ML19308A409
| ML19308A409 | |
| Person / Time | |
|---|---|
| Site: | South Texas, Comanche Peak  |
| Issue date: | 08/01/1979 |
| From: | Gross R CAROLINA POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML19208C305 | List:
|
| References | |
| ER77-485, NUDOCS 7909260207 | |
| Download: ML19308A409 (12) | |
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. CAROLINA POWER AND.LIGHI COMPANY FERC DOCKET NO. ER77-485 PREPARED TESTIMONY OF ROBERT M. GROSS, JR.
( 1 Q PLEASE STATE YOUR NAME AND ADDRESS.
2 i 3 A My name is Robert M. Gross, Jr. My business address is 1000 Crescent
) 4 Avenue, N.E., Atlanta, Georgia 30309.
J 5 6 Q WHAT IS YOUR EDUCATIONAL BACKGROUND?
7 8 A I graduated from Georgia Institute of Technology in 1965, receiving 9 the degree of Lachelor of Industrial Engineering. I also attended 10 Georgia State University and in 1971 received the degree of Master of 11 Business Administration, majoring in finance.
12 13 Q PLEASE STATE YOUR PROFESSIONAL EXPERIENCE.
! 14 15 A I have been employed by Southern Engineering Campany of Georgia for 16 approximately nine years. During this time I have been involved in 17 the preparation of cost of service studies of Class A and B investor-13 owned utilitics, rural electric cooperatives and municipal electric 19 systems and have participated in wholesale and retail electric rate 20 consulting assignments in 23 states. I am a registered professional 21 engineer in the State of Georgia.
22 23 Q HAVE YOU EVER TESTIFIED IN OTHER COSIISSION PROCEEDINGS?
24 25 A Yes, I have testified as a rate expert and cost of service witness
(' 26 before the State Commissions of Kentucky, Indiana, luchigan, Vermont, Texas 27 and Virginia. I have also testified.before the Federal Power Commission 28 in proceedings involving the Mississioni Power comoanv, FPC Docket No.
29 E-7685; Aooalachian Power Comoanv, FPC Docket No. E7775; Duke Power 30 Comoanv, FPC Docket No. E-7994; Gulf States Utilities Comoanv, FPC
- 31 Docket No. E-8911; Anoalachian Power Comoanv, FPC Docket No. E-9101; i
32 _Vircinia Electric Comoanv, FPC Docket No. E-9147; Arizona Public 33 Service comoany, FPC Docket No. E-8624; Public Service Comoany of Indian 2, 34 Inc., FPC Docket Nos. ER76-149 and E-9537; Carolino Power & Licht Comoanv,
! 35 FPC Docket No. ER75-495; Georcia Power Comoany, FPC Docket Nos. E-9091, 36 E-9521, E-9522 and ER76-587; Southern California Edison Comoany, FPC
38 ER77-578.
a 39 j 40 Q WHAT WAS YOUR ASSIGNMENT IN THIS PROCEEDING?
j 41 42 A First, I was to compute the demand allocation factors applicable to the
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43 Wholesale-For-Resale customer classification based upon the demand allocation 1
44 methodology established by the Presiding Law Judge in Docket No. ER76-495.
l 45 46 Secondly, I was to determine if the methods employed by Carolina Power &
47 Light (CP&L) to establish the proposed wholesale rate structure applicable .
48 to the Wholesale-For-Resale classification were just, reasonable and 49 consistent with sound rate making procedures.
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( 1Q WIIAT DATA 11 AVE YOU REVIEWED IN PREPARING YOUR TESTIMONY AND EXIIIBITS?
I 2
3 A I have reviewed those portions of CP&L's filing which relate either 4 to its estimated test year loads for wholesale service or to the 4 5 wholesale rate design. This would include testimony and exhibits 6 of CP&L's witnesses and other information CP&L supplied in response
, 7 to the FERC staff and various intervenor requests for data.
> 8 9 Q WOULD YOU PLEASE SUMMARIZE TIIE COOPERATIVE INTERVENOR POSITION WITil 10 REGARD TO YOUR TESTIMONY IN TIIIS PROCEEDING?
