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CASENO8707IISTAFDIRECTTESTDLV&AW
November 20, 1996
Daniel P. Gahagan
Executive Secretary
Public Service Commission
of Maryland
6 St. Paul Street
Baltimore, Maryland 21202-6806
Re:
Case No. 8707, Phase II
Dear Mr. Gahagan:
Enclosed for filing in Case No. 8707, Phase II, are the
original and two (2) copies of the Direct Testimony of David L.
Valcarenghi and Aurora Watson of the Public Service Commission
Staff.
Copies of Staff's Direct Testimony have been provided to the
Hearing Examiner conducting this proceeding and to all parties of
record.
Very truly yours,
James R. Scheltema
Assistant Staff Counsel
JRS/rt
Enclosures
cc:
Teresa M. Bay, Hearing Examiner
All Parties of Record
BEFORE THE
PUBLIC SERVICE COMMISSION OF MARYLAND
IN THE MATTER OF THE APPLICATION OF
CHESAPEAKE UTILITIES CORPORATION
FOR AUTHORITY TO REVISE ITS RATES
AND CHARGES FOR GAS SERVICE
)
)
)
)
CASE NO. 8707
PHASE II
DIRECT TESTIMONY
OF
AURORA D. WATSON
ON BEHALF OF THE STAFF
OF THE
PUBLIC SERVICE COMMISSION OF MARYLAND
NOVEMBER 20, 1996
TABLE OF CONTENTS
I.
INTRODUCTION AND SUMMARY
1
II.
NEW RATE CLASSES
4
III.
CUSTOMER CLASS COST ALLOCATION
4
IV.
RATE IMPACTS
15
V.
NEGOTIATED CONTRACT RATES
16
VI.
SHARING OF INTERRUPTIBLE AND CAPACITY
RELEASE MARGINS
18
VII.
TARIFF MODIFICATIONS
19
VIII.
RATE DESIGN
20
IX.
CONCLUSION
21
CASE NO. 8707
DIRECT TESTIMONY OF AURORA D. WATSON
ON BEHALF OF
THE PUBLIC SERVICE COMMISSION STAFF
I.
Introduction and Summary
Q.
Please state your name, occupation and business address.
A.
My name is Aurora D. Watson. I am a regulatory economist with the
Maryland Public Service Commission in the Division of Rate Research and
Economics. My business address is 6 St. Paul Street, Baltimore, Maryland
21202.
Q.
Please describe your professional background.
A.
From 1979 to 1991, I was employed by the Federal Energy Regulatory
Commission as a public utilities specialist. I conducted various investigations
involving natural gas producers and pipeline companies and testified in rate
proceedings, particularly in the area of cost classification, cost allocation and rate
design.
In 1991, I joined WestGas, the former gas subsidiary of Public Service
Company of Colorado, as a financial analyst. In this capacity, I was responsible
for all tariff matters including regulatory filings with the State of Colorado and the
FERC. I also prepared regulatory impact analyses for the company during the
transition into an Order 636 era.
4
In 1993, I was employed by the Colorado Public Utilities Commission as a
financial analyst to conduct investigations of various state regulated utilities and
brief the Commission on my conclusions. I joined the Maryland Public Service
Commission Staff in April 1996.
Q.
What is your educational background?
A.
I have a Bachelor of Science degree in Chemistry from the American
University in Washington, D.C. I have received supplementary
training/education from the FERC, NARUC, AGA, FEBA (Federal Energy Bar
Association), RMNGA (Rocky Mountain Natural Gas Association), the USEPA
and graduate course work at the American University, the Colorado School of
Mines and the University of Denver.
Q.
What is the purpose of your testimony today?
A.
I am submitting testimony today to address certain cost allocation and
tariff issues. I will discuss: 1) the classification and allocation of costs
associated with distribution facilities, 2) margin-sharing, 3) negotiated contract
rates for firm service, 4) Chesapeake's proposed new rate classes, 5) the need
to use a gradual approach to phase in rate increases on customer classes, and
6) rate design.
Q.
What are your conclusions and recommendations?
A.
