Case Background
This proceeding commenced on August 11, 2008, with the
filing of a petition for a permanent rate increase by Tampa Electric Company
(TECO or Company). The Company is engaged in business as a public utility
providing electric service as defined in Section 366.02, Florida Statutes
(F.S.), and is subject to the jurisdiction of the Commission. A hearing was
conducted on January 20-21, and 27-30, 2009. At the March 17, 2009, Agenda
Conference, the Commission approved an increase to operating revenue of $104,268,536
for the 2009 projected test year. TECO requested an increase of $228,167,000.
The Commission
also approved an additional increase in base rates, effective January 1, 2010,
of $33,561,370 to recover the cost of the five combustion turbine (CT) units
and the Big Bend Rail Facilities, subject to the condition that these investments
are needed and in commercial operation by December 31, 2009. The final revenue
requirements and step increase calculations are contained in Schedule 1.
This recommendation
addresses the issues that were not addressed at the March 17, 2009, Agenda
Conference, and which set the final rates (Issues 101, 102, and 107). In Issue
108 the recommendation addresses the Capacity Cost Recovery, Energy
Conservation Cost Recovery (ECCR), and Environmental Cost Recovery Clause (ECRC)
factors that will change based on the Commission’s vote in various cost of
service and rate design issues. New Issue 114A addresses how the increase in
revenue requirements effective January 1, 2010, be collected from the
customers. Based on the Commission vote at the March 17, 2009, Agenda
Conference, TECO filed a compliance cost of service study on March 25, 2009, to
be used to establish revenue requirements for each rate class and final rates
and charges.
Staff’s
recommendation on Issue 86, approved by the Commission on March 17, 2009, establishes
the method by which any increase in revenue requirements is allocated to the
various customer classes to set new rates. That decision set certain parameters
for designing new rates: (1) to the extent possible, consistent with other
parameters, the revenue increase should be allocated so as to bring all rate
classes as close to parity as practicable; (2) no class should receive an
increase greater that 1.5 times the system average increase; and (3) no class
should receive a decrease. The final class revenue requirements are shown in
Schedule 2.
Several interim
steps are necessary to establish final rates. First, to determine the increase
by class, the present revenues must be restated to reflect the change in rate
structure for the interruptible (IS) class approved in Issue 87. Because production
demand costs will now be allocated to the IS class based on its actual measured
12 Coincident Peak load responsibility, demand costs to all other rate classes
are reduced. However, the ECCR charge for all classes will increase to reflect
the demand-side management (DSM) credits payable to IS customers, in lieu of
the reduced base rate. If current revenues are not adjusted to reflect the IS
rate restructuring, firm customers will see an increase in their total bills (base
rates plus clauses) simply due to the restructuring, even without any change in
total revenue requirements.
Second, the
unadjusted revenue requirement by class is determined by subtracting the
revenues at current rates (determined in Step 1) by class, from the revenue
requirement shown in the compliance cost of service study. This unadjusted result
must then be evaluated against the parameters set forth in Issue 86. If the
increase to any class is greater than 1.5 times the system average increase
(11.6 percent), revenue requirements will be shifted to other classes to meet
that constraint. Also, since no class is granted a decrease in a general rate
increase, the surplus shown for the IS class is reallocated to reduce the
increase to other classes. Class
revenue requirements are then adjusted to recognize unbilled revenues (Issue 85)
to arrive at the final revenue requirement by rate class.
The final step
is to translate the class revenue requirement into actual rates. The total
revenue requirement for each rate class is first reduced by the customer charge
revenue approved in Issue 100. The proposed energy and demand charges are designed
to provide approximately the same percentage increase in energy and demand
charge revenues as the overall percentage increase in class revenues. All
other rates, charges, and credits reflect the decisions made on March 17, 2009.
Final rates, charges, and credits by rate class are contained in Schedule 3.
Pursuant to the
Commission vote in Issue 88, TECO also developed rates and charges for the new
firm IS and IS standby and supplemental rate schedule. The IS customer charge
is based on the approved GSD customer charges for primary and subtransmission
level (Issue 100) plus the cost of interruptible equipment. IS service is only
provided at primary or higher level. TECO proposed to keep the current IS-1
and IS-3 demand charge of $1.45 per kW at the same level, while increasing the non-fuel
energy charge. The dollar increase in the energy charge will be offset by the per
kW DSM credit interruptible customers will now receive under the GSLM-2 and
GSLM-3 load management riders. Since the DSM credit is a load factor adjusted
credit, increasing the energy charge in lieu of the demand charge will ensure
that the base rate component of bills for all IS customers with varying load
factors will remain unchanged.
Schedule 5
contains a calculation of TECO’s 1,000 kilowatt-hour (kWh) monthly residential
bill at both present and recommended rates. While the base rate component of
the bill will increase by $1.45, overall bills will decrease due to projected
lower fuel costs for the remainder of 2009. TECO filed a petition for a
modification to its fuel and purchased power cost recovery factors in Docket
No. 090001-EI, which is also scheduled for the April 7, 2009, Agenda
Conference. Staff notes that TECO proposed in its midcourse correction
petition to adjust fuel factors by the 2009 estimated over-recovery of $190
million. Staff recommends in Docket No. 090001-EI that TECO also include the final 2008 true-up of $35 million in its calculation of the May through
December 2009 fuel factors. Thus, the Commission’s decision in the fuel docket
will impact the final bill calculations.