11 12 A With raspect to the calculation of the Wholesale-For-Resale demand
- 13 alloca: ion factors based upon the Initial Decision in FERC Docket 14 No. ER'6-495, I have determined that CP&L hac erred as follows:
15 16 1. CP&L has incorrectly estimated the Wholesale-For-Resale monthly 17 demands coincident with the monthly system peaks for Period II; 18
- , 19 2. In calculating the Wholesale-For-Resale demand allocation 20 factors at the transmission level, CP&L has included in the 21 tholesale customers' load responsibility, capacity the
- 22. wholesale customer purchases directly from the Southeastern 23 Power Administration (SEPA) . This treatment requires the i 24 wholesale customer to compensate CP&L for the costs incurred 25 in wheeling SEPA capacity even though CP&L is paid directly 26 by SEPA for this transmission service.
27 .
28 Secondly, I believe that the Company's wholesale rate design is unjust and 29 unreasonable because it does not properly match CP&L's cost of providing 30 service to its wholesale customers. Specifically in this regard I believe 31 that the rate is deficient for the following reasons:
32 33 1. There are major cost differences between service to the Cooperative
, 34 wholesale classification and the Municipal and Private Utility 35 wholesale classification which require separate rate treatment 36 by wholesale classification.
, 37 38 2. Within each aholesale classification there is a substantial 39 difference letween the cost of service to delivery points at 69 kV 40 and above, and to delivery points below 69 kV which should also 41 be recognicad in the design of the rate structure.
42 43 3. Additional ~.y the Company's proposed 95% summer-base billing 44 demand rate.het, contained in the proposed wholesale rate, is 45 entirely inconsistent as a rate device with the methods employed 46 by Staff and intervenors to establish demand cost responsibility 47 on CP&L's system. Furthermore the Company provides no evidence 48 linking its own filed cost of service studies with the level 49 (957.) of the proposed ratchet provision.
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1 4. Finally I believe that the Company's tariff provision concerning 2 totalized metering is restrictive to the extent that it is unduly 3 discriminatory with respect to many of CP&L's wholesale customers.
4 I believe that the provision for totalized metering should be 5 revised to apply to any wholesale customer who takes service 6 from CP&L at two or more delivery points which have a voltage
, 7 of 115 kV or higher.
8 9 Q I IIAND YOU COOPERATIVE INTERVENOR EXHIBIT NO. (RMG-1) AND ASK YOU 10 TO IDENTIFY IT.
11 12 A This exhibit is entitled " Revised Statement M-Demand Responsibility 13 Allocation Factors, weighted Average CP Demand-Twelve Month, Period 11-1977."
14 .
15 Q WOULD YOU PLEASE EXPLAIN THIS EXHIBIT?
16 17 A This er.hibit shows the results of my computation of. the Period II demand 18 allocation factors ear the wholesale class based upon the allocation 19 methodology establt.shed by the Presiding Law Judge via the La.tial 20 Decision in Docket No. ER76-495.
21 22 Q WHAT ALLOCATION MEDIODOLOGY DID THE PRESIDING LAW JUDGE DETERMINE TO BE 23 JUST AND REASONABLE IN THAT DOCKET?
24 25 A The twelve month average coincident peak method, (12 month cps) .
( 26 27 Q DO YOU BELIEVE THAT TIIE TWELVE MONTH' COINCIDENT PEAK ALLOCATION METHOD 28 IS ALSO Ti1E MORE REASONABLE DEMAND COST ALLOCATION PROCEDURE IN TIIE 29 INSTAhI DOCITT? -
30 31 A Yes, I do. I will not go into a discussion of the merits of the 12 months 32 CP Allocation Method since the parties stipulated that the Commission's 33 eventual decision in Docket No. ER76-495 would hold as to the demand 34 allocation method in the Instant Case.
35 36 Q UlIAT DEMAND ALLOCATION METHOD DID T11E STAFF UTILIZE IN ITS DIRECT CAS2.
t 37 38 A The average of 12 month cps.
39 40 Q WIIAT WAS TliE STAFF'S EOURCE OF DATA IN COMPUTING TIIE DEMAND ALLOCATION 41 FACTORS?
42 43 A The monthly wholesale demands coincident with the Company's monthly system 44 peak demand were estimated by CP&L and included in Statement M of the 45 filing. These estimated monthly demands were used by Staff witness 46 Callagher to calculate his version of the twelve month coincident peak 47 demand allocation factors. Of course CP&L utilized this scme data to 48 compute its allocation factors which are based on the average of the 49 four summer months cps.
