. PLACE: Commission Hearing Room, Raleigh, NC 2 DATE: September 13, 1991 DOCKET: E-7, Sub 487 3 TIME IN SESSION: 9:30 a.m. - 12:30 p.m. 4 BEFORE: Chairman William W. Redman, Jr. Commissioner Sarah Lindsay Tate 5 Commissioner Julius A. Wright 11 12 13 17 18 20 21 22 24 IN THE MATTER OF: Duke Power Company General Rate Increase g VOLUME 12 10 APPEARANCES: FOR DUKE POWER COMPANY: Steve C, Griffith, Jr., Senior Vice President & General Counsel 14 Ellen T. Ruff, Deputy General Counsel Karol P. Mack, Senior Attorney 15 Duke Power Company 422 S. Church Street 15 Charlotte, North Carolina 28242 - and - Clarence W. Walker, Attorney at Law Myles E. Standish, Attorney at Law 19 Kennedy, Covington, Lobdell & Hickman 3300 NCNB Plaza Charlotte, North Carolina 28280 FOR THE CITY OF DURHAM W. I. Thornton, Jr., City Attorney Gayle Moses, Assistant City Attorney 23 101 City Hall Plaza Durham, North Carolina 27701 Continued) NORTH CAROLINA UTILITIES COMMISSION
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BEFORE: Chairman William W. Redman, Jr. VOLUME 12 ...
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. PLACE: Commission Hearing Room, Raleigh, NC
2 DATE: September 13, 1991 DOCKET: E-7, Sub 487
3 TIME IN SESSION: 9:30 a.m. - 12:30 p.m.
4 BEFORE: Chairman William W. Redman, Jr.
Commissioner Sarah Lindsay Tate 5 Commissioner Julius A. Wright
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IN THE MATTER OF:
Duke Power Company General Rate Increase
g VOLUME 12
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APPEARANCES:
FOR DUKE POWER COMPANY:
Steve C, Griffith, Jr., Senior Vice President & General Counsel
14 Ellen T. Ruff, Deputy General Counsel Karol P. Mack, Senior Attorney
15 Duke Power Company 422 S. Church Street
15 Charlotte, North Carolina 28242
- and -
Clarence W. Walker, Attorney at Law Myles E. Standish, Attorney at Law
19 Kennedy, Covington, Lobdell & Hickman 3300 NCNB Plaza Charlotte, North Carolina 28280
FOR THE CITY OF DURHAM
W. I. Thornton, Jr., City Attorney Gayle Moses, Assistant City Attorney
23 101 City Hall Plaza Durham, North Carolina 27701
Continued)
NORTH CAROLINA UTILITIES COMMISSION
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APPEARANCES: (Continued)
FOR
FOR
FOR
FOR
CAROLINA UTILITY CUSTOMERS ASSOCIATION, INC.:
Sam J. Ervin, IV, Attorney at Law Byrd, Byrd, Ervin, Whisnant, McMahon & Ervin, P. 0. Drawer 12 69 Morganton, North Carolina 28655
NORTH CAROLINA INDUSTRIAL ENERGY CONSUMERS:
Thomas W. Steed, Jr., Attorney at Law Moore & Van Allen P. 0. Box 26507 Raleigh, North Carolina 27611
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William A. Chesnutt, Attorney at Law McNees, Wallace & Nurich P. O. Box 1166 Harrisburg, Pennsylvania 17108
SOUTHERN ENVIRONMENTAL LAW CENTER;
Derb S. Carter, Jr., Staff Attorney Southern Environmental Law Center 137 East Franklin Street, Suite 404 Chapel Hill, South Carolina 27514
- and -
Jeffrey M. Gleason, Staff Attorney Southern Environmental Law Center 201 West Main Street, Suite 14 Charlottesville, Virginia 22901
CONSUMERS;
Karen E, Long, Assistant Attorney General NC Department of Justice P. 0. Box 629 Raleigh, North Carolina 27602
(Continued)
P.A.
NORTH CAROLINA UTILITIES COMMISSION
Ill
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FOR THE USING & CONSUMING PUBLIC:
3 A. W. Turner, Jr., Staff Attorney James D. Little, Staff Attorney Public Staff - NC Utilities Commission P. 0. Box 29520
5 Raleigh, North Carolina 27626-0520
NORTH CAROLINA UTILITIES COMMISSION
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I N D E X
William R. Stimart Direct (Standish) 2 Cross (Ervin) 32 Cross (Long) 67 Cross (Turner) 73
Thomas S. Lam Direct (Turner) 9 0 Cross (Ervin) 102
E X H I B I T S
ID AD
Stimart Exhibits 1 - 3 ' 3 85
Stimart Supplemental Exhibit 1 3 8 5
AG Stimart Cross Exhibit 1 70
Denton Exhibits 1 - 4 -- 85
Lam Appendix A 91
Exhibits TSL-1 thru TSL-4 91
NORTH CAROLINA UTILITIES COMMISSION
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E-7, Sub 487
CHAIRMAN REDMAN:
Let' s come
Duke to call their
MR. STANDISH:
VOLUME 12
on the record,
September 13, 1991
please.
next witness, please.
Mr. Chairman, Duke would
R. Stimart.
WILLIAM R. STIMART
CHAIRMAN REDMAN:
Please have
Let me ask.
on the cross with
that has been nega
MR. TURNER;
There's no
; Being first
fied as foil
a seat.
Mr. Little had
Mr. Stimart.
ted, and we will
call Mr.
duly sworn
ows :
I'd ask
William
testi-
asked to go first
And I assume that
proceed as
need for us to go first
people particularly want us to.
CHAIRMAN REDMAN:
Very good.
Mr. Ervin,
MR. ERVIN:
We haven't
CHAIRMAN REDMAN;
I 'm sorry.
in moving this thi
:UCA.
sworn him and have him give
I just -- I'm
Tg right along.
normal.
unless
his --
really interested
NORTH CAROLINA UTILITIES COMMISSION
, Mr. Standish, would you --
DIRECT EXAMINATION
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BY MR. STANDISH:
ft Mr. Stimart, could you state your name and
address for the record?
fl. My name is William R. Stimart. My business
7 address is 422 South Church Street, Charlotte, North
Carolina.
ft Mr, Stimart, did you cause to be prepared
and filed in this docket 19 pages of direct testimony
11 and Stimart Exhibits 1, 2 and 3?