My conclusions are as follows:
(1)
Chesapeake's proposed rate class segmentation reflects certain
characteristics of the respective customer groups such as size and usage
patterns;
5
(2)
The classification and allocation of costs for distribution mains
needs to be reconfigured. An allocation of mains to demand and commodity is
appropriate;
(3)
Chesapeake's use of the minimum system (MIN) approach to cost
allocation is inappropriate because the data used can be easily manipulated to
arrive at allocation factors ranging from 16% to more than 100% of the actual
investment in mains;
(4)
The classification and allocation of costs for services needs to be
reconfigured. Services are largely customer-related and should therefore be
allocated on the number of customers;
(5)
The ratio for margin sharing related to interruptible service and
capacity release should remain at 90/10 (ratepayers/company);
(6)
The NCR tariff offering negotiated contract rates for firm service is
inappropriate prior to unbundling. Negotiated contracts should continue to be
considered by the Commission individually in the form of special contracts -- not
through a blanket authorization; and
(7)
The rate design used by Chesapeake in this case should be
approved.
II.
New Rate Classes
Q.
Please comment on Chesapeake's proposals to establish new rate
classes.
6
A.
To design rates, it is first necessary to separate the company's customers
into rate classes. The rate class segmentation is dependent upon the
characteristics of the customers and the company's ratemaking goals. Examples
of ratemaking goals include economic efficiency, fairness, competitiveness and
reflection of cost incurrence. In this proceeding, Chesapeake proposes to
redefine its rate classes according to certain characteristics, principal among
which is customer size.
Q.
Are you opposed to Chesapeake's proposed class segmentation?
A.
No. It appears that Chesapeake has redefined its rate classes in
accordance with the characteristics of its customer population including size,
customer type, load factor and alternate fuel capability.
III.
Customer Class Cost Allocation
Q.
Would you please describe the processes of cost classification, cost
allocation, and rate design?
A.
First, overall costs are functionalized into categories such as production,
storage, and transmission or distribution. Next, these functionalized costs are
classified as demand or capacity-related, commodity or energy-related, and
customer-related for the purpose of cost allocation and rate design. Demand or
capacity-related costs are associated with the peak usage of a system and do
not vary directly with the number of customers or their annual usage.
Commodity costs are those that vary in proportion to a customer's volumetric
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consumption. Customer costs are those that vary directly with the number of
customers served.
It is important to note that there is no one scientifically correct method of
cost allocation. The process by which just and reasonable rates are produced is
generally more judgment than math. The allocation methodology provides the
cost of service for each customer class. The goal of cost allocation is well
described in the following quote:
The steps which comprise the cost classification and allocation
process are designed to identify the nature, characteristics and
behavior of system costs, and to identify the classes of service or
customers that are deemed responsible for the incurrence of such
system costs.
[AGA Gas Rate Fundamentals, 3rd Ed.(1978) p.235]
Costs are thus allocated to the customer classes using factors, such as units of
service, that reflect the identifying characteristics of cost incurrence.
Rate design is a creative process that translates these allocated costs into
unit charges in a manner that is judged to achieve certain ratemaking goals while
recovering the required revenue from each customer class. Defining customer
class must therefore precede the rate design process.
8
Q.
What cost classification and cost allocation issues do you wish to
address specifically?
A.
I wish to address the treatment of distribution mains and services for the
purposes of cost classification and cost allocation.
Q.
How does Chesapeake treat distribution mains and services for
purposes of cost classification and cost allocation?
A.
Chesapeake assigns the fixed costs of mains and services to demand-
related and customer-related classifications using a minimum distribution system
methodology. As described by Mr. Johnson (at lines 23-24 on page 5 of his
direct testimony), the allocation employed for the customer-related portion of
mains and services is "based on the number of customers in each class of
service rather than the maximum demand imposed during the peak day by each
class."
Q.
Please describe the minimum distribution system concept.
A.
As the NARUC Gas Distribution Rate Design Manual (June 1989) states
at page 22:
The minimum size main theory assumes that there is a minimum
size main necessary to connect the customer to the system and
thus affords the customer an opportunity to take service if he so
desires. Under the minimum size main theory, all distribution
mains are priced out at the historic unit cost of the smallest main
installed in the system, and assigned as customer costs. The
remaining book cost of distribution mains is assigned to demand.
9
Q.
Is this the procedure used by Chesapeake's witness Johnson?
A.
No. Chesapeake uses its own variant of the approach described above.
