Case Background
As
part of the continuing fuel and purchased power adjustment and generating
performance incentive factor clause proceedings, an administrative hearing was
held on October 25, 2017. At the
hearing, stipulated issues 1B, 2B-2I, 2Q, 2R, 3A, 6-11, 13A, 16-22, 23A,
24A-24D and 27-36 were approved by bench decision. Issues 1A, 2A, 4A and 5A,
hedging issues contested by the Florida Retail Federation (FRF), the Office of
Public Counsel (OPC) and the Florida Industrial Users Group (FIPUG), were also
approved by bench decision. As a result of the bench decisions on these issues,
all issues associated with Tampa Electric Company (TECO), Florida Public
Utilities Company (FPUC), Gulf Power Company (Gulf), and Duke Energy Florida,
LLC (Duke) have been decided. Testimony was taken on the remaining Florida
Power & Light Company (FPL) issues, Issues 2J-2P, which address FPL’s solar
generation (SoBRA) projects. FIPUG and
FPL filed briefs on the SoBRA issues on November 13, 2017. On November 16,
2017, FPL filed an Unopposed Motion for Leave to File Response to New Issue
Raised in FIPUG’s Post Hearing Brief with its response attached.
The
Commission has jurisdiction over this subject matter pursuant to the provisions
of Chapter 366, Florida Statutes (F.S.), including Sections 366.04, 366.05 and
366.06, F.S.
Discussion
of Issues
Issue A: Should FPL’s Unopposed Motion for Leave to File
Response to New Issue Raised in FIPUG’s Post Hearing Brief be granted?
Recommendation:
Yes, the Commission should grant FPL’s Unopposed
Motion for Leave to File Response to New Issue Raised in FIPUG’s Post Hearing
Brief (Motion). (Brownless)
Staff Analysis:
In its Brief, FIPUG argues
that the Commission lacks jurisdiction to allow the recovery of the capital
costs associated with FPL’s solar energy projects through the fuel clause,
citing the Florida Supreme Court decisions Citizens
v. Graham (Woodford), 191 So.3d 897 (Fla. 2016) and Citizens v. Graham (FPUC), 213
So.3d 703 (Fla. 2017). FPL filed its Unopposed Motion for Leave to File
Response to New Issue Raised in FIPUG’s Post Hearing Brief on November 16, 2017,
with its response to the jurisdictional issue attached. FIPUG does not object to granting this
Motion. The other parties to this docket, having taken no position on the SoBRA
issues, Issues 2J through 2P, did not file briefs or take a position on the Motion
or the underlying jurisdictional issue.
FIPUG did not raise this issue on
or before the Prehearing Conference as required by Order No.
PSC-17-0053-PCO-EI, issued on February 20, 2017. However, Order No.
PSC-17-0053-PCO-EI does not prohibit FIPUG from raising the jurisdictional
issue for the first time in its Brief since lack of jurisdiction can be raised
at any time. Ruble v. Ruble, 884 So.
2d 150 (Fla. 2d DCA 2004; In re: D.N.H.W.,
955 So. 2d 1236 (Fla. 1st DCA 2007). Notwithstanding that fact, due
process requires that FPL be given reasonable notice and a fair opportunity to
be heard on this issue before a decision is made. Citizens v. Florida Public Service Commission, 146 So. 3d 1143,
1154 (Fla. 2014). In this instance, due process requirements with regard to the
jurisdictional issue are satisfied by granting FPL’s Motion and staff
recommends that the Commission do so.
Issue B: Does the Commission have jurisdiction to approve the
SoBRA projects in this docket?
