact timing and types of securities sold will be influenced by the ability of the Company to meet coverage ratio tests and maintain a reasonable capital structure, as well as the conditions of the securities markets during 16 those years.
One of the major problems facing the, Company is the 17 need for continued sales of large amounts of common stock, which the 18 Company needs to sell at prices above book value.
19 Q.
What, if any, other problems do you feel the Company faces in 20 carrying. out this financing program?
21 A.
Historically, the Company has raised capital for its construction 22 23 24 25 program through the sale of first mortgage bonds, preferred stock and common stock.
Let me examine briefly the current situation relative to the Company's ability to issue such types of securities.
First Mort a e Bonds 26 Table I listed below shows the average cost of outstanding
3, bonds at the end of each of the past ten years and at June 30, 1975.
As recently as December 31,
- 1969, the average cost of all bonds outstanding was 4.72%.
This, average cost has increased with the sale of each issue of bonds by the Company and had reached 7.72% by year end
- 1975, an increase of 63% during the six-year period.
TABLE I 8
Year End of Year Embedded Cost All Bonds 10 1966 4.04 1967 4.40 12 1968 4.72 13 1969 4.72 14 1970 5.64 15 1971 6.14 1972
.6.40 17 1973 6.77 18 1974 7;29 19 1975 7.72 20 21 The ability of the Company to acquire capital through the sale of first mortgage bonds at a competitive interest rate is 22 principally determined by the rating which the first mortgage 23 bonds of the Company are assigned by the major bond rating 24 25 26 agencies.
As a result of declining earnings and thus declining fixed charge coverage ratios, the first mortgage bonds of the Company were downrated during 1971 by both of the major rating
4 agencies from AA to A.
Fixed charge coverage ratios declined further during 1973 and 1974 and by December 1974 had dropped to the dangerously low level of 1.92 times.
Moody's reduced h
the rating on the Company's first mortgage bonds to Baa, further aggravating the ability of the Company to raise needed capital.
During the second half of 1975, principally as a result of the addition of revenues collected, subject to refund, under South Carolina and North Carolina interim rate increase orders and 10 a wholesale rate increase order from the Federal Power Commission, the Company's fixed charge coverage improved slightly to 2.27 times by year end 1975.
- However, we feel it absolutely necessary for the fixed charge coverage ratio to increase to a minimum of 2.5 times 13 and to remain somewhat above that level in order for the Company 14 to retain its A bond rating and to hold such a bond rating.
Table II lists the year end fixed charge coverage ratios of 16 the Company, as calculated under the Securities 6 Exchange
- formula, 17 for the past 10 years.
18 TABLE II
.19 Year Fixed Char e Covera e Ratio 20 1966 5.16 21 1967 4.87 22 1968 4.32 23 1969 3.38 24 1970
.2. 25 25 1971 2.50 26 1972 2.90, 27 1973 2.34 28 1974 1.92 29 1975 2.27 As shown, as recently as December '31, 1972, the fixed charge coverage ratio was 2.90 times, but had declined to 1.92 times as of December 31,
- 1974, a decline to a dangerously low level.
While the collection of "subject to refund" revenues allowed under interim rate orders and the receipt of a rate order making permanent all revenues collected on North Carolina retail sales has resulted in an improvement in fixed charge coverage during recent months, as of the time of the preparation of this testimony, the Company still has not 10 received a restoration of its A bond rating from Moody's Investors Service.
If the coverage of fixed charges does not continue to 11 improve in the near future, the Company risks not only a continuation 12 of the Baa rating assigned by Moody's, but a downgrading of the A
13 rating presently assigned by the other major bond rating agency.
14 Q.
What effect has the reduction of the rating on the Company's bonds 15 from A/A to Baa/A had upon the Companyf
~
A.
T1ie reduction of the rating on the Company's first mortgage bonds 17 18 to Baa/A has had three major negative effects upon the Company.
First, the reduction in rating requires that the Company pay a
19 20 21'2 23 24 25 26 substantially higher cost in order to sell its bonds.
In his testimony, Mr. Shearon Harris has pointed out that in April 1975, after the downgrading of CP&L's bonds, the Company sold
$ 100,000,000 first mortgage bonds at a cost to the Company of 11.24%.
The next sale of a comparable size issue with a comparable maturity by an electric utility company with an A/A rating occurred a short time later when Florida Power
& Light Company sold
$ 100,000,000 of first mortgage bonds at a cost of 9.08%,
216 basis points lower than the cost CP&L was required to pay.
While the difference in cost between a Baa/A bond and an A/A bond will vary, it is expected that the cost differential generally will be high.
Since CP&L utilizes most of the funds obtained from the sale of first mortgage bonds to pay for assets with an expected life of 25 years or longer, it has been the practice of the Company to sell bonds with a maturity of 30 years.
Unfortunately, the CP&L
'I bond rating of Baa/A was not sufficiently high to attract investors to a 30-year maturity at the time of the 'last bond sale and thus 10 12 13 14 15 16 it was necessary for the Company to sell bonds with a maturity of only nine years.
Such action, 'of course, indicates that the risk of additional financing and the expense of additional financing must be met during the expected life of the assets.
- Second, a reduction in bond rating has eliminated certain sources of funds to the Company; that is, many institutional investors and large individual investors as a matter of policy or of legal limita-17 tion will not purchase a bond with a rating below A/A.
For example, 18 19 pension funds for the employees of the States of South Carolina and North Carolina may no longer be invested in bonds presently being 20 offered by CP&L.
Such restrictions of the market in which the 21 bonds of the Company are sold increase greatly the difficultyof 22 23 marketing the Company's bonds at any reasonable interest rate.
Third, the reduction from the A/A rating of the Company's bonds 25 26 also has had a substantial adverse impact upon other financing costs of the Company.
At the time Hoody's reduced the Company's bond rating, it also reduced from A to Baa the rating on the Company's lo-
preferred stock and reduced the rating on the Company's commercial paper from Prime 1 to Prime 2.
The Prime 2 c'ommercial paper rating has resulted in the Company's cost for these short-term borrowings increasing by 50 to 75 basis points.
(i.e.,
6.00% to 6.50% or 6.75%).
The rating assigned to a Company's first mortgage bonds is in effect the "key rating" to which other securities and borrowings
~ of the Company are related.
The fact that CP6L's securities are now rated below investment grade has had a substantial adverse impact 10 upon the cost of long-term and short-term securities'ssued by the
- Company, as well as any lease financing or other types of financing 12 which the Company may utilize.
Preferred Stock 13 Q.
Please comment upon the difficulty, if any, of selling preferred I
14 stock.
15 A.
Table III lists the average cost of preferred stock of the Company 16 at the end of each of the past 10 years.
17 18 Year TABLE III Weighted 19 1966 4.72, 20 21 1967 1968 5.06 5.06 22 1969 5.06 23 1970 6.46 24 1971 6.91 1972 7.17 26 1973
- 7. 24 27 1974 7.54 28 1975 8.06
Here again, it is noted that as recently as December 31,
- 1969, the average cost of preferred stock was 5.06%.
As of December 31, 1975, this cost had increased to 8.06%,
an increase of 59%.
As was discussed earlier, during most of 1975, the
- Company, because of reduced earnings available to pay interest and preferred stock dividends, did not meet its Charter require-ments for the issuance of additional preferred stock.
- Thus, the Company simply was in a position where it could not issue preferred stock and had to resort to other, more expensive, sources of 10 capital.
In March 1975 it was necessary for the Company to issue preference
- stock, a class of stock rated junior to preferred stock,-.
12 13 14 15 16 17 18 at a cost to the Company of 11.17%.
The cost of issuing preferred or preference stocks with ratings.lower than A/A was quite high during 1975.
For example, during September
- 1975, Indiana Michigan Electric Company sold an issue of preferred stock with a rating of Baa/BBB at a cost to the Company of 12.75%.
It is noted that the rating obtained by Indiana Michigan Electric Company was above the
'I rating which could have been obtained on CP&L reference stock.
19 20 Since preference stock is a junior issue to referred stock, the rating agencies normally assign a rating to preference stock one 21 rating below the rating assigned to preferred stock.
22 Again, the collection of additional revenues, which are subject 23 to refund as aLlowed by interim rate increases, has allowed the Company's earnings to improve sufficiently to meet the Company's 25 26 Charter requirements for'he issuance of preferred stock provided such revenues are made permanent by the appropriate regulatory 27 authorities.
12-
Common Stock 2,
Q.
Please comment upon the common equity ratio of the Company.
3 A. It is vitally important that the Company, be able to sell common stock successfully.
Common stock is the foundation upon which senior capital financing rests..
The bond holder -and other senior capital holders look to an adequate common stock equity base for protection of "their investments.
Thus, the common equity ratio of the Company is extremely important in determining the Company's continued ability to sell senior securities.
The goal of the 10 Company is a
common equity ratio of approximately 35%.
The long-term financing plans of the Company are designed to achieve this 12 goal.
However, after the sale of two issues of common stock 13 totaling 9,000,000 shares during 1975, the common equity ratio of the Company is less than 33% and thus the Company will need to sell 15 16 additional common equity in the near future.
While general financial market conditions have improved and the market price of CP&L common 17 stock has also
- improved, the stock of the Company still has a
18 market price below book value.
19 Q.
Does the Company experience any significant difficulties in attract-20 ing common equity?
21 A.
During 1965, the common stock of CP&L sold at
$ 52 per share.
During 22 23 24.
25 late
- 1974, the common stock of the Company sold below
$ 11 per share or at less than 50% of book value.
Table IV shows the relationship of the sales price of common stock to the book value per share for the last four sales of common equity by the Company.
Date of Sale TABLE IV Number of Shares Net Price Per Share Book Value Percentage
~ Above or Below Book Value ll/9/72 2,500,000 11/15/73 30000,000 1/16/75 4,000,000 28.05 20.31 14.00 21.16 23.25
,.23. 35 32.6 (12.6)
(40. 0) 17.215
.10/28/75 5,000,000 (25.6)
The rapid and sharp reduction from the ability to sell common 10 12 13 14 equity at more than book value to the necessity to sell at prices substantially under book value is having a severe impact upon the ability of the Company to attract common equity on any reasonable
.basis.
When the stock of a company is selling below book value, a
greater number of shares is required to be issued in order to obtain 15 a given amount of equity capital.