First, Mr. Johnson performs his analysis using an "inflated" unit cost to determine
the customer-related costs of a minimum system. An inflation factor is applied to
express costs of different vintage pipes in today's dollars. Second, Mr. Johnson
performs his analysis on the basis of 1 1/4 inch pipe -- not the smallest main
installed in the system. Third, Mr. Johnson develops a "trended installed cost"
ratio (comparing the 1 1/4" pipe to the average for all distribution main) to derive
the percentage of distribution main being classified as customer-related.
Q.
Please describe Mr. Johnson's application of the MIN methodology
to Chesapeake's distribution system.
A.
According to Mr. Johnson's testimony at line 5, page 6, the minimum
system for mains was based on a 1 1/4" steel main. He states that "this main
was selected because it is the smallest size main shown on the company's
records as having significant installed footage." (Page 6, lines 6-7). According
to Mr. Johnson, the cost of the 1 1/4" main is 41.80% per foot of the average
cost per foot for all distribution mains. Mr. Johnson concludes therefore that
41.80% of the distribution main costs should be classified as customer-related.
(Page 6, lines 9-10).
Q.
Do you agree with Mr. Johnson's use of the minimum distribution
system methodology for the allocation of mains and services to demandrelated and customer-related classifications?
10
A.
No, I do not. According to Mr. Johnson's direct testimony (page 5, lines
18-24), the minimum distribution system methodology recognizes "that there is
conceptually, a minimum size system of distribution mains and services in order
to connect each customer to the transmission system or source of supply which
is required regardless of the volume of gas required by that customer." He
further states that this minimum system "is a function of the expanse of the
service territory and concentration of customers" and should therefore be
allocated on the basis of "the number of customers in each class of service,
rather than the maximum demand imposed during the peak day by each class."
I question Mr. Johnson's supposition that his minimum size methodology
reflects the concentration or density of customers. To quote Bonbright:
It [the minimum-sized distribution system] makes no allowance for
the density factor (customers per linear mile or per square mile).
Indeed, if the Company's entire service area stays fixed, an
increase in number of customers does not necessarily betoken any
increase whatever in the costs of a minimum-sized distribution
system.
(James C. Bonbright, Principles of Public Utility Rates, 84n.3(1961)
p. 348)
I do not believe that a customer-related classification clearly reflects the
cost causation of distribution mains. While the minimum system methodology is
an approach which has been used in Maryland and elsewhere, it is a
controversial and imperfect approach. It is imperfect because no real distribution
system would be built with only 1 1/4” mains, or any other minimum size of pipe.
In addition, the number of customers bears a weak relationship to costs of
mains. A distribution system is sized to carry the system’s peak load. A better
approach would employ a noncoincident peak (NCP) allocator which would more
11
accurately reflect that costs are incurred to meet the peak load of all customer
classes using the system. However, even if the minimum system were deemed
to be the appropriate method in this case, the data employed to derive
Chesapeake’s minimum system is problematic and, as I will show, unreliable on
its face. For this reason alone, Chesapeake’s application of the minimum
system methodology must be rejected.
Q.
A.
What is the effect of Chesapeake's methodology?
In my opinion, the use of the minimum distribution system over allocates
cost to residential and small commercial customers who comprise 96.77% of
Chesapeake's customers. (See Exhibit JRT-2). This 96.77% is made up of
7,965 residential (of which 1,731 are non-heat) and 1,053 general service
customers. Under the MIN methodology, large volume and industrial customers
receive a smaller allocation of costs.
Schedule 1.1 of Exhibit RSJ-2 -- "Allocation", shows the shifting of cost
responsibility away from the Medium Volume, Large Volume, High Load Factor
and contract Demand customers that would result from allocating more costs on
the basis of number of customers. While these customer classes combined
comprise 31.26% of the design-day demand or peak load, they comprise only
2.60% of the total number of customers.
Q.
What allocation methods have been ordered in other Maryland
cases?
A.
In Case No. 8119, involving Washington Gas Light, the Company
demonstrated an "almost exact correlation" between the number of customers
12
and the length of the distribution mains. Based on this showing, the
Commission deemed it appropriate to recognize the correlation by classifying a
portion of the costs of distribution mains as customer costs and allocating that
portion on a number of customers basis.
In Case No. 8070, involving Baltimore Gas and Electric Company, the
non-coincident peak (NCP) method was accepted and the minimum size
method was rejected. The NCP method was recognized as reflecting the actual
design and operation of the distribution mains system, and further, that mains
must be capable of delivering the maximum amount demanded whether or not
that demand is coincident with the system peak demand. The minimum size
method was rejected for its “many deficiencies.”
