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{{#Wiki_filter:SJJ5P'" ' " ,.-pgp4:..g' "- ~ j ,/ W&9%/17
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,...f.a W I'.. TESTIMONY OF DAVID A.
:.. SJJ5P'   "'",     .-   pgp4
SPRINGS , FPC DOCITT NO. E-7685
                                  - ~fI j ,/ W&9%/17
-1 Q.Please state your name and place of residence.
      .
.2 A David A.Springs, 4514 North Peachtree Road, Chamblee, 3 Georgia.4 Q Would you state your educational background, please.
            .
.5 A I was graduated from GeorgiP. Institute of Technology 6 in 1948 with a Bachelor of Electrical Engineering Degree, 7 and again in 1949 with a Degree of Master of Science in 8 Electrical Engineering.
g' "
9 Q Would you state briefly your experience.
a W
I 10 A During graduate work at Georgia Tech, I had the unique s 11 experienge of working 15 ' months as Assistant Operator 12 of the Georgia Tech AC Network Calculator.
                        .
At that 13 time, the calculator was the most advanced tool for 14 studying the overall operations of power systems.
                                                                  '
This.15 experience gave me a very early understanding of load 16 flow and stability problems on large utility systems.
                    .     . TESTIMONY OF DAVID A. SPRINGS                         ,
17 Af ter graduation, I worked for Southern Engineering 18 Company in Atlanta, Georgia, for approximately three 19 years doing distribution design work, transmission 20 system design, and long-range power supply planning.
FPC DOCITT NO. E-7685
b..-21 From 1952 to 1963, I was with the South Carolina 22 Public Service Authority, first as Supervisor in Charge 1013 002 7 000= G WO27
    -
'.  
1 Q. Please state your name and place of residence.
*.--, , , 1 of Wholesale Billing, and then for a period of six 2 years aa their Planning Engineer.
              .2 A   David A. Springs, 4514 North Peachtree Road, Chamblee, 3     Georgia.
3 Since returning to Southern Engineering Company 4 of Georgia in 1963, I have been in charge of the Power
4 Q   Would you state your educational background, please.
'S Supply Planning and Power System Planning Section.
                                            .
6 Q Are you a registered professional engineer?
5 A   I was graduated from GeorgiP. Institute of Technology 6     in 1948 with a Bachelor of Electrical Engineering Degree, 7     and again in 1949 with a Degree of Master of Science in 8     Electrical Engineering.
7 A Yes, I am registered in the State of Georgia.
9 Q   Would you state briefly your experience.
8 Q To what scholastic and professional societics do
I             10 A   During graduate work at Georgia Tech, I had the unique s
.9 you belong?
11     experienge of working 15 ' months as Assistant Operator 12     of the Georgia Tech AC Network Calculator. At that 13     time, the calculator was the most advanced tool for 14     studying the overall operations of power systems. This
10 A I am a member of the IEEE and the Georgia Society of 1 11 Professional Engineers.
          .
I am also a member of Tau 12 B ta Pi (Scholastic Engineering) and the Eta Kappa Nu
15     experience gave me a very early understanding of load 16     flow and stability problems on large utility systems.
, 13 (Scholastic Electrical) . -
17           Af ter graduation, I worked for Southern Engineering 18     Company in Atlanta, Georgia, for approximately three 19     years doing distribution design work, transmission 20     system design, and long-range power supply planning.
14 0 nave you ever testified in other Federal Power 15 Commission cases?
b..-           21           From 1952 to 1963, I was with the South Carolina 22     Public Service Authority, first as Supervisor in Charge
16 A Yes.I have previously testified in the following 17 proceedings:
                                                                                  '
Georgia Power Company, FPC Docket No.
7 000= G WO27
E-18 7548; Carolina Power and Light, FPC Docket No. E-7564; 19 Duke Power Company, FPC Docket No. E-7557'; and Missis-20 sippi Power Company, FPC Docket No. E-7625.
                                        .
I have 21 also submitted my direct testimony for the Florida 22 Power Corporation Case, FPC Docket No. E-7679.
1013 002
@b 8'-2-N N'A ooj  
 
...'*..,*l Q Ly whom is your firm retained in this proceeding?
                                                                          *
{2 A Vermont Electric Cooperative, Inc.
    .
~3 Q What was your assignment?
,
4 A My assignment in this proceeding was a limited one.
                                                      -                       -
5 It was to determine the reasonableness of the 90%
      ,                           ,
'6" ratchet" provision contained in the Central Vermont 7 Public Service Corporation (CVPS) proposed Resale
1   of Wholesale Billing, and then for a period of six 2   years aa their Planning Engineer.
.8 Service Rate"R" Schedule as to whether such a ratchet
3         Since returning to Southern Engineering Company 4   of Georgia in 1963, I have been in charge of the Power
.9 can or should be based upon demand data occurring prior 10 to the effective date of the rate schedule containing il the ratchet provision.
          'S   Supply Planning and Power System Planning Section.
: t. v.12 O What material and information did you review in carrying 13 out your assigniaent?
6 Q Are you a registered professional engineer?
'14 A The CVPS Monthly Operating Reports for the years 1970 15 and 1971, the FPC Form 1 and Form 12 Reports of CVPS 16 for the same years, CVPS's proposed Resale Service Rate 17"R" Schedule, CVPS 's Statement"M" filing, and testimony 18 filed by various witnesses in this proceeding, cach in 19 Part as they relate specifically to my assignment.
7 A Yes, I am registered in the State of Georgia.
20 O Would you first explain what is neant by a " demand 21 ratchet provision".
8 Q To what scholastic and professional societics do
22 A It is a rate-making device which may be used in the- 3-,  
                                                                                .
.*<.,*e.l design of an electric power rate schedule, when
9   you belong?
{2 appropriate, to cause either the pricing elements in 3 the rate schedule to reflect the cost elements being 4 priced, to levelize the revenues from demand charges 5 over a period of time (usually one year) or to encourage 6 improvement in load factor.
10 A I am a member of the IEEE and the Georgia Society of 1
Essentially, the ratchet 7 sets the minimum billing demand charge in any month 8 relative to the maximum peak demand required by the
11   Professional Engineers.     I am also a member of Tau
.9 customer during a preceding period of time.
,
10 Stated in its simplest form, it may be said that 11 a rate schedule usually attempts to price two basic 1 ebements: the demand element and the associated energy 12 13 element.The demand element is a measure of capacity 14 or capability of delivering power and is usually 15 expressed in kilowatts (KW) or kilovolt-amperes (KVA).
12   B ta Pi (Scholastic Engineering) and the Eta Kappa Nu 13     (Scholastic Electrical) . -
16 The cecond element, the energy element, attempts to 17 put a price on the accumulated hour-by-hour use of the 18 demand or capacity element, and is usually expressed 19 in kilowatt-hours.
14 0 nave you ever testified in other Federal Power 15   Commission cases?
In effect, the demand' element is 20 usually measured as the maximum rate of using energy 21 throughout the billing period which is usually one month.
16 A Yes. I have previously testified in the following 17   proceedings:   Georgia Power Company, FPC Docket No. E-18   7548; Carolina Power and Light, FPC Docket No. E-7564; 19   Duke Power Company, FPC Docket No. E-7557'; and Missis-20   sippi Power Company, FPC Docket No. E-7625.     I have 21   also submitted my direct testimony for the Florida 22   Power Corporation Case, FPC Docket No. E-7679.
22 It is simply the maximum kilowatt-hours taken per hour IOl'' u!y, , 4--1013 005.  
  '
.,.-.-1 and therefore expressed in kilowatts.
                                                                              @b N8 N
2 Since the first element, or the demand element, 3 determines the capacity that must be built into the 4 facilities provided by the utility for a service,'' 5 this is the element the utility would use in attempting 6 to recover its costs which are fixed in nature and do 7 not vary with the amount of energy actually delivered.
                                                                        '
A ooj
 
      ..             .
'       *                                               .
    .     ,
* l   Q   Ly whom is your firm retained in this proceeding?
{
2 A   Vermont Electric Cooperative, Inc.
                                                  ~
3 Q   What was your assignment?
4 A   My assignment in this proceeding was a limited one.
5     It was to determine the reasonableness of the 90%
                                                '
6     " ratchet" provision contained in the Central Vermont 7     Public Service Corporation (CVPS) proposed Resale           .
8     Service Rate "R" Schedule as to whether such a ratchet
                                                                                  .
9     can or should be based upon demand data occurring prior 10     to the effective date of the rate schedule containing t
il     the ratchet provision.
                        . v.
12 O   What material and information did you review in carrying
                                                    '
13     out your assigniaent?
14 A   The CVPS Monthly Operating Reports for the years 1970 15     and 1971, the FPC Form 1 and Form 12 Reports of CVPS 16     for the same years, CVPS's proposed Resale Service Rate 17     "R" Schedule, CVPS 's Statement "M" filing, and testimony 18     filed by various witnesses in this proceeding, cach in 19     Part as they relate specifically to my assignment.
20 O   Would you first explain what is neant by a " demand 21     ratchet provision".
22 A   It is a rate-making device which may be used in the
                                            ,
 