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( 1Q DOES YOUR EXHIBIT NO. (RMG-1) UTILIZE THE MONTHLY COINCIDENT DEMANDS 2 AS ESTIMATED BY CP&L? '
3 4 A No. I found that the monthly wholesale coincident demands estraated by 5 CP&L for Period II were significantly over-stated for the cooperative 6 class.
7 8 Q HOW DID YOU DETERMINE THAT CP&L's ESTIMATES WERE INCORREC'27 9
10 A First of all the Cooperative Period II allocation factors contained in 11 CP&L's filing were rather astounding when compared with the Period I 12 Factors.
13 14 Cooperative Power Supply Cooperative Energy 15 Production Demand Factor Allocation Factor 16 17 Period II (1977) 9.316% 7.884%
18 Period I (1976) 8.497% 8.238%
19 20 The increasing Cooperative demand responsibility in face of a decreasing 21 energy responsibility raised a red flag as far as the reasonableness of 22 the Company's Period II load protection. It is of course very unusual to 23 find such a dramatic increase in a wholesale customer's class demand factor 24 when the same customer class is merely holding its own as to energy 25 responsibility. Here we find the energy responsibility actually drops
(. 26 between Period I and Period II.
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28 This strange relationship between demand and energy responsibility indicates 29 that CP&L's Cooperative coincident demand estimates needed to be 30 thoroughly reviewed.
31 32 Q HOW DID YOU REVIEW CP&L's LOAD ESTIMATES?
33 34 A CP&L's working papers indicate that Period II monthly coincident load 35 estimates for the wholesale class were a product cf trends detected 36 in previous year's actually experienced loads. I therefore analyzed recent 37 years actual wholesale load and energy data to determine if *he estimated 38 wholesale demands and energy amounts, contained in CP&L's filing were 39 accurate with respect to historical demand and energy relationships.
40 41 Q I HAND YOU C00PERitTIVE INTERVENOR EXHIBIT NO. (RMG-2) AND ASK YOU TO 42 IDENTIFY IT.
43 44 A This exhibit is entitled " Analysis of Wholesale-For-Resale Load Factor-45 1971 thru 1976."
46 47 Q WOULD YOU PLEASE DESCRIBE THIS EXHIBIT?
48 49 A This exhibit shows the average of the twelve month coincident demands and 50 the energy requirements by wholesale classification for the years 1971 l
! (' 1 thru 1976. The ratio of energy (kWh) to the average of the twelve
- 2 month coincident demands is shown for both the Cooperatives and the 3 Municipal and Private Utility classifications. This relationship 4 is commonly called average annual hours used of coincident demand, 5 which when divided by 8,760 hours0.0088 days <br />0.211 hours <br />0.00126 weeks <br />2.8918e-4 months <br /> in the year produces a measure of 6 load factor. -
7 8 This exhibit shows that from 1971 thru 1976 the Cooperative wholesale 9 customers' monthly demands coincidental with CP&L's monthly system peak 10 demands produced an average of approximately 5,829 hours0.00959 days <br />0.23 hours <br />0.00137 weeks <br />3.154345e-4 months <br /> use of de=and 11 or approximately 66.5% load factor. This exhibit also shows the 12 comparable calculations for the Municipal and Private Utilities 13 classification.
14 15 It is particularly interesting to note that CP&L's estimate of the 16 Cooperative's average monthly CP and energy for Period II (shown on 17 Line 8) reselts in a significant decline in the Cooperative's anretal 18 average load factor to a level of 5,294 hours0.0034 days <br />0.0817 hours <br />4.861111e-4 weeks <br />1.11867e-4 months <br /> use o'f demand or apptoxi-
. 19 mately 60.4% load factor. A review of the annual hours use of demand 20 amounts for any of the years 1971 thru 1976 shows that at no time in tee 21 recent past has the Cooperatives' annual load factor approached the level 22 projected by CP&L for Period II.