TECO proposes
that the revised fuel factors be effective May 7, 2009, coincident with the Company’s
base rate changes approved in this docket. Based on the staff-recommended fuel
factor, the 1,000 kWh residential bill will decrease from $128.44 to $114.06, a
$14.38 decrease. Schedule 5 also
contains residential bill calculations at various other usage levels based on
staff’s recommended base rates and fuel adjustment.
Based upon the stipulation approved in Issue 111 in this
docket, the revised rates will be effective for meter readings taken on or
after May 7, 2009. The Commission has jurisdiction pursuant to Sections
366.06(2) and (4), and 366.071, F. S.
Discussion
of Issues
Issue 101:
What are the appropriate demand charges?
Recommendation:
The appropriate demand charges are shown in Schedule
3. Staff requests that the Commission grant staff the authority to
administratively approve the tariffs filed to implement the rates, charges, and
credits presented in Schedule 3. (Draper)
Staff Analysis:
The appropriate demand charges are shown in Schedule
3. The demand charges were set at a level that, in combination with the remaining
rate components, will result in the recovery of the total revenues allocated to
each rate class. Staff requests that the Commission grant staff the authority
to administratively approve the tariffs filed to implement the rates presented
in this recommendation.
Issue 102:
What are the appropriate Standby Service charges?
Recommendation:
The appropriate Standby Service charges are shown in
Schedule 3. (Draper)
Staff Analysis:
The appropriate Standby Service charges are shown in
Schedule 3. These rates are calculated using the revenue requirement approved,
consistent with Commission Order 17159, issued February 6, 1987, in Docket No.
850673-EU, In re: Generic Investigation of Standby Rates for Electric
Utilities.
Issue 107: What are the appropriate energy charges?
Recommendation:
The appropriate energy charges are shown in Schedule
3. (Draper)
Staff Analysis:
The appropriate energy charges are shown in
Schedule 3. The energy charges were set at a level that, in combination with
the remaining rate components, will result in the recovery of the total
revenues allocated to each rate class.
Issue 108:
What changes in allocation and rate design should be made
to TECO’s rates established in Docket Nos. 080001-EI, 080002-EG, and 080007-EI, to recognize the decisions in various cost of service rate design issues
in this docket? (Stipulated)
Recommendation:
The methodology for adjusting the affected cost
recovery clause factors was stipulated in Issue 108. Pursuant to the
stipulation, the revised factors are shown in Schedule 4 and should be
approved. The revised factors should become effective May 7, 2009. (Draper)
Staff Analysis:
The Commission approved the following language in
Issue 108:
The changes
in allocation and rate design to TECO’s capacity cost recovery factors
established in Docket No. 080001-EI, conservation cost recovery factors
established in Docket No. 080002-EI, and environmental cost recovery factors
established in Docket No. 080007-EI should reflect the Commission vote in
Issues 83, 87, and 88. In addition, the capacity cost recovery clause and
energy conservation cost recovery clause factors should be recovered on demand
basis rather than an energy basis as it is currently done.
The current factors need to be
revised for four reasons. First, the Commission approved in Issue 83 a change
in cost of service methodology from 12 CP and 1/13 Average Demand (AD) to 12 CP
and 25 percent AD to allocate production demand costs. This change in cost of
service methodology applies to both base rates and cost recovery clause
factors. Second, pursuant to the Commission’s approval of staff’s
recommendation in Issue 87, interruptible customers will now be responsible for
their full 12 CP load share of production capacity related costs in base rates
and cost recovery clause factors. Third, the DSM credits payable to
interruptible customers will be recovered from all rate classes through the
ECCR clause. Finally, as approved in Issue 108, the capacity and ECCR factors will
be recovered on a demand basis from the demand rate classes rather than an
energy basis as it is currently done.
Pursuant to the approved
language in Issue 108, TECO revised the factors in the above dockets. Staff
has reviewed the calculation and recommends approval of the factors by rate
class as shown in Schedule 4. The factors should become effective May 7, 2009.
New Issue 114A:
How should the step increase in revenue requirements
effective January 1, 2010, be collected from the customers?
Recommendation:
The total step increase in revenue requirements
should be allocated to all customer classes based on the cost of service study
approved in this docket. The energy charge, or energy and demand for demand
metered classes, and non-clause recoverable
credits should be increased by the percentage increase in each class’s
revenue requirements. Staff further requests that the Commission grant staff
the authority to approve the step increase rates administratively, once the
dollar amount of the increase has been verified and staff has confirmed the new
plant and facilities are in service by December 31, 2009. (Kummer)
Staff Analysis:
The
Commission voted to authorize an additional increase in base rates of $33.5
million, effective January 1, 2010, provided that the investments in the five
Combustion Turbines and the Big Bend Rail facilities are in service by December
31, 2009. The Commission further stated that such costs should be allocated to
rate classes consistent with the cost of service methodology approved in Issue
83.
In order to retain the relative class relationships developed in the
current cost of service study, staff believes the incremental costs should
first be allocated to each rate class, consistent with the 12 CP and 25 percent
AD cost methodology approved in this docket. Once the dollar increase per
class is established, staff recommends that the base rate energy, or energy and
demand charges, be increased by the percentage increase in class revenues. In
addition, non-clause recoverable credits should also be increased by a similar
amount to retain the relationship between the charges and credits approved in
the current cost study.
Staff further requests that the Commission grant staff the authority to
approve the step increase rates administratively, once the dollar amount of the
increase has been verified and staff has confirmed the new plant and facilities
are in service by December 31, 2009.
Issue 114:
Should this docket be closed?
Recommendation:
The docket should be closed upon the expiration of
the time for filing an appeal. (Young, Brown)
Staff Analysis:
The docket should be closed upon the
expiration of the time for filing an appeal.