This action results in additional 16 dilution in the existing shareholder's equity and a dilution in his 17 18 future earnings per share.
Such action further depresses the market price of the existing stock, thereby increasing the cost of equity 19 and debt financing to the Company and making it 'even more difficult 20 for a company to finance on any reasonable basis.
21 Q.
Are there other factors which add to the difficultywhich the Company 22 experiences in raising the funds necessary to meet its construction 25 26 result from allowance for funds serious adverse impact upon the 23 responsibilities?
24 A.
- Yes, the substantial percentage of earnings of the Company.which used during construction has had a
securities of the Company in the financial markets.
Table V lists the amount and percentage of net income available for common stock that is composed of allowance for funds used during construction for the years ended December 31, 1969 through December 31, 1975.
7 12 Months Ended TABLE V Allowance For Funds Net Income Allowance For Used During Construction After Preferred Funds Used During As
% of Net Income
"'ecember 1969 24,418,000 4,397,000 18.0 20,126,000 10,505,000 9
December 1970 10
.December 1971 29,103,000 14,708,000 24,759,000, 38,093,000 52,982,000 12 December 1973 13 December 1974 14 December 1975 51,599,000 54,609,000 59,957,000 75,870,000 December 1972 50,917,000 52.2 50.5 48.6 71.9 105.8 79.0 15 Q.
Please explain the changes in this percentage and the significance 16 of these changes to the Company.
A.
During the year 1969, only 18% of the net income available for common 18 stock was a result of allowance for funds used during construction.
19 20 21 This percentage increased rapidly to a level of approximately 50%
during the period 1970 through 1972.
During the years 1973 through
- 1975, the percentage again increased sharply averaging approximately 85% during the most recent three years.
It is noted that during the year 1974, allowance for funds used during construction actually 24 exceeded net.income available for common stock.
Regardless of the 25 current accounting treatment of allowance for funds used during 26 construction as "nonoperating income," the amounts are not revenues
- 15
received from the sale of electricity.
When allowance for funds used during construction is excluded from the calculation for fixed charge coverages, the ratio for the year ended December 1975 drops from 2.27 times to an alarming level of 1.67 times.
10 This situation results from the large amount of construction work in progress upon which the Company realizes no cash earnings.
On average during 1975, construction work inprogress amounted to
$ 886,000,000 or approximately 75% of net plant in service.
- Thus, for every dollar of net investment of plant in service, the Company had approximately 75C invested in construction work in progress upon which it did not receive any cash earnings.
- Mitchell, 12 Hutchins, inc.,
a highly regarded research firm in the financial 13 14 community, conducted a study of 45 major electric utility companies during April 1975.
This study shows CP&L as the only company where 15 allowance for funds exceeded net income for common stock during the
'16 17 year 1974.
Such a condition obviously causes grave concern in the minds of investors as to the financial soundness of a company.
1 18 g.
Mr. Lilly, please summarize the factors,to which you have testified 19 which cause difficulty in attracting capital to meet the Company's 20 construction expenditures.
21 A. ~e financial condition of the Company deteriorated rapidly during 22 23 24 25 26 1974 and 1975.
Fixed charge coverage fell to extremely low levels.
resulting in a reduction in the ratings of the Company's first mortgage bonds, preferred stock and commercial paper.
The percentage of net income available for common stock represented by allowance for funds used during construction h'as increased rapidly and during
1974 allowance for funds used during construction actually exceeded total,net income available for common stock.
The cost of attracting capital to the Company has continued 'to increase and remains at a
high level.
These factors, when combined with a return on common equity of an amount less than the earnings level which this Commission has previously found to be fair and reasonable, have resulted in the necessity of the Company selling additional common stock at prices below book value.
The selling of common stock below book 'value further aggravates the serious financial condition of the Company.
Without the interim rate increases ordered by this Commission and other regulatory jurisdictions, the Company's financial condition continues to be critical.
The approval of the requested rates so as to allow the Company to restore its coverage of fixed charges and preferred dividends and to earn a reasonable return on equity capital is absolutely essential in order for the Company to continue to finance its operations and to provide adequate and dependable service to its customers'7-
South Carolina Public Service Commission Docket Nos.
18,361 and 18,387 CAROLINA POWER & LIGHT COMPANY TESTIMONY OF PAUL S.
BRADSHAW 1
Q.
Please state your name and business address.
2 A.
Paul S. Bradshaw, 336 Fayetteville Street, Raleigh, North Carolina.
3 Q.
What is your occupation?
4 A.
Assistant'Treasurer in charge of the Budgets and Statistics Section 5
of the Treasury and Accounting Department of Carolina Power
& Light 6
Company.
7 Q.
Please describe your educational background and business experience.
8 A. I attended Southeastern University and graduated from the Accounting 9
School'of that University with a Master's Degree in Accounting.
10 Immediately prior to joining Carolina Power
& Light Company in July, 11 1962, I worked for the Washington Gas Light Company, a natural gas 12 utility, in Washington, D.
C. I.am a member of the Finance Section 13 of the Southeastern Electric Exchange and also a member of the 14 Budgeting Committee of the Edison Electr'ic Institute. I have completed 15 the Public Utility Executive course at the Georgia Institute of 16 Technology.
17 Q.
What are your duties with Carolina Power
& Light Company?
18 A. I have been responsible for the operation of the Budgets and Statistics 19 Section since its formation in 1972. I am responsible for the 20 Budget Unit, Statistical Unit and Financial Analysis.
Prior to 21 formation of the Budgets and Statistics Section, I was Assistant 22 Controller in charge of General Accounting.
23 Q.
Please examine this document, marked "Bradshaw Exhibit No. 1,"
24 consistingof twelvepages, and state whether or not it was prepared 25 under your supervision and direction.
1 A.
Yes, it was.
(Identify) 2 Q.
Will you describe this exhib5.t?
3 A.
This exhibit sets out, the balance sheet of the Company as of 4
December 31,
- 1975, and statements of income and retained earnings 5
of the Company for the twelve months which ended December 31, 1975.
It contains notes which are an integral part of the statements.
7 This exhibit 'is the same as Exhibit I filed with the Commission 8
in.the series of exhibits containing data for the test period 9,
consisting of the calendar year 1975.
10 Q.
Will you please examine this document, marked "Bradshaw Exhibit No. 2,"
and state whether or not it was prepared under your supervision and 12 direction7 13 A:
Yes, it was.
(Identify) 14 Q.
Please describe this exhibit.
15 A.
This exhibit sets forth the original cost of the electric utility 16 17 plant in service of our Company as shown on our books and records at December 31, 1975.
After deducting
$ 18,507,102, representing 18 the accumulated provision for amortization of nuclear fuel, the 19 total amount of plant in service and nuclear fuel is
$ 1,888,955,553.
20 The plant in service is subdivided into functional accounts.
Of 21 22 23
- course, the nuclear fuel is related only to the production function.
This exhibit is the same as Exhibit C in the exhibits filed with the Commission.
24 Q.
Will you please examine this document, marked "Bradshaw Exhibit No. 3,"
25 26 and state whether or not it was prepared under your supervision and direction, and state what is shown on this exhibit2
I A.
Bradshaw Exhibit No. 3," which is the same as Exhibit D filed for the test period 1975, was prepared under my supervision and direction and states the amounts of the accumulated provision for depreciation of plant in service as shown on the books at
'ecember 31, 1975.
The amounts have been adjusted to reflect depreciation for a full year on plant in service at that date.
7 The amounts are shown by functional accounts corresponding to 8
the functional accounts under plant in service on my Exhibit No. 2.
9 Q.
Will you please state whether or not Bradshaw Exhibit No.
4 was 10 prepared by you or under your supervision?
L ll A.
Yes, it was.
(Identify) 12 Q.
Will you please describe this exhibit?
13 A.
This exhibit shows the Company's operating revenues and operating 14 expenses by major categories for the calendar year 1975.
15 Q.
Have you made any accounting and proforma adjustments to the test 16 year?
17 A.
Yes.
The adjustments made to the test year are summarized in 18 Bradshaw Exhibit No. 5.
19 Q.
Would you please explain these adjustments?
20 A.
Yes.
Adjustment No.
1 was necessary to correct insurance expense 21 for the test year.
Insurance expense applicable to the Brunswick 22 23 No.
2 unit in November and December 1975 was inadvertently charged to plant account and should have been charged to expense.
This 24 25 26 adjustment charges expense in the amount of $109,024.
Adjustment No.
2 is necessary'to charge-off one-fifth of the cost of abandoning the Craven County Plant site.
The five-year
write-off was ordered by this Commission.
Il Adjustment No.
3 is to normalize the effect of hydro generation for the test year.
The value of hydro generation in the test year was adjusted to the 45-year average hydro generation resulting in a charge to Expense of $1, 168, 558.
Adjustment No. 4 is to reflect wages for the test year based on the year-end level.
This requires an increase in operating expenses of $4,560,087 and a related increase in payroll taxes of
$ 234,822.
10 Adjustment No.
5 is necessary to reflect in the test year the 12 13 effect of a postage increase that was placed in effect December 28, 1975.
The effect on operating expenses would be an increase of
$ 293,331.
Adjustment Nos.
6, 7 and 8 are to increase maintenance expense 15 for the test year to a more normal level.
During 1975, because of 16 low earnings and coverage, the Company was operating under a program 17 of reduced expenses in all areas possible.
The expenses'hat were deferred or eliminated in 1975 must be resumed in the future.
During a normal operating year, additional maintenance expenses in 20 21 the amount of $ 5,217,000 would be required.
The amount deferred in each category was production - $507,000; transmission - $710,000; 22 23 24 and, distribution -
$4,000,000.
Adjustment No. 9.was made to adjust depreciation expense to the level of plant in service at year-end and also to compensate 25 26 for a change in depreciation rates.
The change in depreciation rates is the result of a study made by Ebasco Services, Incorporated,
and will be testified to in this case by Mr. Reilly.
Adjustment No.
10 is necessary to compensate for an increase in Social Security taxes.
The PICA taxable wage base was increased from $ 14,100 to
$15,300 thus necessitating an increase'o the test year tax expense of $57,508.
Adjustment No.
11 relates the property taxes to the year'end level of Plant in Service at the end of the test year.
To adjust the property tax expense to the year-end level of Plant, in Service required an increase in pioperty tax expense of 10
$4,091,032.