12 A- yes,Idid,
13 Q. Did you cause to be prepared and filed Stimart
14 Supplemental Testimony which consisted of four pages
15 of testimony and Stimart Supplemental Exhibit 1?
15 fl. Yes,Idid.
17 ft If I were to read those questions to you
18 today, would your answers to those questions be
19 the same other than with respect to the items that
20 you will update in your summary?
21 A. Yes.
22 MR. STANDISH:
23 Mr. Chairman, I would request that Mr. Stimart's
24 direct testimony and supplemental testimony be copied
NORTH CAROLINA UTILITIES COMMISSION
1 into the record as if read from the stand and Stimart
2 Exhibits 1 through 3 and Stimart Supplemental Exhibit
1 be marked for identification.
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CHAIRMAN REDMAN:
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e And the request is granted.
STIMART EXS. 1 - 3 & STIMART SUPPLEMENTAL EX. 1
IDENTIFIED
(REPORTER'S NOTE: The prefiled testimony
of William R. Stimart will be reproduced in
the record at this point the same as if the questions
11 had been orally asked and the answers orally given
12 from the witness stand.)
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Q.
A.
Q.
A.
Q.
A,
TESTIMONY OF
W. R. STIMART
FOR
DUKE POWER COMPANY
NCUC DOCKET NO. E-7, SUB 487
PLEASE STATE YOUE NAME, ADDRESS AND POSITION WITH DUKE POWER COMPANY.
My name is William R. Stimart and my business address is 422 South
Church Street, Chari-OLte, North Carolina. I am Vice President, Rates
and Regulatory Affairs of Duke Power Company.
STATE BRIEFLY YOUR EDUCATION, ACCOUNTING BACKGROUND AND PROFESSIONAL
AFFILIATIONS.
I am a graduate of the University of Illinois, holding a degree of
Bachelor of Science in Accounting. I am a Certified Public Accountant,
with membership in the American Institute of CPA's and the North
Carolina Association of CPA's. I am also a member of the Committee on
Corporate Reporting of the Financial Executives Institute (FEI) as weii
as a member of the Accounting Research Committee of the Edison Electric
Institute,
PLEASE DESCRIBE YOUR BUSINESS BACKGROUND AND EXPERIENCE.
Upon graduation from college in 1953, I joined Arthur Andersen & Co., an
international firm of Certified Public Accountants. During the
following eleven years, I worked almost exclusively with public
utilities in the areas of audit, accounting, finance and regulatory
matters. From 1964 to the spring of 1971, I was associated with
Ayrshire Collieries Corporation in varying positions, the last of which
1 was Controller. I joined Duke Power in May 1971 as Assistant Treasurer,
2 was elected Treasurer in April 1972, Controller in October 1976 and Vice
3 President, Regulatory Affairs in October 1979, I became Vice President,
A Rates and Reguiatory Affairs in August 1990.
5
6 Q. ARE YOU FAMILIAR WITH THE ACCOUNTING PROCEDURES AND BOOKS OF ACCOUNT OF
7 DUKE POWER COMPANY?
8 A. Yes. The books of account of Duke Power Company follow the uniform
y classification of accounts prescribed by the Federal Energy Regulatory
Commission (FERC) and by the National Association of Regulatory Utility
Commissioners (NARUC).
MR. STIMART, HAVE YOU PREVIOUSLY TESTIFIED BEFORE THIS COMMISSION?
Yes. I have testified on financial and accounting matters in all of the
Company's general rate cases since 1973. I have also testified in
connection with numerous applications by the Company to adjust its
electric rates and charges based solely on changes in the cost of fuel.
PLEASE SUMMARIZE BRIEFLY WHAT YOUR TESTIMONY IN THIS CASE WILL COVER,
My testimony will cover the results of the Company's operations under
present and proposed rates on the basis of an adjusted historical test
period using the 12 months ended December 31, 1990. I will also discuss
the additional revenue required as a result of the commercial operation
of the Bad Creek Pumped Storage facility. The Company's operating
results and the data required under NCUC Rule Rl-17(b) of the
Commission's Rules and Regulations are set forth in Stimart Exhibits 1,
2 and 3,
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Q.
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1 Q. WERE STIMART EXHIBITS 1, 2, AND 3 PREPARED BY YOU OR AT YOUR DIRECTION
2 AND UNDER YOUR SUPERVISION?
3 A. Yes, these exhibits were either prepared by me or at my direction and
A under my supervision. The North Carolina retail jurisdictional amounts
5 were developed in part by direct assignment of costs and in part by
6 allocations based on demand, energy and customer data.
7
8 Q. ARE THE CAPITAL AND OPERATING EXPENDITURES REPRESENTED ON THESE EXHIBITS
9 REASONABLE?
10 A. Yes. The Company has in place various budgeting, planning and review
11 procedures to establish and monitor the capital and operating budgets as
12 well as actual expenditures. The system of internal accounting controls
13 provides reasonable assurance that all transactions are executed in
14 accordance with management's authorization and are recorded properly,
15 The system of internal accounting controls is annually reviewed,
16 tested and documented by the Company's Internal Audit Department to
17 provide reasonable assurance that amounts recorded on the books and
18 records of the Company do not contain significant errors or
19 irregularities. The books of account of Duke Power Company are audited
20 - on a regular basis by the FERC staff for compliance with FERC accounting
21 requirements. In addition, the FERC staff examines the Company's
22 accounting policies, practices, procedures and internal controls. The
23 Public Staff of this Commission and the staff of the Public Service
24 Commission of South Carolina aiso examine our books and records.
25 In addition, independent certified public accountants perform an
26 annual audit to provide assurance that internal accounting controls are
27 operating effectively and that the Company's financial statements are
28 accurate.
7
1 Q. PLEASE EXPLAIN WHAT IS PRESENTED ON PAGE 1 OF STIMART EXHIBIT 1 ENTITLED
2 "OPERATING INCOME FROM ELECTRIC OPERATIONS".