Recommendation:
Yes. The
Commission has the authority to approve the recovery of FPL’s 2017 and 2018
solar projects through base rates in this docket. (Brownless)
Staff Analysis:
Parties’ Arguments
FIPUG
FIPUG argues that the Commission
lacks the jurisdiction to allow recovery in this docket of 2017 and 2018 solar
base rate adjustment (SoBRA) charges. FIPUG cites the Florida Supreme Court
decisions Citizens v. Graham (Woodford),
191 So. 3d 897 (Fla. 2016) and Citizens
v. Graham (FPUC), 213 So. 3d 703 (Fla. 2017) as precedent supporting its
conclusion. FIPUG characterizes the recovery of SoBRA charges as FPL’s effort
to again use the fuel clause to recover predictable capital costs contrary to
the purpose of the fuel clause which is to address the volatility of fuel
prices between base rate cases. (FIPUG BR 9) FIPUG points out that while the
Legislature has created a clause for nuclear and environmental costs, it has not
provided the Commission with express, or implied, authority for a solar energy
capital cost recovery clause. (FIPUG BR 10) FIPUG acknowledges that the process
for SoBRA cost recovery being followed here is included in FPL’s 2016
Stipulation and Settlement (2016 Agreement), to which it did not object. However,
FIPUG counters that jurisdiction cannot be conferred by agreement of the
parties or by Commission approval of a rate case settlement agreement. (FIPUG
BR 10)
FPL
FPL argues that FIPUG’s reliance
on the Woodford and FPUC decisions is misplaced for one
simple reason: the capital and return on investment costs for the SoBRA
projects are not being recovered through the 2017 and 2018 fuel cost recovery
factors. These costs are instead being recovered through increases in FPL’s
base rate charge, beginning on the commercial operation date of each SoBRA
project. (FPL Supp. BR 1-2) In fact, the fuel factors to be implemented from
January 1 to March 1, 2018, have been stipulated to by the parties and approved
by the Commission. These fuel factors cannot change no matter what the final
Commission decision is on the SoBRA issues.
FPL notes that this cost recovery
mechanism is similar to the generation rate base adjustment (GBRA) mechanism
found in FPL’s 2013 Settlement Agreement to which FIPUG was a signatory. The
use of a GBRA mechanism for base rate adjustments in years beyond a test year
was approved by the Florida Supreme Court in Citizens v. Public Service Commission, 146 So. 3d 1143, 1157 n.7
(Fla. 2014). Further, between 2013 and 2016, three separate generation projects
(Cape Canaveral, Riviera Beach and Port Everglades) utilized the GBRA process
in the fuel clause without objection by FIPUG.
FPL argues that filing for SoBRA
recovery in the fuel docket is simply an administratively efficient process
utilizing an existing docket with a known filing schedule to adjust its base
rates for previously approved capital projects. (FPL Supp. BR 5-6) This
eliminates finding and scheduling separate hearing dates each year as SoBRA
projects come on line and synchronizes each SoBRA rate base increase with the
associated reduction in fuel costs resulting from the projects’ commercial
operation. Based on these facts, FPL concludes that no jurisdictional issue
actually exists and that the Commission has the authority to approve SoBRA
charges in this docket.
Analysis
There is one point on which the
Commission staff and all parties agree: that the Commission derives its
authority to act solely from the Legislature. United Telephone Company of Florida v. Public Service Commission,
496 So. 2d 116, 118 (Fla. 1986). In Woodford,
FPL sought to recover through the fuel factor the capital, operation and
maintenance, and return on investment costs for wells drilled in the Woodford
Shale Gas Region in Oklahoma. The Court identified the Commission’s authority
as the ability to “regulate and supervise each public utility with respect to
its rates and service and to prescribe a rate structure for all electric
utilities.” Woodford, 191 So. 3d at
900. An “electric utility” is defined as a municipal or investor-owned utility
or a rural electric cooperative that “owns, maintains, or operates an electric
generation, transmission, or distribution system within the state.” Section
366.02(2), F.S.
Based on this definition, the
Court found that the exploration, drilling and production of natural gas did
“not constitute generating, transmitting, or distributing electricity in Florida
as the meaning of those terms are plainly understood” and “falls outside the
purview of an electric utility as defined by the Legislature.” Woodford, 191 So. 3d at 901. Further,
the Court found that the Woodford project was not a physical hedge of fuel
costs which had previously been determined by the Court to be within the
Commission’s regulatory authority. Id. Having determined that the
Woodford project was neither an electric utility activity contemplated by the
Legislature nor a physical hedge, the Court found that the Commission had
exceeded its authority in approving the project costs through the fuel clause. Woodford, 191 So. 3d at 902.
In FPUC, the Court found that the Commission exceeded its authority by
allowing the recovery through the fuel factor of capital and return on capital
investment costs associated with the construction of a transmission line
connecting FPUC’s electric system on Amelia Island with that of FPL. The Court
focused on the historical purpose of the fuel clause as a means of “adjusting
for volatile costs associated with fuel” finding that a transmission
line failed to meet this test. FPUC,
213 So. 3d at 718. The Court also relied heavily upon the terms of FPUC’s rate
case stipulation and settlement agreement which specifically stated that FPUC
could not seek recovery through the fuel clause of costs that had
“traditionally and historically” been recovered through base rates and used
“investment in and maintenance of transmission assets” as an example of such an
expense. FPUC, 213 So. 3d at 708-10.