23 24 This data is one indication that in estimating the Cooperatives' Period II 25 monthly coincident demands, CP&L totally disregarded the relationship I
(s 26 between CP demands and energy sales that has existed for the Cooperative 27 class over the past six years. -
28 29 Q I HAND YOU COOPERATIVE INTERVENOR EXHIEIT KO. (RMG-3) AND ASK YOU TO 30 IDENTIFY IT.
31 32 A This exhibit is entitled " Revised Estimates for 12 Month CP Demands 33 Whole sale -For-Re sale - Period II " -
34 35 Q WOULD YOU PLEASE EXPIAIN THE PURPOSE OF THIS EXHIBIT?
36 .
( 37 A This exhibit actually serves two purposes. First of all it provides a 38 second test of the accuracy of the Period II load estimates. Additionally, 39 since I have found these load estimates to be substantially in error for 40 the Cooperative class, the exhibit houses my computation of the proper 41 Molesale coincident loads.
42 43 Q WOULD YOU EXPLAIN THE CALCULATIONS SHOWN ON EXHIBIT NO. (RMG-3)?
1 44 45 A Although the data compiled on the previous exhibit ~ (Cooperative Intervenor
- 46 Exhibit No. (RMG-2) provides an indication as to the reasonableness of l 47 the Period II coincident demand estimates for the wholesale class, I 48 believe the best method for checking the validity of Period II estimates,
- 49 and if necessary, for determining projected monthly coincident demands, 50 is based upon trends in class diversity. By class diversity I mean the i
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1 relationship between the average monthly coincident peak demand and 2 the average monthly non-coincident peak demand.
3 4Q WHAT IS THE SIG"IFICANCE OF TIIIS LOAD RELATIONSHIP?
5 6 A The average monthly coincident demands are used to allocate costs 7 whereas the average monthly non-coincident peak demands are the values 8 used to compute revenues. Certainly the relationship between these two 9 demand values is extremely critical in order to properly match capacity 10 related revenues with allocated capacity related costs. The demand 11 coincidence, i.e.,the class average monthly coincident demand divided 12 by the class average monthly non-coincident demand, for a projected 13 test year should certainly be in tune with the class demand coincidence 14 cxperienced in the past. If the historic demand coincidence is disregarded 15 '/nen projecting coincident loads, then the resulting rate level could be 16 too high or too low, depending upon if the demand coincidence value, 17 produced by the projection, is too high or too low respectively.
18 19 I show on this exhibit that for the years 1974 thru 1976 the demand 20 coincidence for the Cooperative wholesale class averaged 85.17.. CP&L's 21 Period II projection of the relationship between the average monthly 22 coincident demands and the average non-coincident demands (as shown 23 on line 8 of this exhibit) results in a demand coincidence of 92.4%.
24 At no time during the 3-year period 1974 - 1976 did the Cooperative class 25 demand coincidence even begin to approach the high level projected by CP&L.
C 26 In this case CP&L's estimates must be discarded and new estimates computed 27 based upon more normal demand coincidence. I have therefore recalculated 28 the average of the twelve monthly coincident. demands for each of the 29 wholesale customer classifications based upon the average demand coincidence 30 experienced by that class for the Period 1974 thru 1976. These calculations 31 are shown on line 8 of Exhibit No. -(RMG-3).
32 33 Q WITH RESPECT TO THE SECOND AREA 0F YOUR TESTIMONY CONCERNING THE DERIVATION 34 0F THE WHOLESALE ALLOCATION FACTORS, WOULD YOU PLEASE EXPLAIN HOW YOUR 35 TREATMENT OF SOUTHEASTERN POWER ADMINISTRATION (SEPA) CAPACITY DIFFERED 36 FROM THE TREATMENI USED BY CP&L?
.' 37 38 A Yes. Referring to CP&L's filing, Statement M, Exhibit No. (ACG-2) 39 page 26 of 32, CP&L included in the wholesale loads used to determine 40 the Demand at Transmission Output (line 1), the capacity delivered to 41 the wholesale customer from SEPA. As shown on line 5 of page 26, the 42 Cooperative wholesale customers receive 29,300 kilowatts of preference 43 power from SEPA and the Municipals 700 kilowatts. CP&L includes the 44 SEPA capacity in the whol'e sale loads in computing the Power Supply 45 Transmission Demand Factor (line 2, page 26). In so doing, the whole-46 sale customer is assigned the cost of wheeling this power thru CP&L's 47 system. In fact, however, the Southeastern Power Administration,.under 48 its contract with CP&L, pays CP&L directly for this transmission service.