    .
    *
<                                                     .
  ,
* e
      .
design of an electric power rate schedule, when
{           l 2   appropriate, to cause either the pricing elements in 3   the rate schedule to reflect the cost elements being 4   priced, to levelize the revenues from demand charges 5   over a period of time (usually one year)     or to encourage 6   improvement in load factor. Essentially, the ratchet 7   sets the minimum billing demand charge in any month 8   relative to the maximum peak demand required by the
                                                                                .
9   customer during a     preceding period of time.
10       Stated in its simplest form, it may be said that 1
11   a rate schedule usually attempts to price two basic 12  ebements: the demand element and the associated energy 13   element. The demand element is a measure of capacity 14   or capability of delivering power and is usually 15   expressed in kilowatts (KW) or kilovolt-amperes (KVA).
16   The cecond element, the energy element, attempts to 17   put a price on the accumulated hour-by-hour use of the 18   demand or capacity element, and is usually expressed 19   in kilowatt-hours. In effect, the demand' element is 20   usually measured as the maximum rate of using energy 21   throughout the billing period which is usually one month.
22   It is simply the maximum kilowatt-hours taken per hour IOl'' u!y, ,
                                      -
4-1013 005   .
 
      .
,                                                     .
    -
        .
  -
1   and therefore expressed in kilowatts.
2       Since the first element, or the demand element, 3 determines the capacity that must be built into the 4 facilities provided by the utility for a service,
            '' 5 this is the element the utility would use in attempting 6 to recover its costs which are fixed in nature and do 7 not vary with the amount of energy actually delivered.
8 These costs are primarily those costs associated with
8 These costs are primarily those costs associated with
.9 investment plus certain operating cos'ts which tend to 10 be fixed.All other costs,which would tend to vary with the amount of energy produced and sold,would be recovered t il. %*12 by the utility through the energy or KWH pricing element.
                                                                            .
13 It is the im element, or 'the element associated with 14 fixed costs, in which the demand ratchet provision would 15 come into play if found necessary in a rate schedule to 16 Properly recc.er fixed costs for the utility.or if found 17 desirable to levelize revenues.
9 investment plus certain operating cos'ts which tend to 10   be fixed. All other costs,which would tend to vary with t
18 The demand ratchet provision usually states simply 19 that, in the determination of billing demand for any 20 billing month, the billing demand shall not be less 21 than a certain percentage of the maximum demand 22 established during the previous year.
il the amount of energy produced and sold,would be recovered
This, in effect,-5-1013 006  
                  . %*
'..*., 1 allows for the pricing of fixed cost elements to (2 continue at the necessary or desired level even though 3 the use by the customer
12   by the utility through the energy or KWH pricing element.
>r group of customers might 4 drop below the " minimum billing domand" established 5 by the ratcl.et.
13 It is the im element, or 'the element associated with 14 fixed costs, in which the demand ratchet provision would 15 come into play if found necessary in a rate schedule to 16 Properly recc.er fixed costs for the utility.or if found 17 desirable to levelize revenues.
6 Q How do you determine whether a given demand ratchet 7 is necessary to recover fixed costs of the utility?
18       The demand ratchet provision usually states simply 19   that, in the determination of billing demand for any 20 billing month, the billing demand shall not be less 21 than a certain percentage of the maximum demand established during the previous year. This, in effect, 22 1013 006
8 A Stated very basically, the necessity of a demand
 
.9 ratchet provision in the rate schedules of a utility 10 usually develops when, throughout the annual cycle of
  '
'11 operation of the utility's facilities, there is gener-.c (12 ating or transmitting capacity which sits idle seasonally
    .
'13 and is otherwise unsold and not necessary or usable as 14 needed reserve capacity.
.
If there is no such capacity
      .
'15 standing for periods of time unused on a utility system, 16 there is no necessity for that utility to incorporate 17 demand ratchet provisions in its
                                                  *
: 2. ate schedule.
                                ,
With 18 this simple test as a measure of the need for demand 19 ratchet provisions in rate schedules, there are at least 20 five conditions or circumstances on the utility's system 21 which should be considered and taken into account in 22 determining whether a ratchet provision is necessary G --{{j j-
1   allows for the pricing of fixed cost elements to
'.-*-*..1 to recover fixed costs and, if so, at what level the 2 ratchet should be set:
(
..'(1)seasonally varying fixed costs.
2   continue at the necessary or desired level even though 3   the use by the customer >r group of customers might 4   drop below the " minimum billing domand" established 5   by the ratcl.et.
If a utility 3 4 has a seasonally varying fixed cost pattern, 5 which is similar to its seasonal load pattern, 6 the utility would not have fixed costs in the 7 off-Peak season to be recovered through a 8 ratchet provision.
6 Q How do you determine whether a given demand ratchet 7   is necessary to recover fixed costs of the utility?
.9 (2)Diversity between seasonal load natterns of 10 customers or classes of customers.
8 A Stated very basically, the necessity of a demand
To the 1 11 extent that customers or classes of customers. v.12 tend to use their maximum demands during different 13 seasons of the year', there would be a certain 34 amount of installed capacity and related fixed 15 costs that would be put to double use and there-16 f re would not be standing idle seasonally.
                                                                          .
17 (3)Maintenance and other reserve canacity requirements.
9   ratchet provision in the rate schedules of a utility 10     usually develops when, throughout the annual cycle of
18 To the extent that capacity which is normally sold 19 to customers during peak requirement' periods 26 seasonally is used in the off-season for main-21 tenanta purposes (in other words, used in the P ace of facilities that are then being maintained) , l 22.101~3 008- 7-1 1  
        '11     operation of the utility's facilities, there is gener-
'....1 there is a certain amount of capacity that is there-2 by not standing idle seasonally.
                .c
Incidentally, 3 some utilities are actually " maintenance 4 saturated" whereby they are maintaining generating 5 equipment over their annual peak because they do 6 not have enough capacity in their seasonally off-7 peak periods to carry out their maintenance program.
(       12     ating or transmitting capacity which sits idle seasonally
8 (4)The ability to exchance capacity seasonally with
                                        '
.9 other utilities.
13     and is otherwise unsold and not necessary or usable as 14     needed reserve capacity. If there is no such capacity
If a utility is located within 10 practical transmission distance of other utilities
                                                '
'll which have seasonally different load atterns,.c 12 there is a resulting capability for exchanging 13 capacity seasonally with such utilities.
15     standing for periods of time unused on a utility system, 16     there is no necessity for that utility to incorporate 17   demand ratchet provisions in its 2. ate schedule. With 18   this simple test as a measure of the need for demand 19   ratchet provisions in rate schedules, there are at least 20   five conditions or circumstances on the utility's system 21   which should be considered and taken into account in 22   determining whether a ratchet provision   is necessary j j
This 14 not only tends to reduce the utility's investment 15 in generating facilities, but it also makes good 16 use of some of the off-season capacity which might 17 otherwise be standing idle.
                                -
18 (5)Having the ability to buy and the market to sell 19 capacity and/or energy on an " emergency" basis.
G --
20 A utility which has interconnections and arrange-21 ments v/hich give it sources to purchase "emeigency" 22 capacity and/or energy and the market to nell u t]L: 3tpt- 8-U*, us a.1013 009  
{{
'.*.1" emergency" capacity and/or energy is accordingly 2 able to reduce reserve capaci ty requirements and 3 to obtain some revenue from seasonally off-peak 4 capacity which may ot'erwise stand idle.
 