Q.
Do you agree with Mr. Johnson's use of the 1 1/4" pipe as the basis
for his minimum system?
A.
There are a variety of sizes that could be chosen as the basis of a
minimum system. The choice to use the 1 1/4" steel main is at best a judgment
call. With Chesapeake’s proposed MIN methodology, much depends on how
"significant installed footage" is defined. Chesapeake's Response to Maryland
People's Counsel Data Request No. 25 [Exhibit ADW-1] shows the pipe mix
Chesapeake uses in serving its customers. While the 1 1/4” steel main
comprises 12,212 feet of the system, there is 12,244 feet of 1 1/2” steel main
which would appear to meet the company's criterion. If 12,244 feet of 1 1/2” pipe
is considered significant, then basing the minimum system on 1 1/2" main at an
inflated unit cost of $1.92 per foot (versus the inflated unit cost of $5.07 per foot
13
for the 1 1/4" main) would reduce the amount of costs assigned by Chesapeake
as customer-related by more than one million dollars.
Q.
Have you provided an exhibit to show how Chesapeake's data
produces unpredictable and unreliable results?
A.
Yes, I have. Exhibit No. ADW-2, shows the results of my analysis. In this
analysis I mirrored Mr. Johnson's MIN methodology by using the inflated unit
cost of the pipe, but substituted various other pipes represented in Exhibit
ADW-1. Using 3/4" steel pipe, the inflated unit cost is $9.53/foot giving a system
investment of $10,141,854, which is 78.6% of the total to be assigned as
customer-related. If 2" steel pipe is used, the inflated unit cost is $9.95/foot,
yielding a ratio which would assign 82.1% as customer-related costs.
It is important to note that, as Exhibit ADW-2 shows, the inflated unit cost
of 3/4" steel pipe is $9.53/ft. while the 1 1/2" steel pipe is only $1.92/ft., implying
that the smaller diameter pipe costs nearly 5 times more than the larger diameter
pipe. Further, the 1 1/4" plastic pipe is shown to cost $17.82/ft. as compared to
the 2" plastic pipe at a cost of $8.18/ft., or more than twice as much. If the 1 1/2"
steel pipe were employed to arrive at a minimum system using Mr. Johnson’s
methodology, it would result in 15.84% as customer-related costs. Using the
1 1/4" plastic pipe would result in 147% as customer-related costs. It appears
that Mr. Johnson sized his minimum system so that it would yield what he
believed to be a "reasonable result". Clearly, a methodology which relies on
such problematic data is suspect and should be rejected.
Q.
What methodology would you prefer?
14
A.
As I said earlier, a more appropriate allocator for mains would be the
noncoincident peak (NCP). Ideally, I would recommend a result similar to the
Commission's decision in Case No. 8070 which rejected the MIN methodology
because of its deficiencies in favor of the noncoincident peak methodology.
Distribution mains are used to provide gas service for different classes of
customers. The costs of these mains are common costs to all customers. It is
therefore appropriate to look at how the costs are incurred and how the facilities
are used.
The NCP approach gives a better match of cost with cost responsibility
than the problematic MIN system because it recognizes that mains were
originally installed and sized to meet NCP's, and that all gas used at the time of
NCP contributes to that peak. Therefore, the benefits that customers derive from
a functioning distribution system are more related to NCP than to a minimum
system. NCP replicates how the system is actually used. It accepts peak as an
allocation method -- the system will be allocated on peak demand. However, the
allocation used will be the peaks for each customer class whenever that peak is
(which may or may not be coincident to other customer class peaks). The NCP
method ensures that even the non-heating customers are assigned their fair
share based on their noncoincident peak usage.
Q.
Are you recommending an NCP allocation methodology for the
Company?
15
A.
No, I am not. Unfortunately, the required NCP data is not available for
Chesapeake’s customers and I do not think the time and expense that would be
needed to obtain customer class noncoincident peaks is warranted.
Q.
Do you have an alternative method you wish to propose?
A.