49 Section 8 of the contract between the United States of America Department 50 of Interior (Southeastern Power Administration) and CP&L provides:
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i 1 "The government will compensate the Company monthly for 2 the use of its facilities in delivering capacity and j os- 3 energy for the account of the government to the delivery
! 4 points of preference customers of the government at the
. 5 following charge: $16,250 per billing month."
1 6
. 7 This clearly indicates that CP&L has contracted with SEPA to provide 8 this transmission service at a negotiated arms length price. The
- 9 compensation that CP&L receives for this service is but one aspect of
- 10 a multi-faceted contract which , in part, makes available to CP&L' low 11 cost hydro electric capacity and energy. The Wholesale customere of 12 CP&L are certainly not party to the contract between CP&L and SEPA.
13 To the extent that the contract either over compensates or under 14 compansates CP&L for the required transmission service should have no 15 direct impact on the allocated cost of CP&L's service to the wholesale t 16 class. For these reasons, SEPA capacity should be excluded from the 17 wholesale loads in determining the Power Supply Transmission Demand
- 18 Factor for the Wholesale class. I have also advise'd Cooperative
! 19 Intervenor Witness Solomon to specifically credit the revenues' received 20 by CP&L from SEPA to the non-wholesale classification of service.
! 21 22 Q NR. GROSS, WOULD YOU PLEASE EXPIAIN WHY YOU ADVOCATE THAT THE RATE DESIGN 23 APPLICABLE TO THE WHOLESALE CLASSIFICATION SHOULD RECOGNIZE MAJOR DIFFERENCES l'
24 IN COST OF SERVICE THAT EXIST BEIWEEN WHOLESALE CUSTOMERS?
25
( 26 A In order to be just and reasonable within the meaning of section 205 of the 27 ,
Federal Power Act, rates should be designed to truly reflect the cost of 28 service. This is not to say that every picayune difference in the cost 29 of service should be reflected in rate design. However, major differences 30 in cost of service should be so reflected. My analysis indicates that 31
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32 there are such major differences in cost of service in basically two areas of CP&L's service to the wholesale class:
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- 34 1. Cost differences between service to Cooperative wholesale 35 customers and to Municipal and Private Utility wholesale 36 customers;
- 37 38 2.
39 Cost differences between service at transmission 1cvels and
! 40 service at distribution levels within these wholesale customer categories.
41 42 Q I HAND YOU EXHIBIT NO. (RMG-4) AND ASK YOU TO IDENTIFY IT PLEASE.
43
. 44 A This exhibit is entitled " Statement "P" - As Revised Allocated Wholesale j 45 Cost Of Service, Period II - 1977."
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i 47 Q WOULD YOU PLEASE EXPLAIN THIS EXHIBIT?
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- 49 A Yes. This exhibit reflects the adjustments to the Company's filed
. 50 Statement "P" required to show (1) the impact of Cooperative Intervenor i
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, 1 cost of service adjustments on delivered unit cost and (2) the 2 development of demand charges associated with service to wholesale 3 loads served at both transmission voltages and distribution voltages.
4 5 As shown, on lines 11, 12, and 13, there is a substantial unit cost l 6 difference between service to the Cooperative whoicsale customers versus 7 service to the Municipal and Private Utility wholesale customers.
8 Additionally there is a significant cost of service difference between 9 service to transmission voltages as compared with service at distribution 10 voltages for both class of customers. I believe that both of these cost 11 of service differences should be integrated into the rate structures 12 applicable to wholesale service.
, 13 14 Q WHAT WOULD BE THE IMPACT ON TIE WHOLESALE COOPERATIVE CIASS IF THE 15 COOPERATIVE AND MUNICIPAL AND PRIVATE UTILITY WHOLESALE CLASSIFICATIONS 16 WHERE MERGED FOR RATE MAKING PURPOSES?
17 18 A Cooperative Intervenor Exhibit No. (RMG-4) shows that the average
, 19 unit cost to serve the total wholesale class is $6.21 per kilowatt and 20 8.78 mills per kilowatt hour (based upon $340 per month station charge).