Since no discussion of these settlement agreement terms was included in the
Commission’s final order, the Court found that the Commission had “failed to
perform its duty to explain its reasoning” and reversed the Commission’s decision.
FPUC, 213 So. 3d at 710-11.
Both the Woodford and FPUC
decisions discuss what types of costs are appropriately recovered through the
fuel clause factor: fuel, purchased power and volatile fuel-related costs. The FPUC decision does not address the Commission’s
inherent authority to allow the recovery of the FPL transmission line. Further,
if the reasoning in Woodford is
applied to the FPUC facts, the Court
would find the recovery of transmission lines through base rates appropriate
since transmission is specifically listed as an activity engaged in by electric
utilities. Section 366.02(2), F.S.
Likewise, applying the reasoning
of Woodford to the facts here, there
is no question that the Commission has the authority to allow recovery of the
costs associated with solar generation projects. As with transmission,
generation is listed specifically as an activity engaged in by electric
utilities in Section 366.02(2), F.S. It is important to note that FIPUG is not
arguing that FPL does not have the right to recover the solar project costs; it
is arguing that solar project costs can’t be recovered through fuel clause
factors. Presumably, FIPUG would not object to FPL filing a separate docket
seeking cost recovery for the 2017 and 2018 solar projects using an increase in
base rates to do so. Indeed, FIPUG has agreed to such a mechanism to recover
solar project capital costs as a signatory to Tampa Electric Company’s 2017
Amended and Restated Stipulation and Settlement Agreement.
Since FPL is not requesting
recovery through the fuel adjustment clause factor, but is requesting recovery
of costs for its solar projects through increases in base rates, FIPUG’s
complaint does not raise a jurisdictional question at all. Recovery of these
costs through base rates is clearly appropriate under both the Woodford and FPUC decisions. Staff agrees with FPL that placement of this issue
in the fuel clause docket was purely administrative. Staff also agrees with FPL
that to the extent possible, an increase in base rates associated with the
solar projects coming on line should be timed to coincide with any fuel savings
which result from that solar generation.
Litigating the cost effectiveness issues associated with the solar
projects, Issues 2J-2P, in this docket cost-effectively accomplishes this goal.
When dissected and examined
closely, FIPUG’s issue boils down to insisting that rate base cost recovery for
the solar projects be filed in a separate docket. FIPUG has not alleged that it
did not have adequate notice of the solar project issues, or that it has been
harmed in any way by the inclusion of those issues in this docket. Nor could
it. FPL filed direct testimony of four witnesses on this point, Commission
staff conducted extensive discovery on this issue,
FIPUG cross examined FPL witnesses Enjamio and Brannen on this topic at
hearing, and FIPUG filed a post hearing brief. Conducting these activities
under a separate docket number does not change their nature or provide FIPUG
any additional due process rights.
Conclusion
Based on the above, staff
recommends that the Commission find that it has the authority to approve the
recovery of FPL’s 2017 and 2018 solar projects through base rates in this fuel
clause docket.
Issue 2J:
Are the 2017 SoBRA projects proposed by FPL
(Horizon, Wildflower, Indian River, and Coral Farms) cost effective?
Recommendation:
Yes. Based on the evidence contained in the record,
FPL’s proposed solar projects are projected to produce savings under multiple
scenarios. FPL also has met the terms of the 2016 Agreement in regards to
keeping construction cost under the $1,750 per kWac cost cap.
(Wooten, Higgins, Stratis, Wu)
Position of the Parties
FPL:
Yes. The 2017 and 2018 SOBRA projects are cost
effective and are projected to result in $106 million (CPVRR) of customer
savings.
FIPUG:
No.
Staff
Analysis:
Parties’
Arguments
FPL
FPL states that pursuant to the 2016 Stipulation and
Settlement Agreement (2016 Agreement), FPL proposes to construct and operate
596 MW of solar generation by 2018. FPL further states that an economic
analysis was performed to determine the technology with the greatest value for
customers. (FPL BR 5) FPL claims that the choices made for equipment and
technology lowered construction costs. (FPL BR 6)
FPL asserts that the costs for the 2017 and 2018 projects
are reasonable and fall below the $1,750 per kWac cost cap. FPL
states that to ensure reasonable capital costs a competitive bidding process
was completed for equipment to be installed and work to be performed. (FPL BR
7) FPL further asserts that updated efficient designs and reduced
interconnection costs lowered the anticipated costs for the 2017 and 2018
projects. (FPL BR 8)
FPL employs two resource plans for the proposed solar
generation: No Solar Plan and 2017-2018 Solar Plan. FPL further contends that
based on the assumptions made in each plan there was an estimated cumulative
present value revenue requirement (CPVRR) savings of $38.6 million. (FPL BR 10)
FPL asserts that updated tax law in August 2017 provided a reduction in costs,
in the form of reduced property taxes, for three of the four 2018 solar project
sites. FPL states that the efficient designs, reduced interconnection costs,
and reduced property taxes updated the estimated CPVRR savings to $106 million.