12 Adjustment No.
12 is necessary to achieve comprehensive interperiod allocation of income taxes.
The adjustment in the amount of $15,614,000 to deferred taxes in the test year accomplishes full normalization of deferred taxes.
15 Q.
Will you state whether or not the Company maintains bank balances 16 as a part of its commitment in connection with loans obtained 17 from banking institutions.
18 A.
Yes.
19 Q.
What was the amount of such bank balances supporting loan 20 commitments at December 31, 1975.
21 A.
The amount of such balances then was
$9,350,000.
These funds 22 are not maintained to support normal bank accounting services 23 24 such'as checking and collection of funds deposited, but are specifically required in connection with credit extension.
25 Q.
Is the Company requesting any change in its treatment of deferred 26 fuel cost in this proceeding?
1 A.
Yes, it is.
The Company has been deferring the expensing of 2
increased fuel costs on its books until the month in which 3
related revenues are billed.
However, beginning with the effective date of the new fuel clause proposed in this 10 proceeding, we will no longer use deferral accounting for fuel expenses.
At that time all fuel costs will be expensed on a current basis.
When the new fuel clause goes into effect the books of the Company will contain two months'dditional fuel cost that must be collected from the customers.
This is fuel costs for the prior two months in excess of the base cost.
This fuel has been used in serving the customers 12 13 and must. be paid for by the customers.
Without collecting revenues to cover these deferred fuel costs, the Company will be 14 unfairly penalized and earnings will be adversely affected.
15 Q.
.How do you propose to collect this deferred fuel expense from the 16 customers?
17 A.
We propose to collect the deferred fuel expense by a temporary 18 19 20 21 22 23 24 charge on the customer's bill for a period of approximately 12 months.
The amount of the temporary charge will be determined by the amount of deferred fuel expense attributed to South Carolina retail sales at the time the new rates are placed in effect.
This amount could be collected in a shorter time period, but we believe 12 months is a fair and reasonable time period.
Assuming the new rates are placed in effect September 1, 1976, the charge
will be.072 cents per 15lH based on the fuel cost deferred in July and August.
This will be billed on Temporary Rider No. 40, which is attached as Bradshaw Exhibit No.
6.
A copy of this Rider is also included in the Exhibit which presents the alternate rates that the Company is.requesting in this proceeding.
South Carolina Public Service Commission CAROLINA POWER
& LIGHT COMPANY TESTIMONY OF JOHN J.
REILLY 1
Q.
Will you state your name and address?
2 A.
My name is John J. Reilly, and my place of residence is Glen
- Cove, Long Island, a suburb of New York City.
4 Q.
What is your occupation, Mr. Reilly?
5 A. I am a professional engineer employed by Ebasco Services Incorporated at 100 Church Street, New York City, and hold the position of Consulting Engineer.
8 Q.
9 A.
What kind of organization is Ebasco Services?
Ebasco has provided engineering,
- design, construction and 10 12 13 management consulting services to public utilities, other industries and governments for the past 70 years.
It is one of the foremost designers and constructors of power plants in the world.
14 Q.
Will you summarize briefly your education and professional 15 experience?
16 A., I am a graduate of Ohio University with a degree of Bachelor 17 18 19 20 21 22 of Science in Civil Engineering in the year 1932.
I also completed graduate courses in Power Plant Engineering at Columbia University during 1939 and 1940.
During the period 1933-1937, I worked for the City of New York as Structural Design Engineer.
I was employed by Ebasco Services Incorporated as a Design Engineer in April.1937.
Since 1937, except for a
two-year period of service in 'the Navy, I have been continuously employed by Ebasco.
During the ma)or part of the 37-year period I have been engaged in engineering work closely related to the appraisal of industrial property.
These appraisal studies were made generally for acquisition sale, financing, rate condemnation and tax purposes, or to satisfy the requirements of local, State and Federal regulatory agencies.
During this 37-year period, I assisted with appraisal studies for some 200 industrial and 10 12 government clients, more than half of which were public utility clients.
During this same period I either made or directed approximately 125 depreciation studies for some 55 public utility clients.
In connection with these appraisal or depreciation
.13 studies, I participated in conferences, or hearings, as a
'4 15 consultant, or expert witness, in proceedings before the following regulatory agencies:
16 17 18 19 20 21 22 23 Florida, Idaho, Indiana,
- Nevada, New Mexico, New York, North Carolina, Ohio, Pennsylvania, Rhode Island, South Carolina, Virginia, Washington, State Public Utilities Commission, Federal Maritime Commission, Federal Power Commission, Department of Justice and Internal Revenue Service.
24 I have also appeared as an expert valuation and depreciation 25 witness before Courts of law in the United States and Canada.
26 Q.
I-show 'you a document consisting of seven pages entitled Depre-27 ciation Studies involving Statistical Methods Made for Public 28 Utility Clients and ask you if that is a list of public utility 29 clients for whom you have made depreciation studies?
1 A.
Yes it is.
2 Q.
Are you a Licensed Professional Engineer?
3 A.
Yes, I am a registered Professional Engineer in the states of 4
Indiana, Louisiana, New York, Pennsylvania, Rhode Island, Virginia, Texas, and Washington.
.I also hold a certificate of qualification issued by the National Bureau of Engineering Registration.
8 Q.
Are you a member of any professional societies?
9 A.
Yes, I am a member of the American Society of Appraisers and 10 the American Society of Civil Engineers and formerly a member 11 of the Depreciation Accounting Committee of the Edison Electric 12 Institute from 1949 to 1973.
13 Q.
Was Ebasco employed by Carolina Power
& Light Company to make a
14 depreciation study in preparation for this case?
15 A.
Ebasco was given an assignment to make a depreciation'tudy of 16 the Company's electric plant in service at December 31, 1974.
17 Q.
How long has Ebasco been making depreciation studies for CP&L?
18 A.
Ebasco has been making depreciation studies periodically for the 19 20 21 22 23 24 25 26 Company since
- 1950, when it adopted straight-line depreciation accounting to meet the requirements of the uniform system of accounts of the North Carolina, South Carolina and Federal Power Commissions.
These depreciation studies were made by Ebasco every five years since 1950.
As a result of each study, Ebasco recommended annual depreciation rates for all functional classifi-cations of property and the Company generally adopted our recommendations for depreciation accounting purposes.
1 Q.
Were these depreciation studies made by you or under your direction?
3 A.
Yes.
4 Q.
I hand you this exhibit entitled, "Carolina Power
& Light Company Depreciation Study of Electric Plant in Service at December 31, 1974",
and ask if it was prepared 'under your supervision and direction?
8 A.
Yes, it was.
(Identify as Reilly Exhibit No. 2.)
9 Q.
Please explain this exhibit.
10 A.
Reilly Exhibit No.
2 is the latest of the periodic depreciation 12 14 15 studies which I have mentioned above.
It contains the results of our current investigation of average service lives, salvage and cost of removal for the various classes of property which the Company owns and the theoretical depreciation reserve requirement at December 31,
- 1974, based on the assumption that 16 17 these average service lives and net salvage had been used to compute the annual depreciation expense.during the expired life 18 of the property as of that date.
We propose to amortize the 19 difference between the theoretical depreciation reserve, so 20 21 22 23
- computed, and the book reserve over the estimated remaining life of each class of property at December 31, 1974.
This procedure, which has been recommended by the National Association of Rail-road and Utilities Commissioners, results in the inclusion of 24
$1,354,000 per annum as part of the annual depreciation expense.
The-annual depreciation rates which we 'recommend for the year
- 1975, as shown in Schedule l of Reilly Exhibit No. 2, contain the provision for this amortization.
4 Q.
Mr. Reilly, what are the bases for the lives, curve types and 5
net salvage rates you have selected for the various plant 6
accounts?
7 A.
Generally the average service lives, Iowa Curve types and net 10
,salvage selected for each account are based on my judgment after giving consideration to our analysis of available past retirement experience as determined from CP&L property account-ll ing records; present and anticipated future system requirements 12 of CP&L; and industry-wide experience and trends relating to 13 future life expectancy of various classes of property.
14 Q.
Mr. Reilly, can you be more specific by explaining to us the 15 approaches you used for each of the functional.classes of 16 property?
17 A.
Yes, I can.
- First, we looked at the production plant function 18 and segregated it into two separate groups.
One contained the 19 production plants comprising the fueled type of generation and 20 included nuclear, fossil fueled steam plants and gas turbine 21 22 units, while the other contained the Hydraulic Production, Plants.
The decision to approach
- steam, nuclear, and gas turbines
23 generation facilities as functional groups stems from the fact 24 that upon retirement of a generating unit, all associated
components are no longer useful.
Modern plant structures are also of little, if any, use for other purposes.
Massive out-lays of capital for large plants together with little retire-ment experience 'for comparable plant limit the use of actuarial studies.
For the fueled generating plants, there was little Company experience with regard to past retirements 10 12 and there occurred many new and important events since my last study which, in my opinion, would have a greater effect on my selection of lives of these production facilities than past-retirement experience considered alone.
There were basically three events which can be classified in two categories:
(1) environmental and (2) fuel, that occurred since 1970 which 13 have had drastic economic effect on this functional category.
14 Mr. Reilly, will you please explain the events which occurred 15 in the environmental category to which you gave consideration?
16 A.
Yes, I will. Prior to the late 1960's, there was little acknow-17 18 19 20 21 22 23 24 ledgement on the part of the government or by the public as to the pollution of the environment by our industrialization.
Some electric utilities were keenly aware of it and included precipi-tators in all their coal-fired power plants.
Other electric utilities, primarily those in larger urban areas, installed precipitators only in their newer larger plants, while some electric companies installed none at all. 'he action which brought the problem of pollution into focus and to the attention
of the public and industry, under the pressure of concerned
- groups, began in 1970 with the enactment of the "Clean Air Act of 1970", which required that the Administrator of the
'5 Environmental Protection Agency (EPA) promulgate national primary and secondary ambient air quality standards.
This e
act further required each state, within nine months after lf publication, to submit a plan for the implementation, main-
- tenance, and enforcement of the standards:
10
"...as expeditiously as practicable but...in no case later than three years from the approval of such plant" for the primary standards.
It also required 12 the implementation of the secondary standards in 13
"...a reasonable time."