5 Q.Have you analyzed CVPS's proposed 90% demand ratchet
      '
'6 to determine vihether it is necessary to recover CVPS's 7 fixed costs?
.-                                                       *
8 A.Taking each of the five conditions which I have just
  -                                                                               *
.9 described which tend to measure the necessity for a 10 ratchet provision to recover fixed costs, I found the i ll following:
            .                           .
12 ( )Since the overall determination of the need for a
1   to recover fixed costs and, if so, at what level the 2   ratchet should be set:
.13 ratchet provision in a rate schedule is a cumulative 14 thing, the most prominant circumstance or condition 15 affecting it should be considered first.
    ..
In the case 16 of the CVPS systcm in this filing, by far the most 17 Pronounced circumstance which tends to affect this 18 consideration is the fact that the fixed costs on the 19 CVPS system varios considerably on a monthly basis.
                    '
20 In those months of the year when the CVPS load is 21 highest, its fixed costs tend to be highest; and in 22 those months when the CVPS load is lowest, their fixed
3  (1) seasonally varying fixed costs. If a utility 4       has a seasonally varying fixed cost pattern, 5       which is similar to its seasonal load pattern, 6       the utility would not have fixed costs in the 7       off-Peak season to be recovered through a 8       ratchet provision.
_ 9_1013 010-  
                                                                                    .
.'...1 costs tend to be lowest.
9   (2) Diversity between seasonal load natterns of 10       customers or classes of customers. To the 1
My Exhibit (DAS-1), , 2 entitled " Monthly Comparison of Total Available 3 Generation with Monthly Peak Loads for the Years 1970 4 and 1971", shows a bar graph by months of the total "5 generation capability and the monthly peak load of 6 the CVPS system for eacia month of both the Test Year 7 1970 and the year 1971.
11       extent that customers or classes of customers
It will be noted that the 8 graphs show that the total generation capability
                      . v.
.9 available to CVPS varies considerably thr3ughout the 10 year and also to a considerable extent follows the
12       tend to use their maximum demands during different 13       seasons of the year', there would be a certain 34       amount of installed capacity and related fixed 15       costs that would be put to double use and there-16       f re would not be standing idle seasonally.
'll Pattern of the monthly peak load.
17   (3) Maintenance and other reserve canacity requirements.
This is a result. c.12 of the fact that CVPS purchases a very large pei entage
18       To the extent that capacity which is normally sold 19       to customers during peak requirement' periods 26       seasonally is used in the off-season for main-21       tenanta purposes (in other words, used in the 22        P l ace of facilities that are then being maintained) ,
, (13 of its total generation capability.
                                .
For instanc2, in 14 December, 1970, it purchased approximately 73%, and 15 in June, 1970, it purchased approximately 60%.
101~3   008 1
In 16 other words, in December of 1970, CVPS purchased 247 17 megawatts out of a total generation capability of 338 18 megawatts, and in June, 1970, CVPS purchased 141 19 megawatts out of a total generation capab'ility of 232 20 megawatts.
1
Quite a large percentage of these purchases 21 are either short-term purchases or allow for wasonal 22 variations which result in the pattern shown in
 
.- 10 -1013 011.,. . .Jl.L s e  
'
...-(1 Exhibit (DAS-1).2 O What is the source of CVPS 's purchased power?
.                                               .                       .
3 A Theu: re many and varied sources throughout New England
                                .
.4 plus the Pcaer Authority of the State of New York plus 5 the New Brunswick system in Canada.
1             there is a certain amount of capacity that is there-2             by not standing idle seasonally. Incidentally, 3             some utilities are actually " maintenance 4             saturated" whereby they are maintaining generating 5             equipment over their annual peak because they do 6             not have enough capacity in their seasonally off-7             peak periods to carry out their maintenance program.
A list of the 6 sources and a tabulation ot the amounts of the purchases 7 by months is shown on Witness Chayavadhanangkur's 8 Exhibit (JC-1) , pages 3 and 4.
8         (4) The ability to exchance capacity seasonally with
9 O How is it possible that CVPS is able to tap such wide 10 and varied sources for purchased power?
                                                                          .
11 A CV S obtains power over the interconnected transmission (12 systems of New England and New York into the State of
9             other utilities. If a utility is located within 10             practical transmission distance of other utilities
'13 Vermont and then over the VELCO system into CVPS, under 14 many varied contractual arrangements.
  'll             which have seasonally different load   atterns,
15 Q How is Central Vermont able to pattern its seasonal 16 purchases generally in accordance with its seasonal 17 needs?18 A It is in prrt due to the coordinated planning of the 19 utilities in the entire area as to the scheduling of 20 new generation.
                .c 12             there is a resulting capability for exchanging 13             capacity seasonally with such utilities. This 14             not only tends to reduce the utility's investment 15             in generating facilities, but it also makes good 16             use of some of the off-season capacity which might 17             otherwise be standing idle.
It is also due in part to the fact 21 that the interconnected systems of New England and 22 New York are able to exchange capacity seasonally
18         (5) Having the ability to buy and the market to sell 19             capacity and/or energy on an " emergency" basis.
-~-1013 012 a  
20             A utility which has interconnections and arrange-21             ments v/hich give it sources to purchase "emeigency" 22             capacity and/or energy and the market to nell U      3tpt
'...(1 during the winter peaking months of upper New England 2 and the summer peaking months of New York City up into 3 Massachusetts.
* u t]L: us a.
This is being done under a number of 4 varied contractual arrangements which I am personally 5 not fmmiliar wiVa, but the effect of it does reach up 6 into Vermont.
                                                                            ,
A good e'xample of this is the contract 7 which CVPS has with the Boston Edison system (actually 8 purchased and brought into tl a State by tne VEICO
1013 009
.9 sys tem) which provides for the following seasonally .
 
10 varying capacity purchases:
  '
11 July 1, 1970 to September 30, 1970 44,476 Kilowatts 1 (12 October 1, 1970 to May 31, 1971 127,497 Kilowatts 13 June 1, 1971 to Septembar 30, 1971 8,903 Kilowatts 14 October 1, 1971 to May 31, 1972 44,605 Kilowatts 15 June 1, 1972 to September 30, 1972 8,903 Kilowatts 16 October 1, 1972 to May 31, 1973 44,605 Kilowatts 17 June 1, 1973 to September 30, 1973 8,903 Kilowatts 18 October 1, 1973 to May 31, 1974 44,605 Kilowatts 19 June 1, 1974 to September 30, 1974 8,903 Kilowatts 20 October 1, 1974 to May 31, 1975 118,602 Kilowatts 21 June 1, 1975 to September 30, 1975 44,605 Kilowatts 22 The varying seasonal availability is obvious.
  .                                           *
~I~*If t ;l'>'a.1 -1013 013  
                              .
'...(l Q What do you conclude from this?
1         " emergency" capacity and/or energy is accordingly 2         able to reduce reserve capaci ty requirements and 3         to obtain some revenue from seasonally off-peak 4         capacity which may ot'erwise stand idle.
2 A I conclude that CVPS through the purchasing agreements 3 it han .sith other utilities has been able successfully 4 to fairly closely match its total available generation
5 Q. Have you analyzed CVPS's proposed 90% demand ratchet
'' S capacity to its n.onthly peak load.
                                      '
There are occasional excesses above needs to' meet loads from time to time, 6.but the amount of excess has no consistent relationship 7 8 with previous system peaks.
6     to determine vihether it is necessary to recover CVPS's 7     fixed costs?
The monthly pattern itsel.
8 A. Taking each of the five conditions which I have just
.9 is not even consistent, as would be indicated by comparing 10 Sheets 1 and 2 of the Exhibit (DAS-1).This ll certainly shows that a demand ratchet based upon the i (12 P evious peak demand has very little place in the cost 13 patterns of CVPS.
                                                                      .
Incidentally, this shows very strongly 14 that the 12-month average coincidant demand method of 15 allocating fixed costs is the proper method..
9   described which tend to measure the necessity for a 10     ratchet provision to recover fixed costs, I found the i       following:
16 Q Please continue with your analysis of CVPS's ratchet as 17 to each of your five criteria.
ll 12     ()   Since the overall determination of the need for a
18 A Continuing with the second condition:
.
19 (2)A cursory review of delivery point m'etering data 20 within the wholesale for resale customer class indicates 21 there would be come but not a great deal of seasonal
13     ratchet provision in a rate schedule is a cumulative 14     thing, the most prominant circumstance or condition 15     affecting it should be considered first. In the case 16     of the CVPS systcm in this filing, by far the most 17     Pronounced circumstance which tends to affect this 18     consideration is the fact that the fixed costs on the 19     CVPS system varios considerably on a monthly basis.
'22 diversity between the delivery points.
20     In those months of the year when the CVPS load is 21     highest, its fixed costs tend to be highest; and in 22     those months when the CVPS load is lowest, their fixed
I did not have
_ 9_
.'~~1013 014.
1013 010-
'.*.(1 the time to make a detailed study here, but this 2 would be somewhere between 5;? and 10%.
 