3 A. Page 1 summarizes the Company's electric operations for the test period
A ended December 31, 1990 for total Company and North Carolina retail
5 operations before and after the necessary accounting adjustments. It
6 also shows the rate of return on North Carolina retail rate base before
7 and after the proposed increase.
8 The Company accounts for distribution plant and revenues from
9 kilowatthour sales on a jurisdictional basis. All other items are
10 accounted for on a system basis. Lines 1 through 11 under Column 1 set
11 forth the actual operating revenues and expenses from the Company's
12 books for the twelve months ended December 31, 1990. Actual operating
13 revenue and expenses for North Carolina retail electric operations are
14 shown in Column 2.
15 Column 3 summarizes the accounting adjustments allocated to North
16 Carolina retail necessary to correlate the cost of service with adjusted
17 end-of-period rate base, and to reflect a representative level of
18 operations which includes the Bad Creek Pumped Storage Facility in cost
19 of service. These adjustments are shown on Stimart Exhibit 1, page 3
20 and are explained later in my testimony.
21 Column A shows adjusted North Carolina retail operations before the
22 proposed increase.
23 Column 5, line 1 shows the additional revenue requirement of
2A $222,594,000, as developed on page 2 of Stimart Exhibit 1. This is the
25 increase necessary to cover the Company's cost of service, including a
26 rate of return on common equity of 13.50%. Column 5 also shows the
27 effect of the revenue increase on general taxes and income taxes.
1 Column 6, line 11 shows adjusted operating income after the
2 proposed increase. Line 12 shows adjusted North Carolina retail rate
3 base. Dividing operating income by rate base produces the 11,03% rate
A of return which the Company is seeking in this case, as shown on line
5 13.
6
7 Q. PLEASE EXPLAIN IN GREATER DETAIL HOW THE NORTH CAROLINA RETAIL AMOUNTS
8 IN COLUMN 2 WERE DETERMINED.
9 A. First, wholesale electric operations were separated from total electric
10 operations leaving total retail electric operations in North and South
11 Carolina. Next, North Carolina retail electric operations were
12 separated from total retail electric operations. A detailed review of
13 revenue and expense items resulted in the direct assignment of some
IA items. Those revenue and expense items which could not be directly
15 assigned were allocated using applicable "per book" allocation factors.
16 The same process was used to determine the North Carolina retail rate
17 base components set forth on pages A, Aa, Ab, Ac and Ad.
18 Production and transmission demand-related items were allocated
19 using demand factors based on peak responsibility. Energy-related items
20 were allocated using factors developed from annual kwh sales adjusted
21 for losses for the test period.
22 The accounting adjustments in column 3 on pages 1, A, Aa and 4b
23 were directly assigned or allocated using factors from the per book
2A jurisdictional cost study.
1 Q. WITH REFERENCE TO THE ALLOCATION OF PRODUCTION AND TRANSMISSION
2 DEMAND-RELATED ITEMS, WHAT IS MEANT BY "PEAK RESPONSIBILITY"?
3 A. "Peak responsibility" means the determination of the demand for
4 electricity that each jurisdictional rate class places on the production
5 and transmission system during the time of system peak. During the test
6 period, the summer coincident peak occurred on July 11, 1990 at 5:00
7 p.m. As discussed in Mr, Denton's testimony, the Company has used the
8 summer coincident peak allocation method in its cost studies since 1970.
9
10 Q. PLEASE EXPLAIN WHAT IS PRESENTED ON PAGE 2 OF STIMART EXHIBIT 1.
11 A. Page 2 sets forth the calculation of the additional revenue requirement
12 necessary to produce a 13.50% rate of return on common equity using the
13 fonnat required by NCUC Rule Rl-17(b)(9)e. To develop this figure,
14 North Carolina retail rate base of $A,669,92A,000 was allocated to its
15 capital source components of long-term debt, preferred stock and common
16 equity. This allocation was based on capitalization ratios as of
17 December 31, 1990 of AO.50% long-term debt, 9.68% preferred stock, and
18 A9.82% common equity.
19 The amount of operating income needed to cover interest and
20 preferred dividends applicable to North Carolina retail rate base was
21 computed using the embedded cost of long-term debt and preferred stock
22 as of Itecember 31, 1990. These amounts are shown in columns 5 and 8 on
23 lines 1 and 2. Operating income needed to cover long-term debt interest
2A and preferred stock dividends was deducted from total operating income
25 of $382,903,000 shown in column 5 on line A to derive operating income
26 remaining for common equity before the proposed rate increase shown in
27 column 5 on line 3.
10
1 Q. HOW WAS THE ADDITIONAL REVENUE REQUIREMENT OF $222,59A,000 SHOWN ON LINE
2 8 OF PAGE 2 DETERMINED?
3 A. As I stated earlier, the proposed increase is predicated on a rate of
^ return on common equity of 13.50%, shown in column 7, line 3. Applying
5 the 13.50% rate of return to that portion of the North Carolina retail
6 rate base financed by common equity, shown in column 6, line 3, produces
7 an operating income requirement for common equity of $31A,085,000, shown
8 in column 8, line 3.
9 The tuLdi operating income requirement shown in column 8, line A is
10 the sum of the requirements for long-term debt, preferred stock and
11 cornmon equity. Comparing the operating income requirement of
12 $515,132,000 to the operating income before the proposed increase of
13 $382,903,000, in column 5, results in an additional operating income
14 requirement of $132,229,000 as shown on line 6. To realize this
15 additional operating income the Company must collect in revenues the
16 increase in gross receipts taxes (3.22%), state income taxes (7%) and
17 Federal income taxes (3A%) totaling $90,365,000.
18 Adding the additional operating income requirement of $132,229,000
19 and the additional taxes of $90,365,000 produces the additional revenue
20 requirement of $222,59A,000.
21
22 Q. MR. STIMART. WHAT ARE THE EMBEDDED COST RATES FOR LONG-TERM DEBT AND
23 PREFERRED STOCK?
2A A. The long-term debt embedded cost rate of 8.78% is the weighted composite
25 cost of the Company's outstanding long-term debt (excluding current
26 maturities) as of December 31, 1990, The embedded cost rate also
27 reflects the cost of related debt discount, premium and issuance
28 expenses. The preferred stock embedded cost rate of 7.74% is the
, 7
11
1 weighted composite dividend rate of all of the Company's outstanding
2 issues of preferred and preference stock (excluding current sinking fund
3 requirements) as of December 31, 1990.