14 Two years later, the "Federal Water Pollution Control 15 16 Act of 1972" was passed.
This act, aimed at eliminating polluting discharges into navigable waters by 1985, requires 17 19 20 21 that industries must have the most practicable cleanup equipment installed by 1977, and absolutely the best techno-logical equipment working by 1983regardless of cost.
Chemical limitations will become effective in 1977, with additional controls in 1983, and thermal limitations are to 22 23 become effective July 1, 1981, with possible deferral of compliance to July 1, 1983, if a system's reliability would 24 be seriously affected.
1 Q.
Mr. Reilly, turning to the fuel category, will you please explain 2
the events that occurred and which you considered in arriving at' your decision?
4 A.
Yes, I will.
Subsequent to the promulgation of the acts I just 5
- cited, the fuel oil crisis of 1973, which continues
- unabated, has 6
further aggrevated the conditions and affected the economics of 10 12 13 14 15 16 17 electric energy generation.
The fuel oil situation in 1973 and 1974 has further aggrevated and complicated the conditions under which electric utilities operate.
Fuel costs have risen and probably will continue to rise to new and higher levels.
Even competitive fuels, coal and nuclear, will rise as the demands for these increase with the trend away from oil.
The scarcity of natural gas will probably limit its use in the generation of electricity.
Most recently, the stated goal for this nation to become energy independent will result in the search for oil and gas in'emote and inaccessible
- areas, e.g.,
the Alaskan slope, from which transportation costs will be a significant factor.
The search 18 and development costs for other exotic energy conversion methods 20 21 and attendant facility costs, such as coal gasification, in this
/
high capital construction and financing era do not presage a quick k
and inexpensive solution.
22 Q.
What has been the effect of these events as they relate to the 23.
24 determination of average service lives and annual depreciation rates for fueled production plant?
1 A.
As a result of these
- events, the =entire fossil fuel generation function is in a state of flux due to the requirements for air
/
quality control, cooling water pollution control and the effects of the fuel crisis.
Any monies expended on old plants 10 to meet environmental protection requirements must be recovered over the remaining life of the facility.
(Fuel costs have risen and will continue to rise, forcing difficult decisions, as to the continued use of an old, less efficient plant.)
The economics of increasing fuel costs tied to additional substantial outlays of capital for air quality and/or water pollution control may well limit the life of old plants.
We, therefore, deem it 12 13 advisable to lower the service life of existing steam generating facilities notonly in order to recoup the capital spent on 14 15 16 environmental protection equipment but also due to a distinct possibility of early retirement for economic reasons.
Therefore, 3
we have recommended the lives and depreciation rates shown in 17 Schedule II of my Exhibit No.
2 for steam,
- nuclear, and other 18 production plant accounts.
19 Further, if the expected amount of capital required for SO 20 removal in the future is actually spent to make older plants meet 21 environmental requirements, then the annual depreciation rate as 22 recommended in this report could be inadequate.
23 g.
Mr. Reilly, will you summarize the effects of your consideration 24 of these events?
1 A.
Yes.
For Steam Production Plants, all of the aforementioned were taken under consideration in our recommendation to increase the normal depreciation rate for those steam gene-rating facilities we have classified as "Other Steam Production Plant" from the current 2.468 percent to 2.947 percent.
New steam plants of large size will be subject to even more stringent air and water control equipment than older plants.
While the expected life of production plant equipment itself may not be changed significantly, the 10 12 13 14 15 16 17 18 19 20 22 23 associated environmental equipment may require replacement 1 or 2 times over the plant's lifetime.
Little historical knowledge is available for plants operating at high temperatures.
It would be appropriate to expect a higher level of retirement and replacement of plant components subject to the higher temperatures and steam pressures to result.
It is our opinion that new steam production plants represented by Roxboro Nos. 1, 2 and 3, Asheville No. 2, and Sutton No. 3, plus any new plants coming into service should have a normal depreciation rate of 3.452 percent, which is 0.595 percent higher than the 2.857 percent recommended in 1969.
The rates for both old and newer steam production include an allowance of 5 percent net cost of removal (negative net salvage for Account 311 Structures and Improvements and Account 312 Boiler Plant Equipment.
The Iowa Type Curve 24 applicable to the steam plants was selected by judgment.
With regard to Nuclear Production Plant, at the time of our previous study the Company did not have any Nuclear Production Plants in service.
No statistical data are avail-able to make a historical analysis to determine the average life applicable to this relatively new type of plant, either on a Company basis or on an industry-wide basis.
Therefore, by judgment we have selected a depreciation rate of 4.225 10 12 13 15 16 17 18
'9 20 percent.
This is based on a 25-year average service life for all components, together with a negative 10 percent salvage factor for Accounts 321 - Structures and Improvements, and 322 Reactor Plant Equipment.
With regard to Other Production Plant, the Company's historical data are insufficient to apply statistical techni-ques to determine the average life of the gas turbines and related equipment included in Other Production Plant.
The Company is currently using a 30-year average life.
Due to the critical fuel supply for oil-or gas-fired turbine peaking plants, it is our opinion that the shortening to a 25-year average life is reasonable at this time.
Since we have estimated zero percent net salvage, the recommended annual 21 depreciation rate is 4.000 percent.
22 Turning to the balance of the production function, Hydraulic 23 Production, the depreciation rates I recommended in my Exhibit 24 No.
2 are based on the composite of the average lives assigned to each of the major components comprising the account.
The annual depreciation rate for each primary account for each plant is based on the composite of the average lives assigned to each of the major components comprising the account as of December 31, 1948, in the Ebasco study as of that date.
Certain changes were made to the original average lives as assigned in 1948.
The lives shown of the detailed sheets reflect the changes and support the annual rates used.
10 The rates for, the Walters Plant were originally used in our previous report entitled, "Carolina Power
& Light Company-12 13 14 Walters Project No.
432 - Actual Legitimate Original Cost and Accrued Depreciation (Recalculated with 150 year Ceiling Life)
Summary of Reserve Balances Years 1930 to 1956 Inclusive",
which was submitted and accepted by the Federal Power Commission.
15 The Blewett Falls and Tillery rates were used in our report 16 17 18 "Carolina Power
& Light Company - Blewett Falls and Tillery Hydroelectric Developments Projects No.
2206 Summary of Recommended Depreciation Rates and Reserve Balances'Years 1912 19 to May 1, 1950, Inclusive (Dated)
November 1961 Revised 20 21
- January, 1962.
These rates were accepted by the Federal Power Commission.
The determination of rates for the Marshall hydro-22 electric plant Project No.
2380 follows the same method that 23 was applied to the other licensed projects.
12'-
Q.
Mr. Reilly, now that you have explained the basis for your determination of lives for production function, will you 3
please continue with your explanation of how you selected 4
the lives and depreciation rates for the other functional' groups?
6 A.
Yes, l will.
As I indicated in Exhibit No. 2, in general, 10 the investigation of the service lives and mortality characteristics of the property in each account, other than production, plant, involved the following steps:
1)
An analysis of available past retirement experience I
from Company's acco'unting records, and 2) the modification 12 of the results of the analysis of such past retirement 13 experience to reflect judgment as to (a) present and antici-14 pated future system requirements and (b) industry-wide 15 experience and trends relating to future life expectancy of 16 various classes of utility property.
The Actuarial Method 17 18 of life analysis using dollar units was employed in compiling mortality statistics.
Data through December 31,
- 1973, was 19 analyzed.
20 The periods of years selected to provide experience data 21 for the life studies involving the methods l will discuss 22 23
- shortly, was limited by the following considerations:
1)
Primary accounting data must be on a consistent basis 25 26 2)
Experience used must be fairly indicative of what might reasonably be expected in the future 3)
Availability of useful data 1
Q.
Mr. Reilly, earlier you mentioned "curve types" and "net 2
salvage".
Can you explain these terms and how you arrived 3
at these factors?
4 A.
Yes.
The actuarial method used to determine average service 5
lives for the various types of property also yields informa-10 tion as to the dispersion of retirements about that average age.
In our study, we matched these dispersions with those, of the well known and frequently 'used Iowa Curves.
Net Salvage is the difference between the cost of removal and salvage value received fram property retired.
The net salvage percentages used in this report are expressed as a
12 percent of original cost.
13 Q.
Mr., Reilly, at this time will you explain the actuarial studies 14 you made?
15 A.
Yes.
The Actuarial Method of life analysis using dollar units 16 17 18 19 was employed in compiling mortality statistics for all accounts other than the production plant.
Data through December 31, 1973 was analyzed.
This method of analyzing past experience represents the application to industrial property of statistical 20 procedures developed in the life insurance field for investigating 21 22 23 24 human mortality. It is distinguished from other methods of life estimation by the requirement that it is necessary to know the age of the property at the time of its retirement and.the ages'f survivors, or plant remaining in service; that is, the installation date must be known for each particular retirement and for each particular survivor.
The application of this method to the Company's experience involved the statistical procedure known as the "annual rate method" of analysis.
This procedure relates the survivors of a given age in an account to the survivors of the previous age-year, thus yielding a sequence of annual survival probabilities* from which a survivorship characteristic can be constructed.
Similarly the ratio of retirements of each age.-year to the survivors of the previous age-year may be used to get a series of mortality 10 13 14 probabilities which may be converted into a survivorship characteristic.
The mathematical combination of these two factors results in a series of relationships which, if plotted on graph paper, form what is known as a survivor,'r mortality curve.
The length of this curve depends primarily upon the 15 years of experience available; so that, if the experience band 16 of years is short in relation to the average life of the property, 17 an incomplete or stub survivor curve results.
There are a number 18
. of acceptable methods of smoothing and extending this stub 19 survivor curve in order to compute the area under it from which.
20 21 the average life is determined.
The well-known Iowa Type Curve Method was used in this study.
In 1935, the Iowa Engineering 22 23~
24 Experiment Station of Iowa State College published Bulletin 125 entitled, "Statistical Analyses of Industrial Property Retire-ments" by Robley Winfrey.
This bulletin describes the development of 18 type mortality curves and their applicability to 'industrial property having.a wide range of mortality characteristics.
Since their publication in 1935, these.type curves have been frequently used by public utility operating companies for depreciation accounting, tax, rate and other purposes.
They have also found general acceptance with the Securities and Exchange Commission',
the Federal Power Commission, the Bureau of Internal Revenue and many state public utility commissions.