This would 3 tend to say that there is a doubling up on the sale 4 of capacity seasonally within the wholesale for resale 5 class, which would tend to reduce the need for a demand 6 ratchet by approximately 5% to 10%.
    .' .
7 (3)The need for seasonally off-peak capacity to meet 8 scheduled maintenance is not obvious on the CVPS system.
                                      .
.9 This is duc, of course, to the fact that the CVPS 10 system has only a small amount of generating capacity
                                                      .
'll in its system.
1         costs tend to be lowest. My Exhibit     (DAS-1),
However, the same effect comes into.c P ay with the " unit purchases" of CVPS from the outside l 12'13 which are not otherwise firmed.
,
In effect, when these 14 unit purchases are from generating units which aro down 15 for maintenance purposes, they must be replaced by 16 CVPS with other capacity.
2       entitled " Monthly Comparison of Total Available 3       Generation with Monthly Peak Loads for the Years 1970 4       and 1971", shows a bar graph by months of the total "5         generation capability and the monthly peak load of 6       the CVPS system for eacia month of both the Test Year 7       1970 and the year 1971. It will be noted that the 8       graphs show that the total generation capability
Since it is normal for such 17 units to be scheduled for maintenance in the months of 18 the year when the area loads are lowest, in effect 19 these maintenance reserve kilowatts would have a 20 tendency to be used for this purpose and otherwise 21 not stand idle in the off-peak months on the CVPS 22 system.(.i f i: ti- 14 -I ' br LaUl 1013 015.
                                                                              .
'.*, r'1 (4)In my test of CVPS 's ability to exchange capacity 2 seasonally with other utilities, this is definitely 3 an effective consideration.
9       available to CVPS varies considerably thr3ughout the 10         year and also to a considerable extent follows the
However, it has been 4 accomplished in a round-about way to a considerable 5 extent through the seasonal purchases discussed under
        'll         Pattern of the monthly peak load. This is a result
.6 Paragraph (1) above.
                    . c.
7 (5)A cursory review of the Operating Reports of CVPS 8 indicates that, in the month-to-month operation of its
  ,      12         of the fact that CVPS purchases a very large pei entage
.9 system, it is able to sell considerable quantities of 10 capacity and energy either as emergency power or other-t il wise.This would definitely have a tendency to make
(
'1;t least partial use of seasonally available capacity
13       of its total generation capability. For instanc2, in 14       December, 1970, it purchased approximately 73%, and 15       in June, 1970, it purchased approximately 60%. In 16       other words, in December of 1970, CVPS purchased 247 17       megawatts out of a total generation capability of 338 18       megawatts, and in June, 1970, CVPS purchased 141 19       megawatts out of a total generation capab'ility of 232 20       megawatts. Quite a large percentage of these purchases 21       are either short-term purchases or allow for wasonal 22       variations which result in the pattern shown in
,'13 v/nich would otherwise stand idle.
                                                                            .
14 Q What conclusions have you reached from this analysis?
                                                        .  ,
.A M st of the conditions or circumstances discussed in 15 16 Paragraphs (1) through (5) above would tend to
                      ...                                       1013 011 Jl.L s     e
.17 indicate that a ratchet provision is not necessary to 18 recover CVPS's fixed costs and probably not even 19 desirable in the Resale Service Rate"R"' Schedule.
 
20 Taken together, they definitely show that a 90% demand 21 ratchet provision is much too stringent and is out of 22 place in this filing as a dev2cc to recover fixed costs.
    ..
.1013 O!6  
    -
*.*.e (l Since the 90% demand ratchet is not necessary to 2 recover CVPS's fixed costs, it would appear that it 3 has been included in the rate schedule as a devict 4 to levelize revenues from the demand component a"'' 5 the rate schedule over the summer and winter se sons.
.
6 Q IIave you analyzed CVPS 's 90% demand ratchet to determine
(     1     Exhibit       (DAS-1).
'7 whether it is appropriate in this instance as a device 8 to levelize revenues?
2   O What is the source of CVPS 's purchased power?
.9 A Yes.In some instances on a utility system, there is consistent similarity in the seasonal load patterns of 10'll the customers in a given class.
3   A Theu:   re many and varied sources throughout New England .
In this case, if all uch customers have the same seasonal load patterns, (12'no customer is advantaged or disadvantaged with respect 13 to the others in the class by the application of a 14 15 ratchet or the non-application of a ratchet.
4     plus the Pcaer Authority of the State of New York plus 5     the New Brunswick system in Canada. A list of the 6     sources and a tabulation ot the amounts of the purchases 7     by months is shown on Witness Chayavadhanangkur's 8     Exhibit       (JC-1) , pages 3 and 4.
In such 16 cases, then, a ratchet may be used as an incentive to 17 improve load factor, or it may be applied in order to 18 levelize annual revenue.
9   O How is it possible that CVPS is able to tap such wide 10     and varied sources for purchased power?
In this instance there is no 19 evidence that the primary purpose of CVPS 's ratchet is as 20 an incentive to improve load factor.
11   A CV S obtains power over the interconnected transmission systems of New England and New York into the State of
As I indicated 21 above, the purpose of the 90% ratchet provision in the
(    12
-22 proposed resale Service Rate"R" Schedule appears to d[I, b$b*16 --1013 017  
                                          '
..,', 1 be to 2av31ize revenues.
13     Vermont and then over the VELCO system into CVPS, under 14     many varied contractual arrangements.
TIowever, an analysis of 2 the seasonal load patterns of purchases by different 3 wholesale for resale customers to be served under 4 Rate"R" Schedule shows that the summer to winter 5 peak comparisons among these customers varies quite 6 widely, which will cause certain of them to be 7 unfairly disadvantaged by the application of a 8 ratcher for revenue levelizing purposes.
15   Q How is Central Vermont able to pattern its seasonal 16     purchases generally in accordance with its seasonal 17     needs?
..9 Q What is the effect of CVPS 's 90% demand ratchet as 10 applied beginning June 28, 1972, based upon demands 1 11 occurring during the winter 1971-1972?.v 12 A Since the demand ratchet is not in this case a device 13 to recover actual fixed ' costs, but is instead a device 14 to levelize revenues, the effect is to spread a portion 15 f revenue related to CVPS's winter 1971-1972 sales over 16 to the summer 1972 period but at increased rates.
18   A It is in prrt due to the coordinated planning of the 19     utilities in the entire area as to the scheduling of 20     new generation. It is also due in part to the fact 21     that the interconnected systems of New England and 22     New York are able to exchange capacity seasonally
In 17 other words, Vermont Electric Cooperative is paying 18 again, at increased rates, for services it received 19 from CVPS and paid for at then existing rates during 20 the 1971-1972 winter period.
                                        -
21 O fir. Springs, I hand you Exhibit (DAS-2) consisting 22 of six pages, and entitled " Vermont Electric Cooperative, 1013 018"',_ 1, _  
                                ~     -
-..*, 1 Inc. Computation of Demand Charge Difference for 2 1972 Appl.ying Former Contract Ratchet Provisions, 3 versr.s 90% Ratchet, both Af ter June 28, 1972." 4 was this Exhibit prepared under your direct supervision?
1013 012 a
5 A Yes, it was.
 
'6 Q Would you describe the Exhibit, please.
  '
7 A This Exhibit was prepared at the request of the 8 Cooperative, to show the very severe effect of the
    .                                                   .
.9 application of a 90% demand ratchet during the year 10 1972; if made effective along with Resale Service Rate
                                        .
'll"R" Schedule on June 28, 1972; and is based on previous
1             during the winter peaking months of upper New England
'heakdemandsregisteredinthewintermonthsprior to 12 (the effective date of Ph'e new rate schedu._e.
(
The 13 14 computations are presented in tabular form and are 15 based on actual billing data for the early part of 16 the year and estimated billing data through December, 17 1972.The computations are sin.ilar in overy way 18 except for the ratchet provisions assumed.
2             and the summer peaking months of New York City up into 3             Massachusetts. This is being done under a number of 4             varied contractual arrangements which I am personally 5             not fmmiliar wiVa, but the effect of it does reach up 6             into Vermont. A good e'xample of this is the contract 7             which CVPS has with the Boston Edison system (actually 8             purchased and brought into tl a State by tne VEICO
In both 19 computations, the rates and charges of tlie proposed 20 Resale Service Rate"R" Schedule are assumed to be 21 in effect for the months of Ju.ly through December; 22 but in one case the demand billing computations are
                                                                                  .
.013 019 LlL'" ''.  
9             sys tem) which provides for the following seasonally .
,..1 based upon the 90% demand ratchet of Resale Service
10             varying capacity purchases:
<2 Rate"R" Schedule, and in the othcr case, the demand 3 b_11ing computations are based on ratchet provisions 4 cxisting in previously applicable schedules.
1 11                 July 1, 1970 to September 30, 1970     44,476 Kilowatts 12                 October 1, 1970 to May 31, 1971       127,497 Kilowatts
Page i of the Exhibit is a summary page showing a comparison 5 6 of the computation b'ased on 90% demand ratchet shown in Column (c) and the computation based upon the 7 8 former demand ratchet provisions shown in Column (d) 9 with the difference in resulting billing demands 10 shown on Line 1 under Column (e) and the dollar 11 difference shown on Line 2 in Column (e).
(
Pages 2 12 and 3 show the dollar computations and the billing 13 demand determinations,respectively,for the 90% ratchet 14 assumption.
13                 June 1, 1971 to Septembar 30, 1971       8,903 Kilowatts 14                 October 1, 1971 to May 31, 1972       44,605 Kilowatts 15                 June 1, 1972 to September 30, 1972       8,903 Kilowatts 16                 October 1, 1972 to May 31, 1973       44,605 Kilowatts 17                 June 1, 1973 to September 30, 1973       8,903 Kilowatts 18                 October 1, 1973 to May 31, 1974       44,605 Kilowatts 19                 June 1, 1974 to September 30, 1974       8,903 Kilowatts 20                 October 1, 1974 to May 31, 1975       118,602 Kilowatts 21                 June 1, 1975 to September 30, 1975     44,605 Kilowatts 22             The varying seasonal availability is obvious.
Pages 4 and 5 show the dollar computation 15 and the billing demand determination, respectively, 16 utilizing the former contract demand ratchet provisions.
          *If
17 The total amount of the increase is $64,844.
                  '
18 O Could the retroactive application of this ratchet 19 have any other adverse effect on Vermont Electric
                                          ~I ~
_20 Cooperative?
a .1 - t ;l
21 A Yes, definitely so.
                  >     '
Assume that the Vermont Yankee 22 Nuclear plant goco into commercial operation on
1013 013
_1013 090- 19 -..  
 