21 Within the wholesale customer classification, there exists a substantial 22 difference in the unit capacity cost required to serve the Cooperatives 23 as compared to the Municipal and Private Utility service. Line 13 shows 24 that at the distribution level, the unit capacity cost required to serve f 25 the Cooperatives is $5.91 per kilowatt and service to the Municipals
(, 26 carries a higher unit cost of $6.42 per kilowatt. Combining the two 27 classifications of service for rate making purposes would require the 28 Cooperatives to support a -ate approximately 30c per kilowatt above its 29 allocated cost of service.21 Ihis translates into an overcharge of 30 approximately 1.4 million dollars per year. Obviously this far exceeds 31 a rone of reasonableness with respect to the just and reasonable defini-32 tions contained in section 205 of the Federal Power Act.
33 34 Q HAVE YOU READ THE PREPARED TESTIMONY OF STAFF WITNESS MICHAEL P. GALLAGHER 35 FILED IN THIS PROCEEDING?
36 c 37 A Yes.
38 39 Q DO YOU AGREE WI'HI HIS TESTD10NY CONCERNING THE CITY OF FAYETTEVILLE AS 40 A SEPARATE . CLASS OF CUSTOMER FROM TTIE OTIER WHOLESALE FOR RESALE CUSTOMERS 41 (MUNICIPALS AND PRIVATE UTILITY CLASS)?
42 43 A Yes, I agree in principle with Mr. Gallagher's approach of establishing 44 a specific class distinction for the City of Fayetteville. 'However, I 45 do not believe Mr. Gallagher went far enough in the application of his 46 principle. As I have emphasized my analysis indicates that, based upon 47 primarily differing load characteristics, wholesale for resale customers 48 indeed are, and should be treated as at least two separate distinct classes s 49 for rate making purposes; i.e., cooperatives and all other wholesale for 50 resale customers. I have no problem with the principle of subdividing
[1 Average wholesale unit demand cost = $6.21/kW
. Cooperative wholesale unit demand cost = $5.91/kW
$0.30/kW
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( 1 the Municipal and Private Utility wholesale class into Cities Other 2 Than Fayetteville and Fayetteville as long as proper cost of service 3 justification is provided.
4 5 I should point out that I am not in total agreement with regard to Mr.
6 Gallagher's calculations in this area because he has utilized CP&L's 7 Period II Demand estimates as a basis for his wholesale class allocation 8 factors. I have shown these estimates to be in error. However my re-9 estimation of the Period II monthly coincident wholesale demands for 10 the Municinal and Private Utility class does not appreciably vary from 11 those estimated by CP&L. A more detailed analysis of subgroups, such 12 as Fayetteville, within the Municipal and Private Utility class may also 13 show substantial errors in CP&L estimates. I have not cade this analysis, 14 therefore, I can only support Mr. Gallagher as to the philosophy 15 and principle of his approach to the City of Fayetteville as a separate 16 classification for rate making purposes.
17 18 Q PLEASE DISCUSS WHY YOU BELIEVE THAT THE RATE DESIGN IN THIS PROCEEDING 19 SHOULD BE STRUCTURED TO PROVIDE FOR A DIFFERENTIAL IN DEMAND CH/J1GES FOR 20 TRANSMISSION VERSUS DISTRIBUTION DELIVERIES.
21 22 A Referring again to Cooperative Intervenor Exhibit No. (RMG-4) I 23 show that there is a substantial cost of service differential between 24 CP&L's service to delivery points that have a transmission voltage 25 versus delivery points at a distribution valtage. For Cooperatives,
{ 26 the cost of service increases by 43c per kilowatt should the delivery 27 point be served at a distribution voltage (line 12, Exhibit No.
28 (RMG-4)).