Yes. As an alternative to NCP, I am recommending adoption of a 50/50
split of mains between demand and commodity. A proper allocation of
distribution mains should reflect the actual design and operation of the
distribution mains system. While a second best to the noncoincident peak
method, my proposed cost allocation methodology reflects usage at times other
than the coincident peak, as does the NCP allocator. Further, my methodology
reflects the fact that the system of mains is planned and justified upon both the
energy and peak requirements of customers.
The distribution mains are sized to meet anticipated peak loads. Yet
clearly, these same facilities are available to provide gas service to customers
year round, irrespective of peak demand. The system capacity is used both for
meeting peak demands and for providing service at times other than during peak
periods. To reflect both the annual deliveries and the peak usage for which the
facilities are built and used, I have allocated the costs of distribution mains on a
50% commodity and 50% demand basis. As a practical matter, this ensures
that mains costs are apportioned to customers classes whether their peak
demand falls in the coldest month or at some other time of the year.
Q.
What allocators did you use in your proposed methodology?
16
A.
For this allocation, I used Chesapeake's annual sales allocator and its
design day allocator, respectively. Half of the mains costs were assigned as
demand-related costs and allocated on the basis of Chesapeake's design day
demand. The remaining half were assigned as commodity and allocated on the
basis of annual sales deliveries.
Q.
Why did you choose a 50/50 allocation of costs to demand and
commodity?
A.
My methodology presents a balance between the pure peak and the pure
volumetric cost responsibility approaches. A pure peak responsibility method
would assign 100% of the fixed costs as demand or capacity-related costs and
allocate such costs among customer classes according to their non-coincident
peak demand. A pure volumetric approach would treat 100% of the fixed costs
as commodity or energy-related costs to be allocated among customer classes
on the basis of annual deliveries. (High load factor and non-weather sensitive
customer classes will bear a greater proportion of the costs on an annual basis
than on a peak basis.)
Q.
How did you treat services?
A.
With respect to services, I have assigned costs as being predominantly
customer-related and allocated them to classes based on the number of
customers. Services includes the investment made for the connection to the
customer, which is a service line cost. It is therefore recognized in the
assignment of services to the customer-related classification.
17
Q.
Your Exhibit ADW- 3, shows costs allocated by your recommended
methodology to the current customer classes. Please explain.
A.
My Exhibit ADW-3 is for illustrative purposes only. Staff did not have the
information necessary to provide an analysis using the proposed customer
classes. Because Staff accepts the new customer classes (with the exception
of NCR) as proposed, Chesapeake should apply my methodology to their
proposed new classes.
IV.
RATE IMPACTS
Q.
What concerns do you have with respect to the rate impact on
customers as a result of Chesapeake’s proposal?
A.
Chesapeake's cost of service studies demonstrate that certain gas
customer classes have been providing returns which are substantially greater
than the system average. (Exhibit TJS-1, Schedule 1.0, Page 1). Even as
modified for a more appropriate allocation of distribution mains and services,
Chesapeake's cost allocation produces class costs of service which differ
markedly from current revenue by customer class.
To equalize class rates of return, some significant changes in class
revenue requirements will be necessary. However, such a movement in class
revenue requirements should proceed gradually and moderately in order to
prevent or lessen any potential for rate shock. Thus, I believe that the change
in class revenue requirements should take place in two steps, half on the
effective date of the order in this case and the remaining half, one year from
18
that date. This would be practically achieved by using 1/2 the revenue
allocation results for increases and using 1/2 the revenue allocation results for
any decreases in the first year. The remaining increases and decreases from
the allocation results would then be applied in the second year.
V.
Negotiated Contract Rates
Q.
What is the proposed Rate Schedule "NCR"?
A.
Rate Schedule "NCR" is a negotiated contract rate service that
Chesapeake is proposing to offer on a voluntary basis. NCR service will be
available to any customer who has economically competitive alternatives to its
full or partial service requirements that "it is likely to select if the Company does
not provide a negotiated contract rate", and the price to the customer "will
provide net revenues above the incremental costs to provide" this NCR service.
The contract term for NCR service is fixed at one year or more. NCR service is a
firm service which Chesapeake believes will be elected by some of its large
customers.
Q.
Will the NCR rate schedule be open to all customers?
A.
No, it will not. According to a letter from Chesapeake's counsel dated
October 3, 1996, NCR service will only replace service from alternate fuels other
than gas service at this time. (Exhibit ADW- 4) This action is according to
agreement among the parties.
Q.