4
5 Q. PLEASE TURN TO PAGE 3 OF STIMART EXHIBIT 1 CAPTIONED "DETAIL OF
6 ACCOUNTING ADJUSTMENTS," AND EXPLAIN THESE ADJUSTMENTS.
7 A. Page 3 sets forth the individual accounting adjustments to revenue and
8 expenses (including income tax effects) for North Carolina retail
9 electric operations which were shown in summary total on page 1 of
10 Stimart Exhibit 1 in column 3. The totals on line 20 of page 3 are the
11 amounts carried forward to page 1 of Exhibit 1.
12 Line 1 is the additional North Carolina retail revenues and gross
13 receipts taxes required to reflect the annualization of rates in effect
14 at December 31, 1990 and the proposed fuel rate.
15 Line 2 adjusts fuel expense in the test period to reflect the
16 generation mix, quantity of fuel, and price of fuel as shown on Stimart
17 Exhibit 2, which is discussed later in my testimony.
18 Line 3 adjusts revenue, fuel expense and gross receipts taxes to
19 reflect the expected annual level of kilowatthour (KWH) sales resulting
20 from growth in the number of customers during the test period.
21 To determine additional revenue due to customer growth, an
22 end-of-period level of customers for residential, general and street
23 lighting rate schedules was developed using regressions over the 36
2A month period January 1988 through December 1990. The end-of-period
25 level of customers was compared to the actual number of customers billed
26 each month to yield monthly increases or decreases in number of
27 customers. The monthly increases (or decreases) in number of customers
28 were multiplied by the applicable average monthly KWH consumption per
12
1 customer to derive the annualized change in KWH consumption based on the
2 number of customers at the end of the test period,
3 Line A reflects adjustments to revenue, fuel expense and gross
A receipts taxes to normalize weather conditions experienced during the
5 test period. Because of milder than normal temperatures, actual KWH
6 sales were lower during the test period than they otherwise would have
7 been. Our Forecasting Department determined the effect that temperature
8 variances had on KWH sales. The change in KWH sales was then priced out
9 for each customer class during the test period at the rates in effect at
10 the end of the test year to obtain the adjustment to revenue. For
11 customer classes other than residential, the average price per KWH for
12 each respective class was used to develop the revenue resulting from
13 changes in KWH sales. For the residential class, the change in KWH
14 sales for each rate schedule within that class was apportioned to
15 specific blocks within the rate structure according to test period usage
16 patterns. The rate for each block was then applied to the KWH sales
17 assigned to the block to determine the adjustment to residential
18 revenue. The related fuel expense and gross receipts taxes due to this
19 adjustment in KWH sales were then calculated.
20- Line 5 reflects the annualization of depreciation expense, using
21 current depreciation rates, to the year-end level of plant in service at
22 December 31, 1990. The Company provides depreciation for major
23 production facility additions from the point in time that they go into
24 service. Depreciation for all other plant additions is based on the
25 average of beginning and year-end balances. Because a year-end rate
26 base is used in this proceeding, it is necessary to annualize
27 depreciation expense to reflect a full year's level of depreciation on
28 plant in service as of the end of the test period.
13
1 Line 6 adjusts depreciation expense to reflect the Company's
2 proposed depreciation rates and nuclear decommissioning expense. The
3 Company employed Foster Associates, Inc. to assist in the preparation of
4 a depreciation rate study. This study, which is included in Item 10 of
5 the NCUC Form E-l filed in compliance with Rule Rl-17(b), serves as the
6 basis for the proposed rates.
7 The following table sets forth the Company's current and proposed
8 depreciation rates:
9
10 Function Present Proposed Difference
11 Production
12 Steara 3.57% 2.57% (1.00%)
13 Nuclear
14 Decommissioning 0.67% 1.61% 0.9A%
15 Investment 3.33% 3.09% (0.2A%)
16 Total Nuclear A.00% A.70% 0.70%
17 Hydraulic 1.50% 1.98% 0,A8%
18 Other 0.00% 0.7A% 0.7A%
19 Transmission 3.00% 2.57% (0.A3%)
20 Distribution 3.A0% 3.59% 0.19%
21 General 5.A8% 3.59% (1.89)
22 Total Utility 3.68% 3.69% 0.01%
23 Based on the study year of 1990 (actual balances at year-end 1989
2A plus estimated 1990 plant additions and retirements) the change in the
25 total composite depreciation rate was only 0.01%. This change includes
26 the proposed change in decommissioning expense. In the past, a .67%
27 rate for decommissioning was included in the A% nuclear depreciation
28 rate. The change in decommissioning results in a $32,OAS,000 increase
10
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1 in depreciation expense. This is offset however by a $31,55A,000
2 decrease in other depreciation for a net increase in depreciation
3 expense of $A8A,000.
4 The following table sets forth the components of decommissioning
5 expense included in cost of service in this proceeding:
6
7 (Dollars in Thousands)
8 Unit
9 Oconee 1
10 Oconee 2
11 Oconee 3
12 Oconee ISFSI
13 McGuire 1
14 McGuire 2
15 Catawba 1
16 Catawba 2
17 Total
18
19 *1990 Dollars
20 The study supporting the annual decommissioning expense is included
21 in Item 10 of the NCUC Form E-l filed in compliance with Rule Rl-17(b).
22 Tl16 amounts in the study are based on the prompt dismantlement method of
23 decommissioning because the Nuclear Regulatory Commission (NRC) requires
24 total funding as of the date of termination of the operating license of
25 each unit. In order to minimize costs, Duke decided to utilize a
26 combination of internal and external funds to fund the decommissioning
27 of its seven nuclear units. The NRC requires external funding for
28 decommissioning the contaminated portion of each unit. The external
11
:ands)
Total Cost*
$16A,792
158,311
202,855
21,750
171,2A6
186,265
23,A76
26,163
$954,858
Annual
System
$10,491
10,101
12,218
1,325
8,950
9,29A
1,199
1.271
$5A,8A9
Cost
fL c
$
ii
. Retail
6,526
6,283
7,600
82A
5,567
5,781
7A6
791
34,118
15
1 fund amount is based on estimates contained in the site-specific studies
2 done by TLG Engineering, Inc, in 1989 and 1990 for each Duke nuclear
3 unit. The external fund will be tax qualified to the extent possible
A under IRS rules and guidelines. The cost of decommissioning the rest of
5 the plant will be funded internally and accrued based on a sinking fund
6 methodology amount. Duke has selected Wachovia Bank & Trust Co. as the
7 trustee for the external funds.