10 Q.
Please continue with your explanation of your actuarial studies ll of life analysis.
12 A.
In the mortality study of the Company's property, instead of 14 15 16 17 18 mathematically smoothing and pro)ecting the stub survivor curve to determine the average life of the group, it was assumed that the stub curve would have the same mortality characteristics as the type curve selected.
The selection of the appropriate type curve and average life was accomplished by plotting the stub curve on transparent graph paper and superimposing it on Iowa 19 curves of the various types and average, lives drawn to the same 20 21
- scale, and then determining by judgment which Iowa curve type best suited the stub.
In some accounts when this method was 22 23
- used, average lives different from those indicated by the stub curve were selected on the basis of judgment.
Such judgment 24 25 took into a consideration factors which indicated that the Company's past experience was not a reasonable criterion of 26 future life expectancy for the facilities now in service in those 27 par t'icular accounts.
1 Q.
What was the basis of your determination of net salvage rates?
2 A.
The net salvage percentages used in this report are expressed 3
as a percent of original cost and were based primarily on judgments However, in determining this judgment, considerable weightwas given to the results of an analysis of the Company's experience with respect to salvage and removal costs for the 10 period of years 1969-1973, inclusive.
The net salvage ratios shown on Column V in the summary in Schedule IX of this exhibit may be explained as follows:
1.
Where the ratio is shown as unity (1.00), it was assumed that the net salvage in that particular
'2 account would be zero.
13 2.
Where the ratio was less than unity, it was assumed 14 that the salvage exceeded the demolition costs.
For example, where the net salvage was 20 percent, 16 17 18 19 the net salvage ratio was expressed as
.80.
I'.
Where the ratio was greater than unity, it was,'ssumed that the demolition costs exceeded the salvage.
For example, where the net salvage was 20 minus 5 percent, the net salvage ratio was expressed 21 as 1.05.
22 These net salvage ratios were used in computing the annual 23 depreciation rate for each primary account in order that the 24,'ate could be applied to the gross balance in the account when calculating the annual depreciation accrual.
For example, if the average life for an account were 50 years, the annual depreciation rate with zero net salvage would be 2.0 percent.
However; if the >et salvage ratio were.90, the annual depre-ciation rate adjusted for net salvage would be the product of' the two, of 1.800 percent.
I 7
Q.
Where in your Exhibit No. 2're the results of your mortality 8
study summarized?
9 A.
Schedule II summarizes the results of my mortality study.
In 10 Column IV under the heading Average Life and Iowa type curve
- selected, the letters.R, S,
and L, together with the numerical 12 suffix, which accompanies them, represent the Iowa, type curve 14 15 16 17 18 selected for each account.
The number prefixed to the letter is the average life in years, which together with the net salvage ratio shown in Column V determines the annual depreci-ation rate shown in Column VI of the Summary.
Column VII represents the application of the rate in Column VI to the Original Cost at December 31, 1974, for each primary plant account, is used to determine the annual depreciation rate 20 applicable to each of the functional groups.
21 Q.
Mr. Reilly, will you please describe Schedule III of your Exhibit 22 No.
2?
23 A.
Yes.
Schedule III is a comparison of the estimated Reserve 24 Requirement at December 31, 1974, based on the average service 1 'ives, curve types and net salvage selected for each primary 2
plant account, with the book Reserve for Depreciation.
The 3
comparison indicates a difference of $34,536,000.
4 Q.
Mr. Reilly, can you explain the reasons for this difference?
5 A.
Yes.
The largest part of, the difference between the calcu-lated reserve and the book reserve at December 31, 1974, is
'due to the change in average life and net salvage percent selected for Steam Production Plant.
This change has been t
caused primarily by the environmental requirements imposed on 10 this type of plant as well as the fuel situation, both of 12 13 15 16 17
-18 19 20 which I discussed in detail and occurred since our 1969 depre-ciation study.
Schedule III in this Section shows that of 'the
$34,536,000 difference between the calculated reserve and the book reserve,
$23,005,000 is in the Steam Production Plant.
The difference in Transmission Plant and Distribution Plant is caused mostly by the inclusion of 'Rights of Way accounts in depreciable plant for depreciation accounting purposes only after 1968, when the Internal Revenue Service allowed the recovery of such costs through a depreciation deduction for Federal Income Tax purposes.
Prior to that time, 21 the Company treated these accounts as nondepreciable
'and no 22 23 depreciation accrual was made to the book reserve for these accounts.
Changes in the selection of average life, curve type and net salvage percentages based on experience since the 1969 study and judgment have created the relatively minor differences between the calculated reserve and the book reserve in the other functional plants.
Since our 1969 study, the difference between the calculated reserve and the book reserve r
has increased from about 1 percent of depreciable plant to 10 about 2.5 percent.
As discussed on page 187 of Reilly Exhibit No. 2, I feel that the proper treatment of this difference at this time is to adjust the normal annual recommended depreciation rates to include an allowance that will adjust for this difference over 12 the average remaining life of each functional plant in which a 13 14 difference exists.
The computation on Schedule I derives the composite recommended depreciation rates for 1975'or each 15 functional plant, including this adjustment.
The calculations 17 on Schedule II in this exhibit determine the actual amount of normal depreciation based on plant in service at December 31, 18 19 1974.
By "normal" we refer to that amount of depreciation
\\
using rates that are based on the average service life and net 20 salvage factor only.
To this amount, I added the amount 21 necessary to amortize the difference between the 'calculated 22 reserve -and the book reserve per Schedule.III to determine the 23
'4 total depreciation from which the recommended rates have been derived in Schedule I for the year 1975.
1 Q.
Mr. Reilly, can you summarize for us the effect of CP&L adopting 2
your recommended depreciation rates?
3 A.
The adoption of my recommended depreciation rates, together with 4
. the amortization of the difference between the theoretical depreciation reserve and the book reserve as of December 31, 1974, will allow the Company to recover its investment in Electric Plant in Service in a rational and uniform manner over the remain-ing life in a plant in service estimated by me as of December 31, 1974.
4 10 A.
My primary responsibility was the assignment and allocation
)
of rate base components,
- revenues, expenses, and capital structure to the South Carolina retail operations, which are subject to the jurisdiction of this Commission.
The results of these assignments and allocations are shown on the various test period exhibits filed in this proceeding.
The original Applications were based on a 1974 test period.
Subsequent to the filing of the original exhibits, the test period has been updated to the year 1975.
The revised exhibi.ts for the 1975 test period are presented in the testimony of Mr. Bradshaw and Mr. Davis, to whom I furnished the results of the allocation of 13 the system totals to determine the amounts for the South Carolina retail operations.
14 I was also responsible for preparation of the 1974 Retail 15 Operations Cost Allocation Study based on the present rates annualized.
This study provides an indication of the relative 17 rates of return earned by the various retail customer rate 18 19 classes.
My testimony 'will include a discussion of the proce-dures used to accomplish the study and the results obtained 20 for the retail rate classes.
21 Q.
Were the allocations to obtain the South Carolina retail 22 jurisdictional operating results accomplished under your super-23 vision and direction?
24 A.
- Yes, they were, and they consisted of methods previously 25 presented to this. Commission.
In summary, I would state that
the power supply allocation was accomplished on the basis of coincident peak demand.
This allocation method states the power supply responsibility for production and transmission cost on the.basis of the demand at the time of our annual summer peak demand.
We believe that this method properly reflects the cost of providing service and relates our revenue levels to the peak load of our system.
We have used this peak load cost formula in our last two rate filings prior to this case and recommend its approval again in this 10 proceeding.
The allocation of the remaining cost items was accomplished in the same manner as in our previous rate filings.
12 Q.
Would you please explain the jurisdictional allocation study in 13 more detail?
14 A.
The results of system operations including adjustments were 15 apportioned to retail service in South Carolina by a series of 16 17 18 19 20 21 steps which began with a study to identify those items related solely to service to specific classes of customers.
Those items were then assigned directly to the related classes.
Those matters which arose from joint-use and thus could not be assigned directly to specific classes were allocated by the application of standard analytical methods.
All items were grouped according to 22 the functions to which they relate production, transmission, 23 distribution, administrative and general, sales and customer
accounting.
Allocable items were also classified as to whether they'were demand-related, energy-related, or customer-related.
Allocations of demand-related items were made using coincident peak demand factors.
Energy-related items were allocated by using kilowatt-hour ratio factors.
6 Q.
Will you please explain briefly how each major revenue,
- expense, 7
and rate base item was allocated, beginning with operating 8
revenues?
9 A.
Operating revenues from sales at retail in South Carolina are 10 readily identified and therefore have been assigned directly to the South Carolina retail class.
Other operating revenues consisting of a number of miscellaneous items were either 13 assigned directly or apportioned by appropriate analysis and factors.
Q.
Please describe the allocation of the operation and maintenance 16 expenses.
17 A.
Before the operation and maintenance expense items could be 18 functionalized into categories for allocation, it was necessary 19 to prorate the supervision and engineering expenses for each 20 expense account.
An analysis provided the amount of the payroll 21 22 23 24 25 charges included in the total expense items.
The respective supervision and engineering expenses were then apportioned to the various expense accounts based on this labor component.
By this means the primary accounts were restated to include a pro-rated portion of the supervision and engineering expense.
10 12 The expenses as thus restated were then classified as either energy-related, demand related, or customer-related.
The production expense items classified as energy-related are fuel, the energy portion of purchased power, boiler plant maintenance, electric plant maintenance, reactor plant maintenance, and nuclear electric plant maintenance..
The remaining power production expenses were classified as demand-related.
The transmission expense was assigned b'etween power supply production and power supply transmission based on the ratio of the plant in service.
The distribution expense was divided functionally between substations, overhead lines, underground 13 lines, meters, and other distribution expense.
These function-14 15 alized expenses were assigned to each state and then allocated to,the jurisdictional classes within the states on the basis of 16 the respective distribution plant accounts.
The customer accounting expense was assigned based on a 18 specific analysis which separated the cost involved between 19 20 21 22 wholesale and retail service in each state.
A portion of the expense of the customer services personnel who are directly involved in wholesale sales was assigned to the wholesale operation in each state.
The remaining sales expense was 23 assigned to the retail class.
Regulatory expense has been analyzed and assigned to the respective jurisdictions.