29 30 Additionally as testified to by Company witnesses in previous CP&L ,
31 wholesale rate cases before this Commission, it has been the Company's 32 policy for many years--and continues to be the Company's policy--to 33 " encourage" wholesale customers to accept service from high voltage 34 transmission lines. In the past CP&L has accomplished this " encourage-35 ment" with a stick; it has, in effect, forced wholesale customers to 36 abandon their distribution voltage delivery points and accept service 37 at higher voltages. Of course when accepting the delivery at higher 38 voltages, the customers, rather than the Company, have born the higher 39 expense of transformation to distribution voltage levels. Since the
'+ 0 costs of transformation in those circumstances have been shif ted from 41 the company to the customers, the C ompany's cost of service for trans-42 mission delivery is significantly less than its cost of service for i 43 delivery below 69 kV (43c per kW 1ess for Cooperatives and 33c per kW 44 less for Municipalities). Once a wholesale customer has been compelled i 45 to take service at a higher voltage and incur the additional trans- I 46 formation investment, it is improper to apply to such new points of j 47 delivery, a rate that contains a component for distribution transforma-48 tion costs.
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1 Q MR. GROSS, W11AT IS TIE ATTITUDE OF TIE Wi!OLESALE CUSTOMERS CONCERNING i'
2 DESIGNING RATES, AS YOU SUGGEST, BASED UPON TIE DIFFERENCE IN CHARGES FOR 3 DELIVERIES OF 69 KV AND ABOVE AND DELIVERIES BELOW 69 KV?
4 5 A To the best of my knowledge, the only wholesale customer which has
! 6 expressed any dissatisfaction with this approach is Pee Dee Electric.
L 7 Membership Corporation.
8 9 Q IK YOUR OPINION WOULD SUCH A RATE DESIGN UNFAIRLY DISCRIMINATE AGAINST 10 PEE DEE EMC?
11 12 A No. The present rate design unfairly discriminates in favor of Pee Dee 13 EMC. Pee Dee EMC and other Cooperative and Municipal low voltage deli-14 very points are Seing cross subsidized by the high voltage delivery points 15 of the Cooperatise and Municipal class. As long as the wholesale rate 16 does not provide recognition of the cost differences between transmission
- 17 and distribution deliveries, then these cross subsidies will continue in 18 the future.
19 20 Q MR. GROSS, IN YOUR OPINION DOES T11E PROVISION OF THE COMPANY'S TARIFF 21 CONCERNING TOTALIZED METERING MEET THE STANDARDS OF " JUSTNESS" AND 22 " REASONABLENESS" OF TIE FEDERAL POWER ACT7 23 24 A No. To the best of my knowledge there are only two customers in the 25 Company who presently qualify for totalized metering. The City of Wilson C 26 qualified for totalization when it first became available several years 27 ago. The City of Fayetteville only recently qualified for this discount 28 by purchasing an existing substation from the Company. In my opinion, 29 this provision unreasonably discriminates against Cooperatives in favor 30 of Ibnicipalities. Two features of the provision caused this undue 31 discrimination. The first is a requirement that each and every delivery 32 point of the customer must be served at a voltage of 115 kV or higher.
33 The second is the requirement that the customer must accept a minimum 34 billing demand of 60,000 kilowatts. The Cooperative wholesale customers 35 of CP&L, because they serve in the sparcely-settled rural areas of the 36 state of North Caro (ina, are unduly discriminated against by the require-37 ment that all delivery points must be at voltages of 115 kV or higher 38 in order to qualify for totali=ed metering. In many instanets it is 39 more economical to serve small loads in remote locations from sd) transmission-40 level (below 115 kV) delivery points--more economical both to the whole-41 sale customer but particularly to CP&L. In these instances, the public 42 interest dictates that subtransmission-level deliveries be encouraged.
! 43 Municipals, on the other hand because of their very nature of having 44 their customers located in fairly dense and compact areas, very seldom 45 face this geographical problem and usually can economically accomodate 46 deliveries of 115 kV or above, 47 48 Furthermore, now that CP&L has magnetic tape meters at all of its wholesale 49 delivery points, there is no valid reason'why totalized metering cannot 50 be utilized for integrating all delivery points of any customer served at
( 1 115 or above regardless of whether that customer also has one or more 2 delivery points taking service at below 115 kV. The 60,000 kW limitation 3 has not been shown by the Company to be cost justified nor has it 4 shown the limitations to be necessary as a protection against revenue 5 crosion. In that context, if both limiations were to be removed then CP&L could certainly recompute the billing units for Period II
! 6 i 7 by class of customer to provide for a proper rate design which would 8 recover the allocated cost of service.