(FPL BR 11) FPL asserts that the 2016 Agreement provides that the 2017 and 2018
projects are cost effective if they lower the system CPVRR without them, which
FPL claims the 2017 and 2018 projects do. (FPL BR 7)
FIPUG
FIPUG argues
that the solar projects are not needed to meet the Commission’s 15 percent
reserve margin or FPL’s 20 percent reserve margin. (FIPUG BR 4)
FIPUG contends that
FPL’s efforts to prove that the SoBRA projects are cost effective are only
supported by hearsay evidence. FIPUG adds that FPL customers will lose $127.3 million
if fuel prices remain low and no carbon tax is imposed in the future. (FIPUG BR
5) FIPUG further asserts that the future cost of natural gas and the future
cost of carbon resulting from a carbon tax is uncorroborated. (FIPUG BR 7)
Analysis
The SoBRA projects for 2017 and 2018 for which FPL is seeking
approval and cost recovery are part of its 2016 Agreement approved by Order No.
PSC-16-0560-AS-EI. The 2016 Agreement allows FPL to construct up
to 300 MW per calendar year of solar capacity during the period 2017-2021 and
to recover through base rates the incremental annualized base revenue
requirement for those facilities for the first 12 months of operation
commencing when the facilities are placed into service.
There are several conditions that must be met for recovery in this case. First,
FPL must request recovery for these projects during the term of the 2016
Agreement, or prior to December 31, 2020. Second, the cost of the components,
engineering, and construction for any solar project is capped at $1,750 per
kilowatt alternating current (kWac).
Third, for projects less than 75 MW (as are all of the projects proposed
in this case): 1) the request for base rate recovery must be filed in the Fuel
Clause docket as part of its final true-up filing; and 2) the issues are
“limited to the cost effectiveness of each such project (i.e., will the project
lower the projected system CPVRR as compared to each CPVRR without the solar
project) and the amount of revenue requirements and appropriate percentage in
base rates needed to collect the estimated revenue requirements.” If
the project meets these requirements, the terms of the 2016 Agreement have been
met.
With this consideration in mind,
staff asserts that FIPUG’s consideration of a reliability need based on a
reserve criterion is not relevant to this issue.
Project Description
FPL witnesses Brannen and Enjamio provided testimony and
exhibits concerning FPL’s proposed 2017 solar generation projects, including
cost effectiveness and the ability to meet the $1,750 per kWac cost
cap. As described in the testimony of witness Enjamio, FPL is proposing to
construct and operate four PV centers with a total nameplate capacity of 298 MWac
(74.5 MWac each) with an in-service date of December 31, 2017. (TR
426) Construction for the 2017 solar
generation projects began on October 21, 2016. (EXH 42) The proposed solar
generation projects are Fixed-Tilt Systems with an average projected first year
net capacity factor of 26.6 percent. (EXH 41, EXH 28) There are no upgrades to
existing transmission infrastructure required as part of the construction of
the 2017 solar generation projects. (EXH 84, p. 122)
The four
proposed sites for the 2017 solar project construction are Coral Farms,
Horizon, Wildflower, and Indian River. The Wildflower site is already included
in FPL’s rate base; therefore, Wildflower land costs are not included in any
analysis. All other parcels are new purchases. (EXH 87, pp. 185-186) Staff
recognized that not all land was being used in construction for the seven newly
purchased sites, and in response to a staff interrogatory was informed that
unused areas could include both usable and unusable areas for future solar
development. (EXH 84, p. 135) To develop
a better understanding of the ratio of land that could be used for future
development, staff requested a more detailed breakdown of each site. This
breakdown included four categories: total acreage, acreage used by the projects
(Site Acreage), non-usable land, and residual land. Residual land consists of
property that could possibly be used in future solar developments on the site,
and for sites with adequate amounts of residual land, FPL will consider leasing
land to parties for farming or cattle grazing activities. (EXH 87, pp. 187-188)
The range of acreages of each site is illustrated in Table 2J-1 below:
Table
2J-1
Land Usage
|
Site Name
|
Total Acreage (acres)
|
Site Acreage (acres)
|
Non-Usable Land (acres)
|
Residual Land (acres)
|
|
Coral Farms
|
587
|
541
|
0
|
46
|
|
Horizon
|
1316
|
552
|
178
|
587
|
|
Wildflower
|
721
|
466
|
12
|
244
|
|
Indian River
|
697
|
389
|
56
|
252
|
Source:
EXHs 87-88
Cumulative Evaluation
The in-service date for the 2017
projects is December 31, 2017. The in-service date for the 2018 projects is
March 1, 2018. Because of the minor timing difference between the in-service
dates, staff recommends that it is appropriate to evaluate both 2017 and 2018
projects together. In addition, both the 2017 and 2018 solar generation
projects were cumulatively evaluated in the initial filing of the docket.