,..1 october 15, 1972 as contemplated by NEPEX as of 2 May 1, 1972.Vermont Electric Cooperative is 3 committed to purchase its 5,583 KN of Vermont Yankee 4 power from and af ter that date.
  '
When the Cooperative 5 starts taking its committed amount of power from 6 Vermont Yankee, this will reduce its required 7 capacity demand from CVES by the 5,583 131.
    .
Therefore, 8 it will be paying CVPS for the original amount of 9 unused ratcheted demand plus this additional 5,583 KN 10 demand v!hich is now excess to their needs.
                                                      .
This is a 11 doubling up of cost on Vermont olectric Cooperative (12 which is unreasonable and uncalled for.
                                      .
CVPS, in 13 addition to collecting these sums from the Cooperative, 14 can now, through their access via VELCO and NEPEX, sell 15 this capacity to other utilities in New England.
(         l     Q   What do you conclude from this?
In 16 effect, CVPS is charging its customers for capacity 17 the customer can't use, and then selling this capacity 18 to others; thus collecting twice for the same item.
2     A   I conclude that CVPS through the purchasing agreements 3         it han .sith other utilities has been able successfully 4         to fairly closely match its total available generation
19 Incidentally, if commercial operation of Vermont 20 Yanhoe is further delayed until early 1973 and after 21 the Cooperative has established its new winter peak, 22 the above described circumstances will exist throughout U (> l- r .',fi.s.-- 20 -1013 021 i'.-1 the remainder of 1973.
        '' S         capacity to its n.onthly peak load. There are occasional 6
(The 90% ratchet is very punitive in this case 2 3 and is out of place.
excesses above needs to' meet loads from time to time,
4 5 6.7 8 9 1C 11-12 c'13 14.15 16.17 18 19 20 21*22 1013 022- 21 -}}
                                                                                .
but the amount of excess has no consistent relationship 7
8       with previous system peaks. The monthly pattern itsel.
                                                                                  .
9       is not even consistent, as would be indicated by comparing 10         Sheets 1 and 2 of the Exhibit         (DAS-1). This i              certainly shows that a demand ratchet based upon the ll
(         12         P evious peak demand has very little place in the cost 13         patterns of CVPS. Incidentally, this shows very strongly 14         that the 12-month average coincidant demand method of 15         allocating fixed costs is the proper method..
16   Q   Please continue with your analysis of CVPS's ratchet as 17       to each of your five criteria.
18   A   Continuing with the second condition:
19         (2) A cursory review of delivery point m'etering data 20       within the wholesale for resale customer class indicates 21         there would be come but not a great deal of seasonal
                                                                    '
22       diversity between the delivery points. I did not have
            .
              '
                                        ~   ~
                  .
1013 014
 
  '.
                                                        *
                                      .
1           the time to make a detailed study here, but this
(
2           would be somewhere between 5;? and 10%. This would 3           tend to say that there is a doubling up on the sale 4           of capacity seasonally within the wholesale for resale 5           class, which would tend to reduce the need for a demand 6           ratchet by approximately 5% to 10%.
7             (3) The need for seasonally off-peak capacity to meet 8           scheduled maintenance is not obvious on the CVPS system.
                                                                                .
9           This is duc, of course, to the fact that the CVPS 10           system has only a small amount of generating capacity
      'll           in its system. However, the same effect comes into
                      .c 12            P lay with the " unit purchases" of CVPS from the outside
                                                '
13           which are not otherwise firmed.     In effect, when these 14           unit purchases are from generating units which aro down 15             for maintenance purposes, they must be replaced by 16           CVPS with other capacity. Since it is normal for such 17           units to be scheduled for maintenance in the months of 18           the year when the area loads are lowest, in effect 19           these maintenance reserve kilowatts would have a 20           tendency to be used for this purpose and otherwise 21           not stand idle in the off-peak months on the CVPS 22           system.
(                                                 .
Ii 'fbr i: ti                                   LaUl
    .
1013 015
 
  '.
                                                *
                              ,
r'       1   (4)   In my test of CVPS 's ability to exchange capacity 2   seasonally with other utilities, this is definitely 3   an effective consideration. However, it has been 4   accomplished in a round-about way to a considerable 5   extent through the seasonal purchases discussed under
                                      .
6   Paragraph (1) above.
7   (5)   A cursory review of the Operating Reports of CVPS 8   indicates that, in the month-to-month operation of its
                                                                      .
9   system, it is able to sell considerable quantities of 10   capacity and energy either as emergency power or other-t       wise. This would definitely have a tendency to make il
              '
,      1;     t least partial use of seasonally available capacity
                                        '
13   v/nich would otherwise stand idle.
14 Q What conclusions have you reached from this analysis?
                  .
15  A M st of the conditions or circumstances discussed in 16   Paragraphs (1) through (5) above would tend to
                                              .
17   indicate that a ratchet provision is not necessary to 18   recover CVPS's fixed costs and probably not even 19   desirable in the Resale Service Rate "R"' Schedule.
20   Taken together, they definitely show that a 90% demand 21   ratchet provision is much too stringent and is out of 22   place in this filing as a dev2cc to recover fixed costs.
                                                  .
1013 O!6
 
                                                                        *
  .
                                                *                         .
e Since the 90% demand ratchet is not necessary to
(      l 2       recover CVPS's fixed costs, it would appear that it 3       has been included in the rate schedule as a devict 4       to levelize revenues from the demand component a"
    '' 5       the rate schedule over the summer and winter se sons.
                                        '
6   Q IIave you analyzed CVPS 's 90% demand ratchet to determine 7       whether it is appropriate in this instance as a device 8       to levelize revenues?
                                                                            .
9   A Yes. In some instances on a utility system, there is 10        consistent similarity in the seasonal load patterns of the customers in a given class. In this case, if all
    'll uch customers have the same seasonal load patterns,
(     12
                                          '
13 no customer is advantaged or disadvantaged with respect to the others in the class by the application of a 14 15         ratchet or the non-application of a ratchet. In such 16         cases, then, a ratchet may be used as an incentive to 17       improve load factor, or it may be applied in order to 18       levelize annual revenue. In this instance there is no 19       evidence that the primary purpose of CVPS 's ratchet is as 20       an incentive to improve load factor. As I indicated 21       above, the purpose of the 90% ratchet provision in the
    -22         proposed resale Service Rate "R" Schedule appears to d[I, b$b                                             *
                                    -
16 -
1013 017
 
  ..
    ,
                                                '
                                ,
1     be to 2av31ize revenues. TIowever, an analysis of 2     the seasonal load patterns of purchases by different 3     wholesale for resale customers to be served under 4     Rate "R" Schedule shows that the summer to winter 5     peak comparisons among these customers varies quite 6     widely, which will cause certain of them to be 7     unfairly disadvantaged by the application of a 8     ratcher for revenue levelizing purposes.
                                                        .                 .
9   Q What is the effect of CVPS 's 90% demand ratchet as 10     applied beginning June 28, 1972, based upon demands 1
11     occurring during the winter 1971-1972?
              .v 12   A Since the demand ratchet is not in this case a device 13     to recover actual fixed ' costs, but is instead a device 14     to levelize revenues, the effect is to spread a portion 15       f revenue related to CVPS's winter 1971-1972 sales over 16     to the summer 1972 period but at increased rates. In 17     other words, Vermont Electric Cooperative is paying 18     again, at increased rates, for services it received 19     from CVPS and paid for at then existing rates during 20     the 1971-1972 winter period.
21   O fir. Springs, I hand you Exhibit         (DAS-2) consisting 22     of six pages, and entitled " Vermont Electric Cooperative,
"'
          ,
_ 1, _
1013 018
 