9 10 Q YOU HAVE PREVIOUSLY STATED THAT YOU DISAGREE WITH CP&L'S PROPOSED 95%
11 SIDBER-BASED BILLING DEMAND RATCHET. WOULD YOU PLEASE EXPLAIN WHY, 12 1
13 A I agree with Staff uitness Gallagher that it is not consistent from a i 14 rate making standpoint to adopt a very severe seasonable billing demand 15 ratchet when system demand related cost are allocated based upon an i
16 average of the demands placed on the system throughout the year.
17 18 CP&L includes in its proposed wholesale rate schedule a 95% su=mer-based 19 billing demand ratchet. This ratchet provision proposes a monthly minimum
- 20 billing demand based upon 95% of the highest non-coincident delivery point 21 demand experienced by the customer during the preceding months of June 22 through September. This ratchet, of course, causes individual wholesale 23 customers' power bills to be greatly influenced by the level of demands 24 experienced during the period of June through September. It makes little 25 sense on one hand to allocate demand related costs on the basis of an
(. 26 average of twelve monthly demands, as proposed by both Staff and Inter-27 venors, and then turn around and bil-1 the wholesale customer predominantly 28 on the basis of that customer's 'maximu= demand established during a four -
29 month period.
30 31 Q ASSUMING FOR TIE MOMENT Ti1E APPLICABILITY OF CP&L' S POWER SUPPLY I
32 DEMAND ALLOCATION METHODOLOGY (1.E. , FOUR SUFBER MONTH CP's), WOULD YOU l 33 THEN AGREE WITH TliE INCLUSION OF A SIDDER-BASED BILLING DEMAND RATCHET 34 IN CP&L'S WHOLESALE RATE STRUCTURE?
35 36 A Yes, I believe that the billing demand ratchet must be consistent with 37 the method used to allocate power supply cost. If power supply costs !
38 are properly allocable on the basis of the four succer months' CP's, 1 39 then it would be consistent to use a similar billing demand ratchet, as 40 CP&L has proposed in this case. However, even assuming the applica-
, 41 bility of CP&L's demand allocation methodology, which certainly Staff 42 and Intervenors oppose, I believe the 1cvel of CP&L's summer-based !
43 ratchet is too high.
44 45 Q WHY DO YOU BELIEVE THAT THE PROPOSED RATCIET LEVEL IS 'IDO HIGH?
46 47 A in CP&L's previous rate filing Docket No. ER76-495, I studied the whole-48 sale customers' summer seasonable diversity which existed at that time.
. 49 I concluded that the proposed 95% sur.:mer-based ratchet did not adequately 50 reflect the su=mer seasonal diversity that wholesale customers experience.
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i 1 I would propose th2t if the Com:nission ultimately approves the Company's 2 proposed demand cost allocation method in Docket No. ER76-495 and also j 3 approves the use of a summer-based billing demand ratchet, then the 4 sunrier seasonal diversity for the wholesale class should be used to i 5 determine the precise level of the summer-based ratchet.
l 6 7 Q WOULD YOU PLEASE SUDIARIZE YOUR RECO)DIENDATIONS CONCERNING THE DESIGN g 0F THE UHOLESALE RATE STRUCTURE.
9
, 10 A I believe the wholesale rate structure should encompass the following:
11 12 (1) The 1cvel o f demand, energy, and customer charges set out on 13 lines 11 & 13,14 and 15 respectively of Cooperative Inter -
14 venor Exhibit (R'4G-4) for Cooperative wholesale service
, 15 and for other wholesale (Municipal and Private Utility) 16 service.
17 l 18 (2) The 95% summer-based ratchet should be replaced with a 50%
19 year around ratchet. fl, 20 21 (3) 115 kV totalized metering available to any wholesale customer 22 with two or more delivery points at 115 kV.
23 j 24 Q DOES TilAT CONCLUDE YOUR TESTIMONY AT THIS TDIE?
i I
(
\.
25 26 A Yes.
27 28
, 29 30 i
31 '
j 32 33 I 34 35 1. The billing demand units shown on Cooperative Intervenor Exhibit 36 No. (RMG-4)., do not reflect a ratchet so, in the unlikely
- 37 event the 507. ratchet has an impact on the demand billing units, 38 the unit charges should be adjusted downward.
l 39 40
. 41
! 42 l 43 44 45
. 46 i
47 48
. 49 k
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