The remaining administrative and general expenses were allocated to the customer classes principally by the use of labor factors.
Certain items such as property insurance and maintenance. of general plant were allocated on plant ratios.
The operation and maintenance expense adjustments were allocated on the same basis as the items to which the adjust-ments related.
'0 Q.
Would you please explain the allocation of the depreciation 12 A.
13 14 15 16 expense?
Depreciation expense was assigned in accordance with the assign-ment and allocation of the functional plant to which the depre-ciation related.
The adjustments to the depreciation expense were similarly functionalized and allocated on the basis of the respective functional plant account.
17 Q.
Please describe the allocation of the remaining operating 18 19 A.
20 expense items.
Taxes other than income were assigned for allocation as related to labor, property, KWH sales, or revenue and were then allocated 21 by the respective allocation factors.
Unemployment taxes were 22 23 considered labor-related, property taxes were considered related to plant investment, the South Carolina electric power generation 24 25 tax was classified as KWH-related, and revenue taxes such as the North Carolina gross receipts tax were treated as related to 26 revenue.
State income taxes were assigned specifically to the respective states and then allocated to classes on the basis of the ratios of income before taxes.
Federal income taxes were calculated for states and for classes using allocated taxable income.
The provision for deferred income taxes and the investment tax credit were functionalized into production, transmission, distribution and general categories, and then 8
allocated on the basis of the respective plant allocations.
9 Q.
Will you please explain the allocation steps used to determine 10 the portion of the electric plant used in providing service to ll South Carolina retail operations?
12 A.
The allocation of electric plant in service consisted of two 13 14 as basic steps.
The first step was to specifically assign all items of cost for which sufficient information allowed a specific separation between classes.
This step involved separating the 16 cost associated exclusively with the wholesale operation and also 17 18 19 joint costs which were allocated on a specific basis.
The second step was to allocate the costs where the joint use was so thorough that a specific analysis was not practical.
These costs were 20 assigned for allocation to the classes of service and the alloca-21 22 23 tions were accomplished by the use of allocation factors developed for the respective classes.
Allocations of the power supply production and.power supply 24 transmission facilities were accomplished using the coincident
peak demand allocation factors.
All allocations of facilities below the level of power supply transmission were accomplished by use of NCP demand allocation factors.
The NCP factors for each of these specific allocations were developed by an analysis of the demands imposed on the facilities being allocated.
The production plant in service was allocated between classes of service by KW demand allocation factors developed from system load data.
These KW demand allocation factors were based on data adjusted to the production level.
No production 10 plant account dollars were specifically assigned to classes of 12 13 14 15 16 18 19 service.
The transmission plant in service was allocated between the classes by KW demand allocation factors developed from system load data.
No transmission plant account dollars were specifically assigned.
It was necessary, however, to separate the transmission plant into two levels for allocation by KW demand factors.
Since the function of the step-up trans-formers at the various generating plants is considered to be production, these facilities were allocated using the production KW demand allocation factors.
All other transmission facilities 20 were allocated using transmission KW demand allocation factors.
21 22 23 The investment in distribution facilities was assigned between the states on a geographical basis as shown directly on the books of the Company and between the wholesale and retail 24 classes on the basis of specific analysis.
General plant was
first placed in the functional categories in its relationship of use with the production, transmission, or distribution facilities.
The amounts thus functionalized were then assigned on the same b'asis as the respective functional plant accounts.
The item for intangible plant was assigned on the basis of the other electric plant.
The depreciation reserve distributed on the books to the functional plant from which it results was assigned in accordance with the plant assignment.
10 Q.
Would you please now describe the allocation of the other rate base items?
12 A.
Net nuclear fuel, which consists of nuclear fuel assemblies in 13 14 15 17 18 19 20 21 the reactor, nuclear fuel in process, and spent nuclear fuel, was allocated by the use of KWH energy factors.
The fuel portion of materials and supplies was allocated by energy factors.
Other.
materials and supplies were analyzed as to their type and were allocated according to the assignment of related plant.
The bank balance portion of the cash working capital allowance was assigned in accordance with plant investment.
Prepayments were assigned by specific analysis or by allocations based on gross plant.
The cash allowance was assigned in the same proportion as the operation 22 and maintenance expenses.
Deducted from cash working capital were 23 24 25 average tax accruals and customer deposits.
The tax accrual offset was allocated in accordance with plant investment.
Customer deposits were directly assigned to the proper jurisdiction.
1 g.
Where are the results of applying these allocation procedures 2
to the 1975 test period shown in this proceeding?
3 A.
The results of my 5urisdictional allocation study are shown in Davis Exhibit No.
1.
I provided to Mr. Davis the South 5
Carolina retail allocated portion of the cost of service that 6
he is presenting in his testimony.
7 g.
Will you please now turn to the next part of your testimony 10 relating to the procedures and results of the Retail Opera-tions Cost Allocation Study for the 1974 test period.
Please summarize what is meant by a retail operations cost allocation 11 study.
12 A.
A retail operations cost study allocates system cost and devel-13 14 15 16 17 18 19 20 22 23 ops a rate of return for each of the retail classes.
The study allocates the revenues,
- expenses, and rate base between the various retail classes.
The rate of return is derived by measuring net operating income as a percent of average net original cost rate base.
Horne Exhibit No.
1 describes the procedures that are used in our retail cost allocation studies.
The methods and )udgment used in our retail cost allocation studies are extensions of the methods used in the preparation of jurisdictional allocation studies.
While advice for portions of the study is obtained from consultants, the studies are accomplished by Company personnel.
Recognized and accepted allocation procedures are used through-out the studies.
For the major components, these procedures conform to those used in the recent rate hearings before the regulatory commissions in the two states which the Company serves.
6 Q.
How were the cost data and customer information obtained to 7
apply these allocation procedures in the retail studies?
A.
The basic cost data for the study were taken from the books and 10 12 14 1S 16 records of the Company.
Adjustments have been made to include the effect of known changes during the year.
- However, these adjustments do not include all the items that would be necessary if the results of this type of study were to be used to determine the rate levels of the Company.
Fundamental to appraising the results of this type of allo-cation study is a recognition that the use of an average original cost rate base without all of the adjustments normally 17 included in a ratemaking proceeding is appropriate in a study of 3.8 the relationship of rates to each other but not in considering 19 the adequacy of the overall rate of return.
20 Q.
Was the document marked Horne Exhibit No.
2 prepared by you or 21 under your supervision and direction?
22 A.
Yes, it was.
(Identify) 23 Q.
What is shown in this Exhibit?
24 A.
This Exhibit presents the results of our Retail Operations Cost 25 Allocation Study for the year 1974 on the basis of the present 26 rates annualized.
1 Q.
Does this Study for 1974 provide the information which is 2
necessary in the establishment of the rates for the various retail classes of service?
4 A.
No.
This Study only provides an indication as to the relative 10 rates of return that are being earned by the various rate classes.
It attempts to analyze and consider cost factors in providing service to the various customer classes.
This
- study, however, does not consider all of the factors which are essential in setting rate levels and the design of the resulting rate schedules.
The end results of the accounting and the engineering 12 13 14 procedures involved in cost allocation studies do not establish value of service or even levels of reasonable rates.
The results simply reflect the total cost assigned to the rate 15 16 classes by following basic principles with logical and supportable procedures starting from the premise of allocation 17 18 19 20 21 joint costs.
The resulting rates of return can serve only as a guide, under the assumptions of the study, to the relative earnings of the various rate classes.
Proper rates can be established only after consideration of all the factors rele-vant to their justness and reasonableness.
A retail class cost 22 allocation study is one of the aids in that task.
South Carolina Public Service Commission CAROLINA POWER
& LIGHT COMPANY TESTIMONY OF JAMES M. DAVIS, JR.
1 Q.
Please state your name and address.
2 A.
James M. Davis, Jr., Raleigh, North Carolina.
3 Q.
What is your position with Carolina Power
& Light Company?
4 A.
I am Assistant Director of Rates and Regulation.
5 Q.
Will you briefly describe your educational and professional 6
background.
7 A.
I am a graduate of North Carolina State University, from which 10
/
I recei'ved a Bachelor of Science Degree in Mechanical Engineer-ing.
After three years'ervice as an officer in the.U.
S.
Air Force, I was employed by Pratt and Whitney Aircraft as a
test engineer in the Experimental Engineering Department.
In 1965, I went to work with Carolina Power
& Light Company as an 13 engineer in the Special Services Section.
I joined the Rates 14 15 16 17 and Regulation Department in February,
- 1968, and in July, 1970, I was named to my present position.
My education in the ratemaking area has consisted of parti-cipation in the development of the load survey, cost analysis, 18 19 rate evaluation, and rate design programs of the Company.
This work has included the studies that were necessary in the prepara-20 tion of the filings and case materials for retail and wholesale rate increase
- requests, including our Company's prior requests to 22 this Commission.
I have attended a training program conducted by
Ebasco
- Services, public utility consultants, and I have worked with a number of rate consultants in the preparation of rate case material; I have attended meetings of the Rate Research Committee of the Edison Electric Institute.
I am a registered 5
Professional Engineer in the State of North Carolina.
6 Q.
Have you testified before a regulatory authority prior to this 7
case?
8 A.
Yes, I have testified before this Commission in prior rate 9
proceedings and before the North Carolina Utilities Commission 10 and the Federal Power Commission.
11 Q.
Please summarize your duties with Carolina Power
& Light 12 Company.
13 A.
The Department of which I am assistant director is responsible 14 for the development,
- issuance, and interpretation of the rates 16 17 18 19 and service practices of the Company.
I am responsible to the Uice President and Director of Rates and Regulation for the direction and supervision of the studies underlying the theoretical and practical aspects of our rate structure; the preparation of rates and revenue comparisons; the direction and supervision of 20 cost allocation studies; and the development of financial and cost 21 22 23 24 studies for rate case presentation.
I supervised the rate of return studies underlying the exhibits which have been filed in this proceeding, and supervised the preparation of the proposed rates and rate schedules.
25 Q.
Millyou please explain the scope of testimony you.intend to offer 26 here?
1 A.
I will present the proposed rates, including.a fuel adjustment 2
clause for the recovery of current fuel costs, for which the 3
Company is requesting approval of this proceeding.
I will also 4
present the actual operating results of the Company.during the test period consisting of the calendar year 1975, with appropriate adjustments.