                                                                        .
  -
    .
                                                  *
                                  ,
1     Inc. Computation of Demand Charge Difference for 2       1972 Appl.ying Former Contract Ratchet Provisions, 3     versr.s 90% Ratchet, both Af ter June 28, 1972."
4     was this Exhibit prepared under your direct supervision?
5   A Yes, it was.
                                          '
6   Q Would you describe the Exhibit, please.
7   A This Exhibit was prepared at the request of the 8     Cooperative, to show the very severe effect of the
                                                                            .
9     application of a 90% demand ratchet during the year 10       1972; if made effective along with Resale Service Rate
      'll       "R" Schedule on June 28, 1972; and is based on previous
(
12      'heakdemandsregisteredinthewintermonthsprior           to 13      the effective date of Ph'e new rate schedu._e. The 14       computations are presented in tabular form and are 15       based on actual billing data for the early part of 16       the year and estimated billing data through December, 17       1972. The computations are sin.ilar in overy way 18       except for the ratchet provisions assumed. In both 19       computations, the rates and charges of tlie proposed 20       Resale Service Rate "R"   Schedule are assumed to be 21       in effect for the months of Ju.ly through December; 22       but in one case the demand billing computations are
                                                                          .
  " ''
LlL'                                                     013 019
            .                      
      ,
    .
.
  <
1   based upon the 90% demand ratchet of Resale Service 2   Rate "R" Schedule, and in the othcr case, the demand 3   b_11ing computations are based on ratchet provisions 4   cxisting in previously applicable schedules.     Page i 5    of the Exhibit is a summary page showing a comparison 6   of the computation b'ased on 90% demand ratchet shown 7    in Column (c) and the computation based upon the 8   former demand ratchet provisions shown in Column (d) 9   with the difference in resulting billing demands 10   shown on Line 1 under Column (e) and the dollar 11   difference shown on Line 2 in Column (e).     Pages 2 12   and 3 show the dollar computations and the billing 13   demand determinations,respectively,for the 90% ratchet 14   assumption. Pages 4 and 5 show the dollar computation 15   and the billing demand determination, respectively, 16   utilizing the former contract demand ratchet provisions.
17   The total amount of the increase is $64,844.
18 O Could the retroactive application of this ratchet 19   have any other adverse effect on Vermont Electric           _
20    Cooperative?
21 A Yes, definitely so.     Assume that the Vermont Yankee 22   Nuclear plant goco into commercial operation on
_
1013 090 .
                                                  .
 
                                                                            ,
    .
.
1       october 15, 1972 as contemplated by NEPEX as of 2       May 1, 1972. Vermont Electric Cooperative is 3       committed to purchase its 5,583 KN of Vermont Yankee 4       power from and af ter that date. When the Cooperative 5       starts taking its committed amount of power from 6       Vermont Yankee, this will reduce its required 7       capacity demand from CVES by the 5,583 131. Therefore, 8     it will be paying CVPS for the original amount of 9     unused ratcheted demand plus this additional 5,583 KN 10       demand v!hich is now excess to their needs. This is a 11       doubling up of cost on Vermont olectric Cooperative 12       which is unreasonable and uncalled for. CVPS, in
(
13       addition to collecting these sums from the Cooperative, 14       can now, through their access via VELCO and NEPEX, sell 15       this capacity to other utilities in New England. In 16       effect, CVPS is charging its customers for capacity 17       the customer can't use, and then selling this capacity 18       to others; thus collecting twice for the same item.
19       Incidentally, if commercial operation of Vermont 20     Yanhoe is further delayed until early 1973 and after 21     the Cooperative has established its new winter peak, 22     the above described circumstances will exist throughout
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1013 021
 
.- i' 1   the remainder of 1973.
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2 The 90% ratchet is very punitive in this case 3   and is out of place.
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Revision as of 15:12, 19 October 2019

Testimony in Response to Tx Utils Generating Co & Houston Lighting & Power First Set of Interrogatories
ML19208C312
Person / Time
Site: South Texas, Comanche Peak  Luminant icon.png
Issue date: 01/22/1977
From: Springs D
GEORGIA POWER CO.
To:
Shared Package
ML19208C305 List:
References
E-7685, NUDOCS 7909260027
Download: ML19208C312 (21)
v • d • e


Text

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                    .     . TESTIMONY OF DAVID A. SPRINGS                          ,

FPC DOCITT NO. E-7685 

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1 Q. Please state your name and place of residence. 

              .2  A   David A. Springs, 4514 North Peachtree Road, Chamblee, 3     Georgia.

4 Q Would you state your educational background, please. 

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5 A I was graduated from GeorgiP. Institute of Technology 6 in 1948 with a Bachelor of Electrical Engineering Degree, 7 and again in 1949 with a Degree of Master of Science in 8 Electrical Engineering. 9 Q Would you state briefly your experience. I 10 A During graduate work at Georgia Tech, I had the unique s 11 experienge of working 15 ' months as Assistant Operator 12 of the Georgia Tech AC Network Calculator. At that 13 time, the calculator was the most advanced tool for 14 studying the overall operations of power systems. This 

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15 experience gave me a very early understanding of load 16 flow and stability problems on large utility systems. 17 Af ter graduation, I worked for Southern Engineering 18 Company in Atlanta, Georgia, for approximately three 19 years doing distribution design work, transmission 20 system design, and long-range power supply planning. b..- 21 From 1952 to 1963, I was with the South Carolina 22 Public Service Authority, first as Supervisor in Charge 

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7 000= G WO27 

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1013 002 

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1 of Wholesale Billing, and then for a period of six 2 years aa their Planning Engineer. 3 Since returning to Southern Engineering Company 4 of Georgia in 1963, I have been in charge of the Power 

          'S    Supply Planning and Power System Planning Section.

6 Q Are you a registered professional engineer? 7 A Yes, I am registered in the State of Georgia. 8 Q To what scholastic and professional societics do 

                                                                                .

9 you belong? 10 A I am a member of the IEEE and the Georgia Society of 1 11 Professional Engineers. I am also a member of Tau 

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12 B ta Pi (Scholastic Engineering) and the Eta Kappa Nu 13 (Scholastic Electrical) . - 14 0 nave you ever testified in other Federal Power 15 Commission cases? 16 A Yes. I have previously testified in the following 17 proceedings: Georgia Power Company, FPC Docket No. E-18 7548; Carolina Power and Light, FPC Docket No. E-7564; 19 Duke Power Company, FPC Docket No. E-7557'; and Missis-20 sippi Power Company, FPC Docket No. E-7625. I have 21 also submitted my direct testimony for the Florida 22 Power Corporation Case, FPC Docket No. E-7679. 

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A ooj 

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  • l Q Ly whom is your firm retained in this proceeding?

{ 2 A Vermont Electric Cooperative, Inc. 

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3 Q What was your assignment? 4 A My assignment in this proceeding was a limited one. 5 It was to determine the reasonableness of the 90% 

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6 " ratchet" provision contained in the Central Vermont 7 Public Service Corporation (CVPS) proposed Resale . 8 Service Rate "R" Schedule as to whether such a ratchet 

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9 can or should be based upon demand data occurring prior 10 to the effective date of the rate schedule containing t il the ratchet provision. 

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12 O What material and information did you review in carrying 

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13 out your assigniaent? 14 A The CVPS Monthly Operating Reports for the years 1970 15 and 1971, the FPC Form 1 and Form 12 Reports of CVPS 16 for the same years, CVPS's proposed Resale Service Rate 17 "R" Schedule, CVPS 's Statement "M" filing, and testimony 18 filed by various witnesses in this proceeding, cach in 19 Part as they relate specifically to my assignment. 20 O Would you first explain what is neant by a " demand 21 ratchet provision". 22 A It is a rate-making device which may be used in the 

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design of an electric power rate schedule, when { l 2 appropriate, to cause either the pricing elements in 3 the rate schedule to reflect the cost elements being 4 priced, to levelize the revenues from demand charges 5 over a period of time (usually one year) or to encourage 6 improvement in load factor. Essentially, the ratchet 7 sets the minimum billing demand charge in any month 8 relative to the maximum peak demand required by the 

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9 customer during a preceding period of time. 10 Stated in its simplest form, it may be said that 1 11 a rate schedule usually attempts to price two basic 12 ebements: the demand element and the associated energy 13 element. The demand element is a measure of capacity 14 or capability of delivering power and is usually 15 expressed in kilowatts (KW) or kilovolt-amperes (KVA). 16 The cecond element, the energy element, attempts to 17 put a price on the accumulated hour-by-hour use of the 18 demand or capacity element, and is usually expressed 19 in kilowatt-hours. In effect, the demand' element is 20 usually measured as the maximum rate of using energy 21 throughout the billing period which is usually one month. 22 It is simply the maximum kilowatt-hours taken per hour IOl u!y, , 

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1 and therefore expressed in kilowatts. 2 Since the first element, or the demand element, 3 determines the capacity that must be built into the 4 facilities provided by the utility for a service, 

            5  this is the element the utility would use in attempting 6  to recover its costs which are fixed in nature and do 7  not vary with the amount of energy actually delivered.