8 Line 7 annualizes the increases in wage rates and related fringe
9 benefit costs that occurred during the test period. This adjustment
10 takes into account only those wage adjustments actually granted during
11 the year. It does not include the annualization of wages for new
12 employees. This adjustment also reflects the change in payroll taxes
13 due to test period wage increases and the change in the FICA tax base.
IA Line 8 reflects the adjustment to annualize O&M expenses other than
15 fuel, purchased power, wages and benefits based on growth in customers
16 during the test period. The annualization factor of .783A% was derived
17 by taking the increase in end of period customers over the 13 month
18 average number of customers. This factor was then applied to test
19 period O&M expenses excluding fuel, purchased power, wages and benefits
20 to calculate the adjustment,
21 Line 9 is a provision for the annual impact of inflation on the
22 Company's expenses occurring after December 31, 1990. The compound
23 annual growth rate in the Consumer Price Index (CPI) from December 1986
2A to December 1990 was A.830A%. This adjustment was calculated by
25 applying the A.830A% to test period O&M expenses excluding fuel,
26 purchased power, wages and benefits. Because the. proposed rates will
27 not be effective until almost a full year after the end of the test
28 period, this adjustment is necessary to make test period O&M expenses
12
16
1 representative of the expenses which will be incurred while these rates
2 are in effect.
3 Line 10 adjusts the income tax provision for the tax effect of the
4 annualization of interest expense reflected in the adjusted cost of
5 service,
6 Line 11 adjusts test period operating expenses, primarily operating
7 materials and supplies, to reflect the continual rise in unit costs
8 which occurred during the test period. The percentage increase of the
9 year-ena url over the average CPI for the test period of 2.68% was
10 applied to test period O&M expenses excluding fuel, purchased power,
11 wages and benefits. This adjustment annualizes the effect of inflation
12 which took place throughout the test period.
13 Line 12 adjusts the levelization of the Catawba purchased capacity
14 costs. This adjustment incorporates into the levelization the current
15 per KW level of purchased capacity payments as well as the current
16 deferred balance. The adjustment also reflects an extension of the
17 levelization of the capacity payments to the Cooperatives to October 31,
18 2001 the last year of any calculated capacity payments to the Catawba
19 buyers which is already the levelization period of the capacity payments
20 to the Municipal owners. This adjustment recognizes that all of Duke's
21 customers will benefit from the sale of Catawba, not just those
22 customers receiving service during the buy-back period.
23 Line 13 annualizes the license fee the Company pays to the NRC.
24 During the test period NRC operations were A5% funded by utilities.
25 Beginning in 1991 100% funding by utilities will be required causing
26 Duke's payment to the NRC to more than double.
13
17
1 Line IA adjusts test period expenses to reflect a provision for
2 incremental operating expenses related to expansion of the Company's
3 demand side programs in conjunction with its least cost planning.
4 Line 15 adjusts cost of service to reflect the operation of the Bad
5 Creek Pumped Storage Facility. This adjustment includes operation and
6 maintenance expenses, depreciation and property taxes.
7 Line 16 reflects a three-year amortization of the start up costs of
8 the Bad Creek Pumped Storage Facility consisting of depreciation and
9 carrying costs.
10 Line 17 annualizes the Company's Interconnection Agreement with
11 Nantahala Power & Light Company. The Nantahala system was connected to
12 the Duke system on October 1, 1990. Therefore, the test period only
13 reflects three months of service to Nantahala.
14 Line 18 reflects the annualization of a new fifteen-year Purchased
15 Power Agreement with R. J. Reynolds for the purchase of 45 MW from the
16 Tobaccoville Cogeneration Facility,
17 Line 19 annualizes test period property taxes on plant in service
18 at December 31, 1990. Property taxes for calendar year 1990 were
19 assessed based upon property balances at the end of 1989. Likewise,
20 property taxes for calendar year 1991 will be assessed based upon
21 property balances at the end of 1990. This adjustment increases
22 property tax expense in the test period to the year-end level of
23 investment.
24
25 Q. PLEASE EXPLAIN WHAT IS PRESENTED ON PAGES A THROUGH Ad OF STIMART
26 EXHIBIT 1.
27 A. Page A shows total Company and North Carolina retail components of
28 original cost rate base. The total Company amounts were taken from the
IA
1 Company's books as of December 31, 1990. The procedure used to
2 determine North Carolina retail rate base was discussed earlier in my
3 testimony. The North Carolina retail net plant in service amount of
4 $4,522,720,000 is an increase of $866,612,000 (24%) over the amount
5 determined by the Commission in the Company's last general rate case,
6 Docket No. E-7, Sub 408.
7 Pages Aa, 4b, Ac and Ad are details of components making up
8 original cost rate base as of December 31, 1990. On each of these four
9 pages, the first column shows the total Company book amounts at
10 December 31, 1990; column 2 reflects the amount for North Carolina
11 retail electric operations and column 3 sets forth the accounting
12 adjustments.
13 As shown on line 8 of page A, the Company is not seeking any
IA Construction Work in Progress in rate base in this proceeding.
15 Page Aa is a summary of the Company's investment in electric plant
lb in service as of December 31, 1990 by functional classification. The
17 adjustment in column 3 reflects the addition to plant in service of the
18 Bad Creek Pumped Storage Facility.
19 Page Ab details accumulated depreciation for each of the classes of
20 * electric plant in service. Current depreciation rates for each class of
21 property are shown at the bottom of the page on lines 8 through 15. The
22 provision for depreciation is recorded using the straight-line method
23 for each functional classification of plant. The Company uses the
2A composite method of depreciation under which the original cost of
25 property retired, together with removal cost less salvage, is charged to
26 accumulated depreciation. The accounting adjustments in column 3 are
27 the same amounts as the depreciation expense adjustments made to cost of
15
19
1 service to annualize depreciation for year-end plant and the Bad Creek
2 Pumped Storage Facility.
3 Page Ac is a summary of the Company's investment in materials and
A supplies as of December 31, 1990 included in rate base.