FPL developed two resource plans to form the basis of the
cost effectiveness analysis that it performed. These two resource plans are
called the No Solar Plan and 2017-2018 Solar Plan. The No Solar Plan assumes
that resource needs will be met by combined cycle units and short term purchase
power agreements (PPAs) through the year 2030. The 2017-2018 Solar Plan takes
into account the eight solar projects, which initially defers the 2025 combined
cycle (cc) unit. (TR 426) The Okeechobee CC Unit is currently under
construction. The resource plan filed in regards to FPL’s initial filing is
shown in Table 2J-2 below:
Table 2J-2
Initial Resource Plan
|
Year
|
No Solar Resource Plan
|
2017-2018 Solar Resource Plan
|
|
2017
|
|
298 MW Solar
|
|
2018
|
|
298 MW Solar
|
|
2019
|
Okeechobee 3x1 CC
Unit
|
Okeechobee 3x1 CC
Unit
|
|
2020
|
|
|
|
2021
|
|
|
|
2022
|
|
|
|
2023
|
|
|
|
2024
|
1-Year 33 MW PPA
|
|
|
2025
|
1 Greenfield 3x1 CC
Unit
|
1-Year 119 MW PPA
|
|
2026
|
|
1 Greenfield 3x1 CC
Unit
|
|
2027
|
|
|
|
2028
|
1-Year 20 MW PPA
|
|
|
2029
|
1 Greenfield 3x1 CC
Unit
|
1-Year 287 MW PPA
|
|
2030
|
|
1 Greenfield 3x1 CC
Unit
|
|
2031
|
Turkey Point 6
|
Turkey Point 6
|
|
2032
|
Turkey Point 7
|
Turkey Point 7
|
|
2033
|
Equalizing 599 MW
CC
|
Equalizing 291 MW
CC
|
Source: EXH
84
In the
process of staff’s evaluation of the March 2017 initial filing, FPL filed the
2017 Ten Year Site Plan in April 2017, when staff was made aware of the planned
Dania Beach Clean Energy Center. In August 2017, FPL filed revised testimony
that updated the evaluation of the 2017 and 2018 solar projects. To reflect
these new changes, staff requested a new resource plan that would incorporate
both the revised filing and the Dania Beach Clean Energy Center. Table 2J-3
below reflects both of these revisions:
Table 2J-3
Revised Resource Plan
|
Year
|
No Solar Resource Plan
|
2017-2018 Solar Resource Plan
|
|
2017
|
|
298 MW Solar
|
|
2018
|
1-Year 958 MW PPA
|
298 MW Solar;
1-Year 636 MW PPA
|
|
2019
|
Okeechobee 3x1 CC
Unit;
1-Year 155 MW PPA
|
Okeechobee 3x1 CC
Unit
|
|
2020
|
1-Year 182 MW PPA
|
|
|
2021
|
1-Year 263 MW PPA
|
|
|
2022
|
Dania Beach CC
|
Dania Beach CC
|
|
2023
|
|
|
|
2024
|
1-Year 44 MW PPA
|
|
|
2025
|
1 Greenfield 3x1 CC
Unit
|
1-Year 149 MW PPA
|
|
2026
|
|
1 Greenfield 3x1 CC
Unit
|
|
2027
|
|
|
|
2028
|
1-Year 93 MW PPA
|
|
|
2029
|
1 Greenfield 3x1 CC
Unit
|
1-Year 363 MW PPA
|
|
2030
|
|
1 Greenfield 3x1 CC
Unit
|
|
2031
|
Turkey Point 6
|
Turkey Point 6
|
|
2032
|
Turkey Point 7
|
Turkey Point 7
|
|
2033
|
Equalizing 574 MW
CC
|
Equalizing 266 MW
CC
|
Source:
EXH 87
The
revised resource plan shows that the addition of the 2017 and 2018 solar
projects should reduce FPL’s need for purchased power agreements.