8 These costs are primarily those costs associated with 

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9 investment plus certain operating cos'ts which tend to 10 be fixed. All other costs,which would tend to vary with t il the amount of energy produced and sold,would be recovered 

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12 by the utility through the energy or KWH pricing element. 13 It is the im element, or 'the element associated with 14 fixed costs, in which the demand ratchet provision would 15 come into play if found necessary in a rate schedule to 16 Properly recc.er fixed costs for the utility.or if found 17 desirable to levelize revenues. 18 The demand ratchet provision usually states simply 19 that, in the determination of billing demand for any 20 billing month, the billing demand shall not be less 21 than a certain percentage of the maximum demand established during the previous year. This, in effect, 22 1013 006 

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1 allows for the pricing of fixed cost elements to ( 2 continue at the necessary or desired level even though 3 the use by the customer >r group of customers might 4 drop below the " minimum billing domand" established 5 by the ratcl.et. 6 Q How do you determine whether a given demand ratchet 7 is necessary to recover fixed costs of the utility? 8 A Stated very basically, the necessity of a demand 

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9 ratchet provision in the rate schedules of a utility 10 usually develops when, throughout the annual cycle of 

       '11     operation of the utility's facilities, there is gener-
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( 12 ating or transmitting capacity which sits idle seasonally 

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13 and is otherwise unsold and not necessary or usable as 14 needed reserve capacity. If there is no such capacity 

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15 standing for periods of time unused on a utility system, 16 there is no necessity for that utility to incorporate 17 demand ratchet provisions in its 2. ate schedule. With 18 this simple test as a measure of the need for demand 19 ratchet provisions in rate schedules, there are at least 20 five conditions or circumstances on the utility's system 21 which should be considered and taken into account in 22 determining whether a ratchet provision is necessary j j 

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1 to recover fixed costs and, if so, at what level the 2 ratchet should be set: 

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3 (1) seasonally varying fixed costs. If a utility 4 has a seasonally varying fixed cost pattern, 5 which is similar to its seasonal load pattern, 6 the utility would not have fixed costs in the 7 off-Peak season to be recovered through a 8 ratchet provision. 

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9 (2) Diversity between seasonal load natterns of 10 customers or classes of customers. To the 1 11 extent that customers or classes of customers 

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12 tend to use their maximum demands during different 13 seasons of the year', there would be a certain 34 amount of installed capacity and related fixed 15 costs that would be put to double use and there-16 f re would not be standing idle seasonally. 17 (3) Maintenance and other reserve canacity requirements. 18 To the extent that capacity which is normally sold 19 to customers during peak requirement' periods 26 seasonally is used in the off-season for main-21 tenanta purposes (in other words, used in the 22 P l ace of facilities that are then being maintained) , 

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101~3 008 1 1

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1 there is a certain amount of capacity that is there-2 by not standing idle seasonally. Incidentally, 3 some utilities are actually " maintenance 4 saturated" whereby they are maintaining generating 5 equipment over their annual peak because they do 6 not have enough capacity in their seasonally off-7 peak periods to carry out their maintenance program. 8 (4) The ability to exchance capacity seasonally with 

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9 other utilities. If a utility is located within 10 practical transmission distance of other utilities 

  'll              which have seasonally different load    atterns,
               .c 12              there is a resulting capability for exchanging 13              capacity seasonally with such utilities. This 14              not only tends to reduce the utility's investment 15              in generating facilities, but it also makes good 16              use of some of the off-season capacity which might 17              otherwise be standing idle.

18 (5) Having the ability to buy and the market to sell 19 capacity and/or energy on an " emergency" basis. 20 A utility which has interconnections and arrange-21 ments v/hich give it sources to purchase "emeigency" 22 capacity and/or energy and the market to nell U 3tpt

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1013 009 

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1 " emergency" capacity and/or energy is accordingly 2 able to reduce reserve capaci ty requirements and 3 to obtain some revenue from seasonally off-peak 4 capacity which may ot'erwise stand idle. 5 Q. Have you analyzed CVPS's proposed 90% demand ratchet 

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6 to determine vihether it is necessary to recover CVPS's 7 fixed costs? 8 A. Taking each of the five conditions which I have just 

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9 described which tend to measure the necessity for a 10 ratchet provision to recover fixed costs, I found the i following: ll 12 () Since the overall determination of the need for a . 13 ratchet provision in a rate schedule is a cumulative 14 thing, the most prominant circumstance or condition 15 affecting it should be considered first. In the case 16 of the CVPS systcm in this filing, by far the most 17 Pronounced circumstance which tends to affect this 18 consideration is the fact that the fixed costs on the 19 CVPS system varios considerably on a monthly basis. 20 In those months of the year when the CVPS load is 21 highest, its fixed costs tend to be highest; and in 22 those months when the CVPS load is lowest, their fixed _ 9_ 1013 010- 

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1 costs tend to be lowest. My Exhibit (DAS-1), , 2 entitled " Monthly Comparison of Total Available 3 Generation with Monthly Peak Loads for the Years 1970 4 and 1971", shows a bar graph by months of the total "5 generation capability and the monthly peak load of 6 the CVPS system for eacia month of both the Test Year 7 1970 and the year 1971. It will be noted that the 8 graphs show that the total generation capability 

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9 available to CVPS varies considerably thr3ughout the 10 year and also to a considerable extent follows the 

        'll         Pattern of the monthly peak load. This is a result
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 ,       12         of the fact that CVPS purchases a very large pei entage

( 13 of its total generation capability. For instanc2, in 14 December, 1970, it purchased approximately 73%, and 15 in June, 1970, it purchased approximately 60%. In 16 other words, in December of 1970, CVPS purchased 247 17 megawatts out of a total generation capability of 338 18 megawatts, and in June, 1970, CVPS purchased 141 19 megawatts out of a total generation capab'ility of 232 20 megawatts. Quite a large percentage of these purchases 21 are either short-term purchases or allow for wasonal 22 variations which result in the pattern shown in 

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                      ...                                        1013 011 Jl.L s      e

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. ( 1 Exhibit (DAS-1). 2 O What is the source of CVPS 's purchased power? 3 A Theu: re many and varied sources throughout New England . 4 plus the Pcaer Authority of the State of New York plus 5 the New Brunswick system in Canada. A list of the 6 sources and a tabulation ot the amounts of the purchases 7 by months is shown on Witness Chayavadhanangkur's 8 Exhibit (JC-1) , pages 3 and 4. 9 O How is it possible that CVPS is able to tap such wide 10 and varied sources for purchased power? 11 A CV S obtains power over the interconnected transmission systems of New England and New York into the State of ( 12 

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13 Vermont and then over the VELCO system into CVPS, under 14 many varied contractual arrangements. 15 Q How is Central Vermont able to pattern its seasonal 16 purchases generally in accordance with its seasonal 17 needs? 18 A It is in prrt due to the coordinated planning of the 19 utilities in the entire area as to the scheduling of 20 new generation. It is also due in part to the fact 21 that the interconnected systems of New England and 22 New York are able to exchange capacity seasonally 

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1 during the winter peaking months of upper New England ( 2 and the summer peaking months of New York City up into 3 Massachusetts. This is being done under a number of 4 varied contractual arrangements which I am personally 5 not fmmiliar wiVa, but the effect of it does reach up 6 into Vermont. A good e'xample of this is the contract 7 which CVPS has with the Boston Edison system (actually 8 purchased and brought into tl a State by tne VEICO 

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9 sys tem) which provides for the following seasonally . 10 varying capacity purchases: 1 11 July 1, 1970 to September 30, 1970 44,476 Kilowatts 12 October 1, 1970 to May 31, 1971 127,497 Kilowatts ( 13 June 1, 1971 to Septembar 30, 1971 8,903 Kilowatts 14 October 1, 1971 to May 31, 1972 44,605 Kilowatts 15 June 1, 1972 to September 30, 1972 8,903 Kilowatts 16 October 1, 1972 to May 31, 1973 44,605 Kilowatts 17 June 1, 1973 to September 30, 1973 8,903 Kilowatts 18 October 1, 1973 to May 31, 1974 44,605 Kilowatts 19 June 1, 1974 to September 30, 1974 8,903 Kilowatts 20 October 1, 1974 to May 31, 1975 118,602 Kilowatts 21 June 1, 1975 to September 30, 1975 44,605 Kilowatts 22 The varying seasonal availability is obvious. 

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( l Q What do you conclude from this? 2 A I conclude that CVPS through the purchasing agreements 3 it han .sith other utilities has been able successfully 4 to fairly closely match its total available generation 

        S         capacity to its n.onthly peak load. There are occasional 6

excesses above needs to' meet loads from time to time, 

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but the amount of excess has no consistent relationship 7 8 with previous system peaks. The monthly pattern itsel. 