5 Page Ad reflects the working capital investment included in rate
6 base. Investor advanced funds on line 2, column 2 were calculated using
7 the lead-lag method applied to per books cost of service amounts.
8 Line 3 of page Ad reflects the net of tax unamortized bond
9 reacquisition premiums the Company incurred in refinancing its higher
10 cost debt. These premiums are being amortized over the terms of the new
11 bonds.
12 Line A of page Ad shows the Company's investment in miscellaneous
13 deferred items required for the day-to-day operation of the Company.
IA
15 Q. PLEASE EXPLAIN PAGES 5, 5a, 5b AND 5c OF STIMART EXHIBIT 1.
16 A. These pages contain the Company's financial statements as of
17 December 31, 1990. These pages are basically self-explanatory and are
18 filed as required by NCUC Rule Rl-17(b).
19 Q. WHAT LEVEL OF FUEL AND PURCHASED POWER HAS THE COMPANY INCLUDED IN ITS
20 COST OP SERVICE?
21 A. As shown on Stimart Exhibit 1, page 1, column 6, line 2 the Company's
22 cost of service includes $A82,873,000 of fuel consisting of system
23 average base fuel costs, nuclear fuel disposal costs calculated at 1
2A mill per KWH of net generation, and an adjustment to reflect the North
25 Carolina retail level of line loss. These amounts are set forth on
26 Stimart Exhibit 2, page 1.
27 Purchased power on Stimart Exhibit 1, page 1, column 6, line 3 of
28 $271,008,000 consists of non-fuel costs of purchased power from our
16
20
1 Catawba joint owners of $266,056,000 plus $A,952,000 of non-fuel
2 purchased power and net interchange,
3
4 Q. WHAT SPECIFIC KWH SALES AND FUEL FACTOR WERE USED TO DEVELOP BASE FUEL
5 COSTS?
6 A, The KWH sales component as shown on Exhibit 2, page 1, consists of the
7 following:
8 N.C. retail test period actual A0,160,7A6,000 KWH
-- explain to the Attorney General that this credit
7 card option payment plan was approved on a Monday
morning Staff Conference here or --
THE WITNESS:
I was thinking it was presented at a Monday
11 morning conference. I'd have to double check that.
12 CHAIRMAN REDMAN:
13 Well, the reason why I'm wondering is I'm
14 trying my best to remember whether or not I was
15 present for that, and that if I was present, whether
-- how it was -- whether or not it was presented
in such a manner as to reflect that you were going
18 to be allowed to charge on credit cards without
19 these -- and whether or not the service charges
20 were presented to us.
21 THE WITNESS:
22 It's my understanding that at the time we
23 discussed this extensively internally as to whether
24 -- what was the form of notification to a customer
NORTH CAROLINA UTILITIES COMMISSION
16
17
8
9
10
-, that that service charge was going to be his respon-
2 sibility. Now, I didn't sit on any of the presen-
3 tations, but I was told that that -- that was part
4 of the routine procedure that he would be advised
5 that he would -- ho would see that charge.
5 CHAIRMAN REDMAN:
7 Well, that's what we said about the 900 numbers,
too. We didn't get the word out too well on that
one.
I -- these credit card companies, if you
11 utilize most of them, you would have to pay them
12 a fee anyway, would you not? Some of them will
13 do it for nothing. But sometimes there's anywhere,
14 depending on how big the customer is, 1%, 2%
15 that the merchant would have to pay. Right?
16 THE WITNESS:
17 That's correct.
18 CHAIRMAN REDMAN:
19 And then they get another percentage on what
20 they -- if you don't pay your bill on time from
21 the consumer?
22 THE WITNESS:
23 That's correct. It may be that there is
24 a restricted area for application where people have
NORTH CAROLINA UTILITIES COMMISSION
88
, problems trying to get downtown to make deposits
2 to get service turned on, something of that nature.
3 But it may have an application that -- and that' s
. what we're looking at now.
CHAIRMAN REDMAN:
Well, what I -- most of these charges
7 the thing I'm concerned about, most of these charges
8
9
10
in addition to having Commission approval require
are at least controlled by law, particularly
the cap on the interest rate that can be charged,
11 Now, the -- these companies, as you well know, most
12 of them are coming out to where you have to pay
13 a charge now that I fought against once before in
14 the legislature of upwards of 15, 2 0 dollars for
the card. And then they get interest. Then the
15 merchant pays them to use the card. I'm trying
17 to figure out what the final rate would be for somebody
18 with $100 bill here -- would be if they had to finance
19 the thing out. I'm getting upwards of 30%.
20 THE WITNESS:
2i I think you're probably right. On the other
2 2 hand, talking to the controller of one of the major
2 3 companies that underwrites credit cards, they have
24 staggering bad debt .losses.
NORTH CAROLINA UTILITIES COMMISSION
89
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CHAIRMAN REDMAN:
I 'm
or
to
by
I 'm
trying
not --
the ere
sure they do.
to conclude
whether or not
dit card fees
legislation to where
That's the
And
--
I will
minutes
lunch hour.
on
MS.
to
to
THE
Are
question I 'm
check our Monde
and find out
however.
But I guess the question
in my own mind
the surcharge
that are paid
that can even
having in my
y morning Staff
is whether
in addition
are covered
be done.
own mind.
Conferences
more about this over the
there any other questions or questions
the questions from the
Ms.
LONG:
Mr.
Long.
Stimart, what
the credit card comp
credit cards?
WITNESS
It's
Duke.
MS. LONG:
All
*
Commission?
fee does Duke
any to have bi
have to pay
lis charged
my understanding there's no charge to
right.
CHAIRMAN REDMAN:
Very good. You're excused, Mr. St imart.
NORTH CAROLINA UTILITIES COMMISSION
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1 (WITNESS EXCUSED)
2
3 CHAIRMAN REDMAN:
4 Let's go off the record for a second here.
5 (DISCUSSION HELD OFF THE RECORD)
CHAIRMAN REDMAN:
Public Staff, would you please call your
witness.