In completing the analysis, FPL
considered multiple components to determine cost effectiveness: solar revenue
requirements, avoided generation costs, and avoided system costs. For the
proposed solar facilities, the revenue requirements included fixed operation and
maintenance (O&M), equipment, installation, land cost, and transmission
interconnection cost. The avoided generation cost component considered avoided
generation capital, avoided fixed O&M, avoided transmission
interconnection, avoided capital replacement, incremental gas transport, and
short-term purchases. The avoided system cost component considers the factors
of fuel savings, avoided variable O&M, and emission cost savings.
FPL stated that the emission cost
savings consideration did not incorporate CO2 pricing until 2028.
(EXH 84, pp. 102-104) FPL witness Enjamio identified ICF’s CO2
emission’s cost forecast as a major assumption in FPL’s economic analysis of
its proposed solar PV generation projects. (TR 427) The CO2 cost
projections used in FPL’s cost-effectiveness analyses are based on ICF’s CO2
emission cost forecast dated December 2016. (TR 427) ICF is a consulting firm
with extensive experience in forecasting the cost of air emissions and is
recognized as one of the industry leaders in this field. FPL has used ICF’s CO2
emission cost forecasts in many of its filings in front of the Commission,
including the recently approved 2017 Ten Year Site Plan. (TR 427, FPL BR 9) No
intervenor offered testimony rebutting FPL’s CO2 emission cost
forecast or provided any alternative emission cost forecast. Staff believes
that the CO2 cost projections FPL used in this docket are
appropriate. FPL’s CPVRR analysis assumed that each project had an actual life
of 33 years, with the analysis ending in 2050. (EXH 84, p. 124)
CPVRR Analysis - Initial Filing
Staff reviewed FPL’s original
CPVRR for the 2017 and 2018 solar generation projects that produced a savings
of $38.6 million for the base fuel and environmental forecasts. (EXH 32) This calculation
included the previously mentioned CO2 pricing in 2028. FPL’s CPVRR
analysis in support of its 2017-2018 Solar Plan included assumptions related to
future fuel prices. The Company employed its standard fuel forecasting
methodology to produce its long-term fuel price forecast. (TR 427, EXH 85, EXH
89) No alternative base fuel forecast was provided to the Commission for the
purposes of valuing the Company’s 2017-2018 Solar Plan. Staff believes the
forecasted fuel prices used in the Company’s CPVRR analysis associated with its
current proposal are reasonable. (EXH 89) In response to staff interrogatory
EXH 84, FPL provided a CPVRR analysis with both fuel and environmental
compliance sensitivities. In FPL’s analysis, a Low, Medium, and High Fuel
Forecast and ENV I, ENV II, and ENV III compliance costs were considered. ENV I
assumes an annual $0/ton cost for CO2 pricing and low environmental
compliance costs, ENV II assumes a most likely cost, and ENV III assumes high
environmental compliance costs. (EXH 84,
p. 104) The range of savings is illustrated in Table 2J-4 below:
Table 2J-4
Initial CPVRR Filing
|
|
Environmental Compliance Cost Forecast
|
|
Fuel Cost Forecast
|
|
ENV I
|
ENV II
|
ENV III
|
|
High
|
($63.5)
|
($136.4)
|
($291)
|
|
Medium
|
$35
|
($38.6)
|
($195.8)
|
|
Low
|
$127.3
|
$53.6
|
($103.1)
|
Source:
EXH 84
CPVRR Analysis - Revised Filing
FPL witness Enjamio filed revised testimony August 2, 2017,
that provided updated economic analysis to reflect a change in cost
effectiveness and cost assumptions of the 2017-2018 solar projects.
Specifically, changes in tax law effective as of July 1, 2017, that allowed an
exemption from property taxes for qualifying solar installations which applied
to three of the planned 2018 solar generation project sites, resulted in a $34 million
CPVRR reduction. This revised testimony resulted in a revised $106 million
CPVRR base case scenario. (TR 434)
The terms of the 2016 agreement also require FPL to adhere
to a $1,750 per kWac cost cap for any solar project. This cost cap
includes the cost of the components, engineering, and construction for each
site. In the initial filing, the 2017 and 2018 solar generation projects had a
total anticipated capital cost of $435 million and $457 million, respectively.