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9 is not even consistent, as would be indicated by comparing 10 Sheets 1 and 2 of the Exhibit (DAS-1). This i certainly shows that a demand ratchet based upon the ll ( 12 P evious peak demand has very little place in the cost 13 patterns of CVPS. Incidentally, this shows very strongly 14 that the 12-month average coincidant demand method of 15 allocating fixed costs is the proper method.. 16 Q Please continue with your analysis of CVPS's ratchet as 17 to each of your five criteria. 18 A Continuing with the second condition: 19 (2) A cursory review of delivery point m'etering data 20 within the wholesale for resale customer class indicates 21 there would be come but not a great deal of seasonal 

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22 diversity between the delivery points. I did not have 

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1 the time to make a detailed study here, but this ( 2 would be somewhere between 5;? and 10%. This would 3 tend to say that there is a doubling up on the sale 4 of capacity seasonally within the wholesale for resale 5 class, which would tend to reduce the need for a demand 6 ratchet by approximately 5% to 10%. 7 (3) The need for seasonally off-peak capacity to meet 8 scheduled maintenance is not obvious on the CVPS system. 

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9 This is duc, of course, to the fact that the CVPS 10 system has only a small amount of generating capacity 

      'll            in its system. However, the same effect comes into
                     .c 12            P lay with the " unit purchases" of CVPS from the outside
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13 which are not otherwise firmed. In effect, when these 14 unit purchases are from generating units which aro down 15 for maintenance purposes, they must be replaced by 16 CVPS with other capacity. Since it is normal for such 17 units to be scheduled for maintenance in the months of 18 the year when the area loads are lowest, in effect 19 these maintenance reserve kilowatts would have a 20 tendency to be used for this purpose and otherwise 21 not stand idle in the off-peak months on the CVPS 22 system. ( . Ii 'fbr i: ti LaUl 

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r' 1 (4) In my test of CVPS 's ability to exchange capacity 2 seasonally with other utilities, this is definitely 3 an effective consideration. However, it has been 4 accomplished in a round-about way to a considerable 5 extent through the seasonal purchases discussed under 

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6 Paragraph (1) above. 7 (5) A cursory review of the Operating Reports of CVPS 8 indicates that, in the month-to-month operation of its 

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9 system, it is able to sell considerable quantities of 10 capacity and energy either as emergency power or other-t wise. This would definitely have a tendency to make il 

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,      1;      t least partial use of seasonally available capacity
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13 v/nich would otherwise stand idle. 14 Q What conclusions have you reached from this analysis? 

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15 A M st of the conditions or circumstances discussed in 16 Paragraphs (1) through (5) above would tend to 

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17 indicate that a ratchet provision is not necessary to 18 recover CVPS's fixed costs and probably not even 19 desirable in the Resale Service Rate "R"' Schedule. 20 Taken together, they definitely show that a 90% demand 21 ratchet provision is much too stringent and is out of 22 place in this filing as a dev2cc to recover fixed costs. 

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1013 O!6 

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e Since the 90% demand ratchet is not necessary to ( l 2 recover CVPS's fixed costs, it would appear that it 3 has been included in the rate schedule as a devict 4 to levelize revenues from the demand component a" 

     5        the rate schedule over the summer and winter se sons.
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6 Q IIave you analyzed CVPS 's 90% demand ratchet to determine 7 whether it is appropriate in this instance as a device 8 to levelize revenues? 

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9 A Yes. In some instances on a utility system, there is 10 consistent similarity in the seasonal load patterns of the customers in a given class. In this case, if all 

   'll uch customers have the same seasonal load patterns,

( 12 

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13 no customer is advantaged or disadvantaged with respect to the others in the class by the application of a 14 15 ratchet or the non-application of a ratchet. In such 16 cases, then, a ratchet may be used as an incentive to 17 improve load factor, or it may be applied in order to 18 levelize annual revenue. In this instance there is no 19 evidence that the primary purpose of CVPS 's ratchet is as 20 an incentive to improve load factor. As I indicated 21 above, the purpose of the 90% ratchet provision in the 

    -22         proposed resale Service Rate "R" Schedule appears to d[I, b$b                                              *
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16 - 1013 017 

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1 be to 2av31ize revenues. TIowever, an analysis of 2 the seasonal load patterns of purchases by different 3 wholesale for resale customers to be served under 4 Rate "R" Schedule shows that the summer to winter 5 peak comparisons among these customers varies quite 6 widely, which will cause certain of them to be 7 unfairly disadvantaged by the application of a 8 ratcher for revenue levelizing purposes. 

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9 Q What is the effect of CVPS 's 90% demand ratchet as 10 applied beginning June 28, 1972, based upon demands 1 11 occurring during the winter 1971-1972? 

              .v 12   A Since the demand ratchet is not in this case a device 13      to recover actual fixed ' costs, but is instead a device 14      to levelize revenues, the effect is to spread a portion 15        f revenue related to CVPS's winter 1971-1972 sales over 16      to the summer 1972 period but at increased rates. In 17      other words, Vermont Electric Cooperative is paying 18      again, at increased rates, for services it received 19      from CVPS and paid for at then existing rates during 20      the 1971-1972 winter period.

21 O fir. Springs, I hand you Exhibit (DAS-2) consisting 22 of six pages, and entitled " Vermont Electric Cooperative, "' 

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_ 1, _ 1013 018 

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1 Inc. Computation of Demand Charge Difference for 2 1972 Appl.ying Former Contract Ratchet Provisions, 3 versr.s 90% Ratchet, both Af ter June 28, 1972." 4 was this Exhibit prepared under your direct supervision? 5 A Yes, it was. 

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6 Q Would you describe the Exhibit, please. 7 A This Exhibit was prepared at the request of the 8 Cooperative, to show the very severe effect of the 

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9 application of a 90% demand ratchet during the year 10 1972; if made effective along with Resale Service Rate 

      'll       "R" Schedule on June 28, 1972; and is based on previous

( 12 'heakdemandsregisteredinthewintermonthsprior to 13 the effective date of Ph'e new rate schedu._e. The 14 computations are presented in tabular form and are 15 based on actual billing data for the early part of 16 the year and estimated billing data through December, 17 1972. The computations are sin.ilar in overy way 18 except for the ratchet provisions assumed. In both 19 computations, the rates and charges of tlie proposed 20 Resale Service Rate "R" Schedule are assumed to be 21 in effect for the months of Ju.ly through December; 22 but in one case the demand billing computations are 

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1 based upon the 90% demand ratchet of Resale Service 2 Rate "R" Schedule, and in the othcr case, the demand 3 b_11ing computations are based on ratchet provisions 4 cxisting in previously applicable schedules. Page i 5 of the Exhibit is a summary page showing a comparison 6 of the computation b'ased on 90% demand ratchet shown 7 in Column (c) and the computation based upon the 8 former demand ratchet provisions shown in Column (d) 9 with the difference in resulting billing demands 10 shown on Line 1 under Column (e) and the dollar 11 difference shown on Line 2 in Column (e). Pages 2 12 and 3 show the dollar computations and the billing 13 demand determinations,respectively,for the 90% ratchet 14 assumption. Pages 4 and 5 show the dollar computation 15 and the billing demand determination, respectively, 16 utilizing the former contract demand ratchet provisions. 17 The total amount of the increase is $64,844. 18 O Could the retroactive application of this ratchet 19 have any other adverse effect on Vermont Electric _ 20 Cooperative? 21 A Yes, definitely so. Assume that the Vermont Yankee 22 Nuclear plant goco into commercial operation on _ 1013 090 . 

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. 1 october 15, 1972 as contemplated by NEPEX as of 2 May 1, 1972. Vermont Electric Cooperative is 3 committed to purchase its 5,583 KN of Vermont Yankee 4 power from and af ter that date. When the Cooperative 5 starts taking its committed amount of power from 6 Vermont Yankee, this will reduce its required 7 capacity demand from CVES by the 5,583 131. Therefore, 8 it will be paying CVPS for the original amount of 9 unused ratcheted demand plus this additional 5,583 KN 10 demand v!hich is now excess to their needs. This is a 11 doubling up of cost on Vermont olectric Cooperative 12 which is unreasonable and uncalled for. CVPS, in ( 13 addition to collecting these sums from the Cooperative, 14 can now, through their access via VELCO and NEPEX, sell 15 this capacity to other utilities in New England. In 16 effect, CVPS is charging its customers for capacity 17 the customer can't use, and then selling this capacity 18 to others; thus collecting twice for the same item. 19 Incidentally, if commercial operation of Vermont 20 Yanhoe is further delayed until early 1973 and after 21 the Cooperative has established its new winter peak, 22 the above described circumstances will exist throughout 

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.- i' 1 the remainder of 1973. ( 2 The 90% ratchet is very punitive in this case 3 and is out of place. 4 5 6 

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