This material will be presented on both a system-wide basis
- and, as indicated in the testimony of Mr. Horne, as allocated and apportioned to the operations which are 'subject to the jurisdiction of this Commission.
My 10 testimony will show the monetary effect that the proposed rates ll would have had on the Company's operations, as adjusted, had the 12 changes been in effect during the test period 1975.
13 Q.
Where have you shown the 1975 test period operating results with 14 the present rates in effect?
15 A.
~ Davis Exhibit No.
1 sets forth the operating experience for the 16 historical test period in this proceeding.
This Exhibit is in 17 the same format as Exhibit G filed with our Application and has 18 19 20 21 22 23 been updated to reflect the year 1975 results.
Column 7 sets forth the allocated South Carolina retail operations.
The proce-dures used to obtain the allocations were described in the testimony of Mr. Horne.
This Exhibit shows the actual 1975 test period operations adjusted to properly reflect for the purpose of jurisdictional 24 ratemaking those changing conditions which were not fully reflected in the actual results of the test period.
Included
- therein, are those proforma adjustments explained in the testimony of Mr. Paul Bradshaw.
In addition, I have included certain adjustments which were calculated under my direction and supervision.
These adjustments include the annualization for the effect of previously allowed rate 6
increases and the normalization and annualization of the
'7 addition of the Brunswick No.
2 generating unit.
8 g.
Will you please explain the adjustments which you have 9
included; starting first w'ith the adjustment for prior rate 10 increases?
11 A.
During the test period 1975, the Company received a retail 12 rate increase which was not fully reflected in the test 13 14 15 16 17 year revenues.
It was necessary to compute the annual effect
'of this approved increase and add to the test year revenues the additional revenues that would have been produced had the approved increases been in effect throughout. the test period.
These adjustments restate the test year revenues to 18 reflect fully the effect of the prior rate increases which 19 occurred during the test period.
20 21 The second adjustment which I have included adjusts
- revenues, expenses, and rate base to reflect the full annualization of the 22 23 addition of the Brunswick No.
2 nuclear generating unit.
This adjustment is essential to state the operating results 'of the 24 Company on the basis of a full year's operation of this new
generating resource.
The adjustment includes many aspects to fully reflect the effect on our operating results from the addition of Brunswick No.
2.
Each respective ad)ustment to
- revenues, expenses, and rate base was computed on the basis 10 of the Brunswick No.
2 unit operating at a
72% capacity factor during the test period.
This availability was selected because it reflects a full year's operation, including a refuel-ing cycle.
We selected a
72% capacity factor on the assumption that the unit would be available on a basis equivalent to ful'1 power operation approximately 85% of the hours during the year, 12 except'for a six-week outage for necessary maintenance and refueling.
This reflects an optimistic estimate of the avail-
"13 14 ability of this new unit and reflects a'full year's operation at a substantial availability and load factor.
15 In order to compute the effects of the availability of 16 Brunswick No.
2 for the entire test period, it was necessary to 17 develop a power estimate which would restate the generation from 18 19 system resources to include the addition of this large nuclear unit.
Purchases and interchange transactions were also 20 analyzed to determine if purchases could have been reduced to an 21 22 23 economic advantage if the nuclear unit.Sad been available.
When this analysis was completed, the result stated the adjusted generation from each of our existing units.
This reduced'genera-24 tion was then analyzed to determine the fuel requirements that
would have existed with the reduced generation.
Our fossil fuel purchases during the year 1975 were reviewed to determine the effect of the fossil generation which would have been replaced by the nuclear unit.
In order to evaluate the fuel purchases, we eliminated the highest price spot purchases that were made in each month at each of the plant locations based on the reduced generation for that respective plant.
We did not reduce contract purchases at any of our plant locations.
The reduced fuel purchases were then processed through our 10 12 13 14 16 17 18 19 20 21 fuel inventories to determine adjusted unit fuel prices.
The adjusted fuel prices were then used as a basis to calculate fossil fuel adjustment factors that would have resulted from the adjusted fuel purchases and consumption.
This calculation was necessary to reduce the revenues that would have been
'roduced by the fuel adjustment factor.
The completion of these detailed calculations to fully annualize the operation of the Brunswick No.
2 nuclear unit resulted in the following adjustments.
South Carolina retail revenues were reduced by
$5.0 million.
The test year fuel expense was reduced by a net of $4.3 million.
Purchased power expense was reduced by
$1.0 million.
Other 0&M expenses were 22 23 increased by
$711,000.
Depreciation
- expenses, property taxes, fuel deferral, and working capital were also adjusted to con-24 form to the related adjustment items.
The combined effect of
these adjustments was to state the test year on the basis of a full annualization and normalization for the addition of Brunswick No.
2 generating unit.
The adjustments to fuel 4
expense and purchased power have also been included in the base cost for the proposed fuel adjustment formula in Davis Exhibit No.
3.
7 Q.
Mill you please describe the rates proposed by the Company in 8
this proceeding?
9 A.
The Company has filed two rate increase applications in this
'A 10 12 proceeding.
On July 31,
- 1975, an application was filed for authority to adjust the rates for residential service.
The effect of this initial application was to equalize the rate for 13 residential service between the state of South Carolina and 14 15 North Carolina.
The Application was assigned Docket No. 18,361,
'I and the proposed rates went into effect under bond, subject to 16 17 18 19 20
- refund, on September 1, 1975, in.accordance with the Commission's Order No. 18,532.
On August ll, 1975, the Company filed an additional Appli-cation requesting a general increase in its rates and charges for retail service in South Carolina.
This Application was 21 22 23 assigned Docket No. 18,387.
Subsequent to the filing of the general application, the Commission consolidated the two dockets into one proceeding.
Exhibit B filed with the Application on
August 11, 1975, contains the rates and rate schedules proposed by the Company.
For convenience, the proposed schedules are 10 13 14 15 16 presented with this testimony as Davis Exhibit No.'.
It should be noted that these schedules contained a "roll-in" of 5.54 mills per KWH to reflect an increase in the cost of fuel reflected in the base rate charges.
At the time of the filing, it appeared that this level of cost was a reasonable expectation for,the current cost of fuel.
However, the Company's experience has been more favorable, and the cost of fuel has stabilized at a level below the requested roll-in figure.
.As a result of this improvement in the cost of fuel, an adjustment was made at the time the requested rates became effective under bond for service rendered on and after March 1, 1976.
Rider No.
- 35A, which has been included as a part of Exhibit B, was placed into effect to reduce the requested rates by
$0.005536 per KWH t'o remove the roll-in requested by the Company and allow the 17 presently approved fuel clause to continue in effect.
18 Q.
Does the Company propose that the filed rates continue in effect on 19 a permanent basis including Rider No.
35A to adjust for the 20 difference in fuel cost?
21 A.
No, we do not.
We have simply made an adjustment to allow the I
filed rates to go into effect on an interim basis, pending a
23 decision of the Commission as to how the rates should reflect a 24 reasonable current cost of fuel. If the present Fossil Fuel
Adjustment Clause Rider No.
32B were to remain in effect, it would be desirable to adjust the kilowatt-hour charges in each I
rate rather than to continue the adjustment through Rider No.
35A. It would also be possible to raise the base cost reflected in the fuel clause and adjust the charges in the basic rates.
This would reflect a lower roll-in than originally requested by the Company but would raise'he base of the fuel clause above its present level.
'0 12 13 14 In addition to the originally proposed rates and adjust-ment to the fuel charge roll-in, I will present an alternative method for the recovery of fuel costs in excess of,those reflected in the base rates.
This alternative method would include a fuel adjustment clause based on changes in the cost of fuel, including nuclear fuel.
Later in my testimony, I will 15 present the specifics of the development of this fuel adjustment 16 17 clause and will present proposed base rate schedules that would be necessary to implement this alternative method of recovering 18 total fuel cost.
19 Q.
Is the Company proposing or requesting any additional change 20 related to the application of the fossil fuel charge7 21 A.
- Yes, we are.
We would request that the fuel charge approved by 22 24 the Commission in the proceeding be applied to the non-metered
- sales, including the lighting classifications.
At the present time, the fuel charge only applies to metered sales.
We have
developed an administrative procedure by which the charge can be applied to non-metered sales on the basis of the estimated kilowatt-hour usage which 'is used in establish-ing and reporting sales under the basic rate.
Me are requesting Commission approval to apply the fuel charge on 6
the basis of this procedure which would be consistent with 7
the present practice of the other major utilities in this 8
jurisdiction.
9 Q.
Do the rate schedules that you are presenting provide for a 10 uniform increase among the customer classes.
11 A.
No, they do not.
The rate increases proposed in this 12 proceeding are not on an across-the-board
- basis, but vary
/
13 with regard to recent financial results from the various 14 customer classes.
The re'lative increases to the classes 15 seek to recognize the areas of cost differences in providing 16
'ervice and are based in part on the results of our most 17 recent retail operations cost allocation study.
18 At the time of the preparation of the rates filed in this 19 proceeding, the results of the 1974 cost of service study were
.20 21 available.
These results which indicated the relative rates of return between the retail rate classifichtions were used as one 22 23 of the guides in determining the percentage increase for each customer class.
10 12 13 14 On the basis of 1975 sales the average percent increase on the retail classification on total charges, including fuel
- revenues, is approximately 27%.
On the basis of an average 27% rate increase, there are variations within the various customer classes.
The residential class will receive a total increase of about 32.5%.
This increase is a combined total of the two requests in this proceeding.
The higher-than-average increase also reflects the fact that the residential class rate of return is below the retail average.
The small general service class will receive an average increase of 20.5%.
The lower-than-average increase is in recognition of the fact that the rate of return for this classification is above the retail average.
The large general service rates would receive an increase of 26%, which is slightly less than the average retail 15 increase.
The schedules for service to the lighting class of 16 17 18 19 20 customer will receive an average increase of 16.45%.
This is the lowest increase that can be applied to the customer class consistent with the receiving of fair rate of return from the classification.
As a result of the Company's rate history and of its prior 21 marketing policy, which produced very successfully a balanced 22 system load with a high growth at a time when those aspects were 23 24 beneficial to our customers, the Company has a relatively large number of existing rate schedules for retail service.
A primary objective in our prior rate proceeding was the reduction of the number of our retail schedules.
We proposed and received Commission approval to eliminate a net of six rate schedules in our prior case.