The 2017 projects were projected to fall under the cost cap with an average
cost of $1,461per kWac and a $1,534 per kWac average cost
for the 2018 projects. (EXH 43) In the revised testimony on August
2, 2017, witness Brannen stated that the completion of design competitive
solicitations for the construction of the interconnection facilities for the
solar energy centers reduced the projected construction cost by $16 Million for
the 2017 solar construction projects. Witness Brannen stated that these same
factors reduced the projected construction cost by $14 million for the 2018
solar construction projects. (TR 538) For the 2017 projects, the new
construction cost was a $419 million total with a revised average $1,405 per kWac
cost. The new cost per kWac is $56 per kWac less
than the initially filed cost and $345 per kWac less than the $1,750
per kWac cost cap. For the 2018 projects, the new construction cost
was a $443 million total with a revised average $1,485 per kWac cost.
The new cost per kWac is $49 per kWac less than the
initially filed cost and $265 per kWac less than the $1,750 per kWac
cost cap. (EX 44) Staff has reviewed the cost cap assumptions discussed
above and believes them to be reasonable.
FPL’s revised testimony from August 2017 did not include
the planned Dania Beach Clean Energy Center. As such, staff requested an
updated CPVRR evaluation that included the planned Dania Beach Clean Energy
Center and updated fuel and environmental compliance sensitivities evaluations.
The result of this updated sensitivity analysis is illustrated in Table 2J-5 below:
Table
2J-5
Revised CPVRR Analysis
|
|
Environmental Compliance Cost Forecast
|
|
Fuel Cost Forecast
|
|
ENV I
|
ENV II
|
ENV III
|
|
High
|
($119)
|
($195)
|
($348)
|
|
Medium
|
($24)
|
($96)
|
($249)
|
|
Low
|
$76
|
$6
|
($147)
|
Source: EXH 87
Table 2J-5 above shows that in seven of the nine scenarios,
the 2017 and 2018 solar projects are cost effective. Notably the base fuel case
(medium), ENV I scenario contains no cost for CO2, but is also cost
effective. When comparing the change in savings on a CPVRR basis between the
initial filing and the revised analysis, there is a substantial increase in
savings for all forecasted scenarios. While examining the forecasted scenarios,
staff observed that in all scenarios avoided fuel costs was the major driving
force in producing overall savings for the projects. This fact manifested in
even the “worst” case scenario of Low Fuel Cost, ENV I, where there are
projected fuel savings in every forecasted year. When investigating the overall
cost effectiveness of the projects, staff observed that the first cumulative
benefit occurred in 2025. This benefit seems to be driven by the avoided
capital that would be required for the Greenfield 3x1 CC Unit. Staff has
reviewed the CPVRR assumptions discussed and believes them to be reasonable.
FIPUG questions the validity of CO2 emission
cost forecasts. However, FPL performed CO2 emission and natural gas
price sensitivities analyses, including zero carbon tax scenarios, to support
its petition. Results of such sensitivity analyses show that the 2017 and 2018
solar projects are cost-effective in seven out of nine fuel and CO2 sensitivity
scenarios, including scenarios that assume zero CO2 cost. (EXH 86)
The CPVRR and construction cost analyses were performed in a consistent manner
and no party presented substantial evidence disputing either the input
assumptions or the analyses.
Conclusion
Based on the evidence contained
in the record, FPL’s proposed solar projects are projected to produce savings
under multiple scenarios. FPL also has met the terms of 2016 Agreement in
regards to keeping construction cost under the $1,750 per kWac cost
cap.
Issue 2K:
What are the revenue requirements associated with
the 2017 SoBRA projects?
Recommendation:
The jurisdictional annualized revenue requirements
associated with the 2017 SoBRA projects are $60.52 million. (Barrett, Vogel)
Position of the Parties
FPL:
$60,523,000.
FIPUG:
Less than $60.52 million.
Staff Analysis:
Parties’
Arguments
FPL
According to FPL
witness Fuentes, FPL is authorized to seek recovery of the 2017 SoBRA projects
pursuant to the Stipulation and Settlement Agreement reached in FPL’s most
recent rate case proceeding. (TR 174) In its brief, FPL asserted the Rate
Settlement Agreement authorized the construction of up to 300 MWs of new solar
generation each year between 2017 and 2020, if 3 requirements are satisfied:
1. The total costs of the solar projects do not exceed
$1,750/kWac;
2. The construction, engineering, and component
costs are reasonable; and
3. The solar projects are cost-effective
additions to FPL’s system.