What is your recommendation with respect to Negotiated Contract
Rate Service?
19
A.
With respect to the gas sales part of Negotiated Contract Rate service,
clearly any negotiated gas sales needs to be addressed in the context of
unbundled services and the development of gas on gas competition.
Chesapeake should not be able to offer negotiated sales rates prior to
unbundling except to the extent that special contracts are currently allowed
subject to the consent of the Public Service Commission.
To the extent that the Company wishes to, it can bring individual contracts
to the Commission for approval. In order to protect customers from
discriminatory treatment, the Commission should retain the authority to approve
or reject individual special contract rates. This is especially true where the
Company may otherwise have an opportunity to bind customers with contracts,
and possibly shift costs to captive customers, in advance of competitors being
able to offer choices to them through unbundling tariffs (and the availability of
open access on the Eastern Shore supplying pipeline).
VI.
Sharing of Interruptible and Capacity Release Margins
Q.
What changes is Chesapeake proposing with respect to the sharing
of interruptible margins?
A.
Chesapeake is proposing to change the formula for sharing interruptible
margins from the current 90/10 to 80/20. Currently, firm customers are credited
90% of the interruptible margin through the PGA. On page 11, line 17 of his
direct testimony, Mr. Schuh asserts that "there is considerable risk associated
with achieving a particular level of interruptible margins. With open access
20
there will be competitive pressures to reduce margins." He argues therefore
that if the Company receives a higher percentage of the margin, the Company
will have greater incentive to "market its services aggressively and take steps to
attract customers". (Page 12, lines 1-2).
Q.
Do you agree?
A.
No, I do not. The 10% that the Company receives is essentially a sales
commission. The Company is acting on behalf of the firm customers to
maximize the return to firm customers. The return should be maximized for the
firm customer since it is the firm customer that is entirely at risk for the cost of
providing interruptible service. Columbia Maryland's margin sharing split is 92%
to firm customers, 8% to Columbia. (See p. 193 of 80 MDPSC, Order No.
68462, Case No. 8157, order issued June 9, 1989). Washington Gas Light
changed from a 90/10 sharing to 92/8 in Case No. 8191 (but 90/10 was retained
for their sales to PEPCO). There is no reason for Chesapeake to receive a
larger share of these margins. If anything, the trend of comparable sharing
arrangements in Maryland would indicate a change to 92/8. If interruptible sales
were to vanish completely, all else equal, the Company's earnings from a
ratemaking perspective would be unaffected, while firm customers would lose
the PGA credit.
Q.
Chesapeake is proposing an 80/20 margin sharing mechanism for
capacity release. Do you agree?
A.
No. Again, the Company is acting on behalf of the firm customers who
bear the cost of this capacity and the risk of under-utilization. (With respect to
21
the sharing mechanism for capacity release of other Maryland LDCs, WGL has
no incentive, BGE has 90/10 and CGMD has 90/10.)
VII.
Tariff Modifications
Q.
Are you proposing any modifications to Chesapeake’s new tariff
pages?
A.
Yes. I am proposing that language be added to the “Availability” section
of Rate Schedule “IS” to ensure that alternate fuel equipment has to be in
operating condition.
VIII.
Rate Design
Q.
Do you have any comments with respect to Chesapeake’s proposed
rate design?
A.
Yes. I support Chesapeake’s rate design in general. I believe the
declining block rates used by Chesapeake are still appropriate as they reflect
the difference in sub-class rates of return for the heating and non-heating
customers and the under-recovery of customer-related costs in the customer
charge. However, I would suggest that the Company's proposed customer
charge increase be incremental with one half imposed currently and the
remainder of the increase imposed in the following year.
22
IX.
CONCLUSION
Q.
Please summarize your recommendations.
A.
In conclusion, I am recommending: 1) that Chesapeake's proposed rate
class segmentation and rate design be accepted; 2) that the minimum system be
rejected as a methodology in this case in favor of a demand/commodity
treatment of mains and a customer-related treatment of services; 3) that the
ratios for margin sharing related to interruptible service and to capacity release
remain 90/10 (ratepayers/company); 4) that the changes in total revenue
requirement for each class and in the customer charge be phased in two steps;
and, 5) that the NCR rate schedule be rejected in favor of Commission review of
individual special contracts.
Q.
Does this conclude your testimony?
A.
Yes, it does.
23