We would propose to continue this improvement in our rate structure by the elimination of four additional active rate schedules.
We are proposing to administratively freeze the availability of three rate schedules, RF-1, AH-1, and 10 12 13 14 15 17 18 19 20 21 22 23 24 25 SC-1.
To avoid severe financial impacts on the present customers served under these three rate schedules, we are not requesting the immediate transfer of the present customers to other rate schedules.
We are proposing instead to limit the availability of the schedules to the existing customers and to place a higher-than-average increase on these rates in order to move the charges into closer alignment with our General Service Rates.
It is anticipated that over a period of time, the customers, because of changing load characteristics and differences in the existing rates, will move to the general service rates, and it will be possible in future rate filings to complete the process of eliminating these three schedules.
We are requesting the elimination of the House Construction Rate Schedule, HC-1.
This rate provides temporary service during the construction of residential housing units.
We would propose to replace Rate Schedule HC-1 with our standard Small General Service Rate, G-l, and serve the builder on the general service rate until the permanent service is installed for the residential unit.
At the time the permanent service is installed to the residence, the residence would then be billed on the standard 4
residential rate for which the residence qualifies.
This will 5
eliminate the need for a separate rate schedule for service dur-6 ing the time the house is under construction.
This change will 7
improve our rate administration and limit the availability for I
10 temporary service to our standard small general service rate.
This proposedprocedure will have a significant financial impact on the existing HC-1 customers.
The rates presented in Davis 12 Exhibit No.
2 containing the modifications described above and others set out therein constitute a set of just and reasonable 13 14 rates appropriate for our Company and the various -types of customers in our service area.
15 Q.
Will you please describe the manner in which the proposed rates 16 recover the fuel expense of the Company?
17 A.
The rates proposed in this proceeding were designed based on a 18 19 20 21 22 23 24 total fuel cost component of 1.010 cents per kilowatt-hour.
The rates were designed during 1975 and reflected average fuel costs experienced during 1974.
The 1975 test year fuel expense when annualized for the operation of the Brunswick No.
2 nuclear generating unit is below the fuel cost level designed into the rates originally filed in this proceeding.
A lower cost of fuel would be more appropriate in setting rates at this
'time.'13-
10 12 A fuel cost level of '8.60 mills per kilowatt-hour sales is a more appropriate level to reflect current costs in the design of the rates.
Davis Exhibit No.
3 is a fuel adjustment clause which we would propose for the consideration of the Commission.
As indicated in the exhibit, we have established 8.50 mills per kilowatt-hour as the base cost for the fuel adjustment clause to include both nuclear and fossil fuels and the effect of purchase and interchange power.
Me would recommend this clause to the, Commission to replace the present adjustment clause which recognizes changes only in fossil fuel costs.
Since the base cost of fuel reflected in this fuel adjustment 13 clause is below the level of 1.01 cents per kilowatt-hour 14 15 16 included in the original filed rates, it. is necessary to adjust the base rates to which the clause would be applicable.
Davis Exhibit No.
4 is a set of alternative rates which have been 17 adjusted to reflect the base cost included in the proposed 18 19 20 21 alternate fuel adjustment clause.
These rates are identical to the rates approved for service in our North Carolina territory.
Approval of this set of rates and the accompanying fuel clause would return the Company to uniform rates,'throughout its retail
'22 service area.
23 Q.
Did you use the results of the 1974 retail cost allocation study 24 in the design of the rates requested in this proceeding?
1 A.
Yes, I did.
The relative relationship of the rates of return among the various customer classes, and,'..to a lesser extent, 10 13 the individual rate schedules, was used as a guide in the distribution of the rate increase among the customer classes.
As we have testified in earlier rate proceedings, we are committed toward moving our rate structure and designing our rates in such a manner as to produce a more uniform rate of return among the retail classes.
We made considerable pro-gress in our last rate case in applying the increase such that the rates of return would move toward the overall retail average.
We have attempted to contine that movement in this rate case.
It should be recognized, however, that there are 14 restraints against moving directly to a uniform rate of return 15 among the various customer classes.
These restraints include 16 the relationship between the individual rate schedules, the 17 18 19 20 21 22 23 overall revenue requirement and the revenue effect on individual customers.
It is necessary and desirable to make the transition and changes in the rate schedules on a gradual and smooth basis, rather than introduce abrupt changes.
We tried to design our rates within all of those restraints and make as much progress toward a uniform rate of return as these conditions would allow.
Even without the restraints that exist in abrupt rate 24 changes, it would not be desirable to structure our rates to 25 produce a uniform rate of return on the basis of one test period.
This is true because the equal rates of return would be'measured by a historical test period and would not exist when the rates became effective.
It would not be possible to measure the result-ing variation in rates of return until the rates had been in effect and a cost study performed at a later date.
It is there-fore desirable to set the rates of return within a reasonable range rather than seeking absolute uniformity on the basis of a 8
past test period.
In the application of the requested rate 9
- increase, we have improved the variation from the average retail 10 'ate of return for each of the customer classes.
ll Q.
Please describe the manner in which the rates requested in this 12 proceeding were designed.
13 A.
The first step in the design of the requested rates was to 14 15 16 17 18 19 20 21 22 23 24 distribute the required additional revenue among the retail classes on the basis of the results of the retail class alloca-tion study and in proportion to each class based on its percentage of the Company's revenues.
It was proposed in the case of the residential class to apply an increase necessary to bring the residential class rate of return to a point closer to the retail average return.
It was likewise concluded to apply less than the average increase to the Small General Service class in order to continue the movement of the rate of return from that class down-ward toward the retail average.
It was proposed to apply 'the minimum increase to the lighting classification necessary to bring 25 the rate of return slightly below the retail average.
Slightly 16-
less than the overall average increase was applied to the Large General Service classification.
The results of these computations were to determine a revenue requirement for each of the retail classes.
The rates were then designed within those classes to produce the total revenue requirement, and to maintain the proper alignment and relationship between the rates.
In the case of general service rates, the most signifi-cant design feature change'as to incorporate in both small and 10 large rates which include a separate demand charge a 12-month seasonal ratchet to establish the minimum billing demand.
This 12 13 design change was made to increase the amount charged for demand in order to create more incentive to conserve electricity.
14 The new billing demand feature establishes the minimum 15 16 17 18 billing demand based on 90% of the customer's maximum demand in the prior summer peak months of July through October.
This form of pricing encourages customers to reduce their demands during the summer peak period.
In addition, a billing provision has 19 been established as a minimum of 50% of the demands during the 20 off-peak winter season months; and as an administrative iequire-21
,ment,
.a minimum of 75% of the contract demand until such time as 22 the actual demand equals the contract demand.
This total ratchet 23 provision enables the customer to control his billing demand by 24 reducing his consumption during peak periods.
It establishes a
12-month ratchet rather than the previous provision in our schedules.
The definition of contract demand has been'evised in the proposed rate schedules and service regu-4 lations to conform to the new ratchet provision.
5 Q.
Have you shown the results of applying the proposed rates to 6
the individual customer classes?
7 A.
Yes, I have.
Davis Exhibit No.
5 presents a summary of the 8
results of the cost allocation study indicating the rates, of 9
return for the retail classes that would have been realized 10 12 during the 1974 test year if the requested rates had been in effect during the entire period.
It should be noted that these rates of return are valid only for comparison of relation-13 ship between the rates and do not indicate the correct rate of 14 15 return for )urisdictional ratemaking.
A comparison of this exhibit with Horne Exhibit No.
2 would indicate that the 16 proposed rates improve the variation from the retail average 17 from each of our rate classifications.
18 Q.
Have you shown the results of the proposed rates'n a 1975 test 19 year basis?
20 A.
Not on a retail class basis.
The 1975 retail cost of service 21 22 study had not been completed and the results were not available't the time of the preparation of this testimony.
The initial 23 rate design was based on a 1974 test period, and the results I 24 25 have shown for the retail classes are based on the 1974 cost of service study.
18-
1 Q.
Will you now please describe the monetary effect that the 3
proposed rates would have had on the Company's jurisdictional operation as adjusted had the proposed rate changes been in effect throughout the 1975 test period?
5 A.
These materials are shown on Davis Exhibit No.
6.
Column 2
\\
6 of Page 1 of this exhibit is identical through Line 25 with 7
Column 7 of Davis Exhibit No. 1.
For convenience, it restates 8
the actual operating results with appropriate adjustments 10 apportioned to the South Carolina retail operations.
Column 3
sets forth the effect of the proposed rates had they been in force throughout the test period.
As shown thereon, the addi-12 tional revenues would have been about
$22,486,985.
Additional 13'4 15 gross receipts, state and federal income taxes arising as a
result of these additional revenues, would have amounted to
$11,528,321 or 51.27% of the gross revenue increase.
The addi-16 tional net operating income for return would have been 17
$10,958,664.
Thus, with the increase applicable to South 18 Carolina retail sales, the net income for return, including 19 customer growth, would have been
$31,055,486, as shown on 20 Line 18 under Column 4.
21 Q.
What else is shown on Page 1 of Davis Exhibit No.
82 22 A.
Lines 19 through 30 show the original cost net investment 24 consisting of net electric plant in service, plus an allowance for working capital.
The total original cost net investment is shown on Line 30.
As stated
- there, the apparent return in the test year at the present rates would have been 5.98%;
and had t
the proposed rates been in effect for the entire test period, this indicated rate of return would have been 9.27%.
5 Q.
What rates of return would have been indicated in the test year 7
A.
common equity?
As indicated on Page.3 of Davis Exhibit No. 6;,the requested 10 rates would have produced 12.18%
on actual common equity in the test period.
This corresponds to an allowance in our prior rate order of 12.50%.
ll Q.
Is it your testimony in this proceeding that Carolina Power 12 13 Light Company will realize from the requested rates a return of 9.27% original cost rate base and 12.18%
on total book equity?
14 A.
No, it is not.
Mr. Harris and other witnesses have testified in 15 16 17 18 19 20 this proceeding to the fact that economic conditions will operate to prevent the Company from earning the rate of return allowed by this Commiss'ion on a historical test year basis.
Even though the test year rate of return computations indi-cate a return on equity of 12.18%,
the Company will not have an opportunity to earn that rate of return.
The rates did not go 21 into effect in the full amount of the increase until March 1, 22 1976.