MR. TURNER
The Public Staff's first witness is Tom Lam.
11 THOMAS S. LAM; Being first duly sworn, testified
as follows:
DIRECT EXAMINATION
14 BY MR. TURNER:
15 g. Mr, Lam, would you state your name and business
15 address for the record, please.
17 A. My name is Thomas S. Lam. I'm an engineer
18 with the Public Staff. My address is 430 North
19 Salisbury Street, Raleigh, North Carolina.
2 0 Q- And did you cause to be filed in this case
21 on August 28th of this year testimony consisting
22 of nine pages, one appendix and three exhibits?
2 3 A. Yes, sir.
24 g. And then subsequent to that at the request
NORTH CAROLINA UTILITIES COMMISSION
91
1 of the Commission Staff, was a fourth exhibit filed
2 to be attached to your testimony?
3 fl. Yes.
4 0. Do you have any corrections to that testimony?
fl. No, I don't.
g, If those questions were asked to you today,
7 would your answers be the same?
A. Yes, they would.
MR. TURNER:
10 Mr. Chairman, I ' d request that the testimony
11 be read into the record as though given orally from
12 the stand and that the exhibits be marked as they
13 were premarked with the prefiled testimony.
14 CHAIRMAN REDMAN:
15 Your request is granted.
15 LAM APPENDIX A, EXHIBITS TSL-1 THRU TSL-4
17 (IDENTIFIED
18 (REPORTER'S NOTE: The prefiled testimony
19 of Thomas S. Lam will be reproduced in the record
20 at this point the same as if the questions had been
21 orally asked and the answers orally given from the
22 witness stand.
23
24
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Q.
A.
Q.
A.
Q.
A.
Q.
A.
92
WILL YOU STATE YOUR NAME AND ADDRESS FOR THE RECORD?
My name is Thomas S. Lam. My business address is 430 North
Salisbury Street, Raleigh, North Carolina,
WHAT IS YOUR POSITION WITH THE PUBLIC STAFF?
I am an engineer in the Electric Division of the Public Staff
representing the using and consuming public.
WILL YOU BRIEFLY DISCUSS YOUR EDUCATION AND EXPERIENCE?
My education and experience are outlined in AppendixA to my
testimony. .
WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?
The purpose of my testimony is to present the Public Staff's
recommended cost-of-service methodology and base fuel factor. The
Public Staff recommends use of the summer/winter peak and average
methodology for jurisdictional and fully distributed cost
allocation purposes. Calculation of the base fuel factor is
fourfold: (1) modification of the Company's prefiled nuclear
capacity factor to 68.82%, which Is an average of the latest NERC
5-year nuclear capacity factor of 65.57% and the Duke's latest
five-year (1986-1990) average system nuclear capacity factor of
72.06%; (2) recommendation of the company's fuel calculation
methodology and an update of the Company's fossil fuel prices;
(3) presentation of the resultant fuel factor recommended by the
Public Staff; and (4) presentation of the fuel factor based upon
the latest NERC 5-year nuclear capacity factor of 65.57%.
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1 COST OF SERVICE
2 Q. WHAT IS THE SUMMER/WINTER PEAK AND AVERAGE METHOD?
3 A. It is a method of computing an allocation factor for production
4 plant that uses both the summer and winter peaks and recognizes
5 that a portion of production plant is related to energy production
6 or average demand. For Duke, this method allocates approximately
7 60% of production plant based on the average demand (energy) or
8 load factor. The remaining 40% of the plant Is allocated by
9 average of the summer and winter peaks.
10
11 Q. WHY IS THE SUMMER/WINTER PEAK AND AVERAGE METHODOLOGY BEING
12 RECOMMENDED BY THE PUBLIC STAFF IN THIS CASE?
13 A. Summer/winter peak and average (SWPA) allocation 1s being
14 recommended for two basic reasons. The first reason is that under
15 this methodology both seasonal peaks are considered in determining
16 the availability of generating units and system capacity
17 requirements. The two seasonal peaks are typically very similar
18 In size and must be met using the same production plant. The
19 second reason 1s that when there Is a basic need for new capacity.
20 there are generally three types of units to consider. These are
21 peaking units. Intermediate or cycling units, and base loaded
22 units. The selection of the type of unit is an economic one based
23 on the energy (kWh) requirement or the number of hours a unit must
24 operate each year. If little energy is required, the peaking
25 units are cost Justified due to their low capital cost as compared
26 to large base load units. If, however, much energy Is needed, the
27 lower energy cost (1/kWh) of capital-Intensive base load units
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1 makes them more desirable. It is, therefore, logical to conclude
2 that, while some of the production plant cost is incurred because
3 of the one-hour summer and winter peaks, some plant cost is also
4 incurred because of the energy or hour-use requirement of the
5 plant. The Commission has followed this reasoning in the last
6 three electric general rate cases, which are CP&L Docket No. E-2,
7 Subs 526 and 537, and VEPCO Docket No. E-22, Sub 314.
8
9 Q. WHAT HAS THE COMHISSION SAID IN ITS ORDERS WITH REGARD TO THE
10 SUMMER/WINTER PEAK AND AVERAGE COST ALLOCATION METHODOLOGY?
11 A. The Commission's order of August 5, 1988, in Docket No. E-2,
12 Sub 537, states:
13' Without baseload plants, CP&L would simply not be able 14 to serve its high load factor customers. It is only 15 appropriate that high load factor customers pay their 16 share of the cost of the base load plants built 17 primarily to serve them. The Commission is reluctant 18 to shift the cost of these production facilities to 19 further burden lower load factor customers, thereby 20 reducing their load factors and, ultimately, CP&L's 21 system load factor still further. 22 23 In its latest electric general rate order of February 14, 1991,
24 in Docket No. E-22, Sub 314, the Comniission states:
25 In Its Order dated December 5, 1983, in Docket 26 No. E-22, Sub 273, the Company's last rate case, the 27 Commission concluded that the cost allocation method 28 utilized for ratemaking purposes should recognize the 29 energy-related port1on of product1 on plant. 30 Essentially, the Commission reasoned that not all fixed 31 costs (for production plant) represent the cost of 32 meeting system peak demand, and that a significant 33 portion of fixed costs represents the cost of producing 34 kWh during many hours of the year and of producing such 35 kWh at a lower fuel cost per kWh. The Commission 36 continues to be persuaded In this proceeding that the 37 cost allocation method utilized herein should recognize 38 the energy-related portion of production plant fixed 39 costs.
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1 The Commission has also concluded in the previous rate 2 cases that the cost allocation method utilized for 3 ratemaking purposes should continue to recognize peak 4 responsibility as the basis for allocating the demand-5 related portion of production plant, and that peak 6 responsibility should include both the summer peak and 7 the winter peak. Essentially, the Commission reasoned 8 that the most significant capacity requirements placed 9 on the system were heating and cooling season loads, 10 and that while both types of loads were similar in 11 their impact on system capacity loads, the customer mix 12 contributing to the heating season load is 13 significantly different from the customer mix 14 contri but 1ng to the cool 1ng season 1oad. The 15 Commission continues to be persuaded in this proceeding 16 that the cost allocation method utilized herein should 17 recognize both the summer peak and the winter peak as 18 a basis for allocating the demand-related portion of 19 production plant fixed costs. 20 21 The Commission concludes in this proceeding that the 22 SWPA method will best recognize the requirement that 23 demand-related production plant fixed costs be 24 allocated based on peak responsibility. The method 25 also recognizes that not all production plant fixed 26 costs are demand-related, and it recognizes that 27 energy-related production plant fixed cost should be 28 allocated by kWh energy. The Commission concludes that 29 the SWPA method 1s the most reasonable and appropriate 30 method for determining jurisdictional and customer 31 class cost of service. 32 33
34 Q. IN REVIEWING THE COMPANY'S FILED SUMMER/WINTER PEAK AND AVERAGE
35 COST-OF-SERVICE STUDY. DID YOU FIND AN ERROR?
36 A. Yes, I did.
37
38 Q. WHAT WAS THAT ERROR?
39 A. In reviewing the company's filed summer/winter peak and average
40 cost study, I found that the company had used an Incorrect
41 allocation factor for most production related expenses.
42 Specifically, in the Duke SWPA, the average summer/winter
43 coincident peak (ASWCP) demand allocator was used in place of the
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96
1 SWPA demand allocator for all production related expenses except
2 for production plant. The use of the ASWCP allocator for demand-
3 related components in a SWPA cost-of-service study is incorrect.
4
5
5 Q. HAS THE PUBLIC STAFF CORRECTED THE COMPANY'S SUMMER/WINTER PEAK
7 AND AVERAGE METHODOLOGY?
8 A. Yes, I have adjusted all of the affected production plant and
9 production expense demand allocators, as filed by Duke in its
10 summer/winter peak and average study (SWPA). The SWPA methodology
11 as adopted by the Commission for CP&L and VEPCO uses the SWPA
12 demand allocator for allocating production plant and related
13 expenses. The remaining components (non-demand related) of the
14 SWPA study are the same as those used in the summer coincident
15 peak study. The Public Staff adjusted per book summer/winter peak
16 and average cost-of-service study summary is Included as
17 Exhibit TSL-1. This study also contains other adjustments as made
18 by Public Staff witness Maness.
19
20 Table No. 1 compares the returns of Duke's per books SCP study and
21 the Public Staff's adjusted per books SWPA study.
22
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97
TABLE NO. 1
Rates of Return (%)
5 6
7
8
9
10
11
12.
13
14
15
16
17
18
19
20
21
22
23
24
25
26
SWPA
SCP
NC Retail
10.3885
10.2321
NC Residential
9.8093
8.9206
NC General Service
12.1064
10.2249
NC Lighting
6.7687
10.2537
NC Industrial
10,0612
12.8494
Q.
A.
WHAT SHOULD THE COMMISSION DO TO ENSURE FAIRNESS IF IT ELECTS
TO RETAIN THE SUMMER COINCIDENT PEAK (SCP) ALLOCATION
METHODOLOGY?
The Commission, if It elects to retain the SCP niethodology,
should, for Increased fairness, at least ensure that each class
1s allocated only Its fair share of purchased (Catawba
Contract) and generated nuclear energy based on each class's
allocated share of rate base production plant as filed in the
Ouke Per Book SCP study. This SCP study shows that the
residential class 1s allocated 24% of rate base production
plant costs, general service 19.3% of costs, and Industrial
18.9% of costs. Thus, residential should be allocated 24% of
purchased and generated nuclear energy, general service 19.3%,
and industrial 18.9%. As it now stands, residential receives
20.1% of total nuclear energy, general service 17.8%, and
Industrial 23.5%. This adjustment 1s fair because no class
would willingly sell off Its low-cost nuclear energy charging
only for fuel and O&M costs without recovering associated
demand charges (rate base and production costs) of these plants
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1 from the purchasers of this energy. This adjustment to the SCP
2 methodology, however, is decidedly inferior to adopting the
3 SWPA methodology for Duke, as the Commission has done for the
4 other major electric utilities.
5
6 BASE FUEL FACTOR
7 Q. WHY ARE YOU RECOMMENDING A NUCLEAR CAPACITY FACTOR OF 68.58% IN
8 THIS PROCEEDING?
9 A. Duke's annual capacity factor for the past five years has been
10 outstanding, averaging over 72% for the period (Exhibit TSL-2).
11 This outstanding performance benefits the North Carolina retail
12 ratepayer but has also led to large overcollections on the part
13 of Duke. We seek to reduce the extent of the overcollection by
14 the use of both Duke's latest five-year (1986-1990) average
15 nuclear capacity factor of 72.06%, to recognize the above-
16 average nuclear performance of Ouke, and the latest NERC five-
17 year average nuclear capacity factor of 65.57%.
18
19 Q. DO YOU ACCEPT MR. STIMART'S FUEL PRICES AS FILED?
20 A. No, the Public Staff is updating Mr. Stimart's test year
21 average fossil prices. The coal price is being updated to the
22 July 1991 figure of 182.34</MBTU, the oil price Is being
23 updated to the July 1991 figure of 500.391/MBTU, and the gas
24 price is being updated to the July 1991 figure of 318.86*/MBTU.
25
26 Q. IS THERE ANY OTHER ADJUSTMENT YOU MADE TO DUKE'S FUEL FACTOR