(FPL BR 2, citing
Order No. PSC-16-0560-AS-EI)
The witness testified that the annualized jurisdictional
revenue requirements for the first 12 months of operations related to the 2017
SoBRA projects are $60,523,000. (TR
175; EXH 45, p. 1; FPL BR 17) Witness Fuentes further stated that the $60,523,000
revenue requirement was calculated by following the methodologies approved by
the Commission for FPL’s generation base rate adjustments (GBRA) for Turkey
Point Unit 5 and West County Energy Center Units 1 and 2 in Order No.
PSC-05-0902-S-EI, West
County Energy Center Unit 3 in Order No. PSC-11-0089-S-EI, and
the modernization projects at Canaveral, Riviera Beach, and Port Everglades in
Order No. PSC-13-0023-S-EI. Witness
Fuentes also testified that the same methodology was also used with the recently
approved 2019 Okeechobee Limited Scope Adjustment (Okeechobee LSA). (TR 176; FPL BR 17)
The jurisdictional annualized revenue requirement
calculation for the 2017 SoBRA projects used several inputs, including the most
current estimated capital expenditures presented by FPL witness Brannen. (Fuentes,
TR 177; EXH 43-45; Brannen, TR 537)
FIPUG
FIPUG did not
sponsor a witness to address this issue, and waived cross-examination of FPL
witness Fuentes. In its brief, FIPUG presented assertions about FPL’s reserve
margin, the overall cost effectiveness of the 2017 SoBRA projects, and the
appropriate cost recovery mechanism for these projects, but did not
specifically address this issue in its brief. (FIPUG BR 11)
Analysis
Issues 2J, 2K, and
2L all pertain to FPL’s proposed Horizon, Wildflower, Indian River, and Coral
Farms solar generation facilities currently being constructed (2017 SoBRA
projects). This issue addresses the revenue requirements associated with
the 2017 SoBRA projects. Staff believes
FPL is authorized to seek recovery of the 2017 SoBRA projects pursuant to the
2016 Agreement. Staff reviewed the testimony, exhibits, and calculations used
by FPL witness Fuentes for determining the amount of revenue requirement
associated with the 2017 SoBRA projects and found them to be reasonable, and
agrees with witness Fuentes’ calculated revenue requirement. (TR 175; EXH 45, p. 1)
Conclusion
Staff
recommends that the jurisdictional annualized revenue requirements associated
with the 2017 SoBRA projects be set at $60.52 million.
Issue 2L:
What is the appropriate base rate percentage
increase for the 2017 SOBRA projects to be effective when all 2017 projects are
in service, currently projected to be January 1, 2018?
Recommendation:
The appropriate base rate percentage increase (SoBRA
Factor) for the 2017 SoBRA projects is 0.937 percent. (Barrett, Vogel)
Position of the Parties
FPL:
0.937%.
FIPUG:
Less than 0.937%.
Staff
Analysis:
Parties’
Arguments
FPL
According to FPL
witness Cohen, the SoBRA factors are incremental cost recovery factors that
will be applied to base rate charges in order for the Company to collect the
revenue necessary to recover the costs associated with building and operating
the 2017 SoBRA projects. (TR 182) Witness Cohen testified that:
SoBRA factors are based on the ratio of (1) the
Company’s jurisdictional revenue requirements for each Project [by year] and
(2) the forecasted retail base revenue from electricity sales for the first
twelve months of each rate year, beginning January 1, 2018 for the 2017 Project
and March 1, 2018 for the 2018 Project.
(Cohen, TR
182; FPL BR 19)
Witness Cohen also presented an exhibit to demonstrate the
inputs and calculations performed to determine the resulting incremental cost
recovery factor of 0.937 percent for the 2017 SoBRA projects. (EXH 47)
FPL asserted in its brief that even when all of the SoBRA
projects are reflected in customer bills, FPL’s typical residential bills will
remain below national and statewide averages. (FPL BR 19) Table 2L-1 below
reflects the base rate changes and fuel cost recovery changes that will occur
for typical monthly residential bills for customers using 1,000 kWh of
electricity. Column 3 in Table 2L-1 reflects a typical bill before the
application of incremental cost recovery factors for any SoBRA projects. Column
4 in Table 2L-1 reflects a typical bill for a residential customer using 1,000
kWh of electricity when the incremental cost recovery factor of 0.937 percent
for the 2017 SoBRA projects is applied, and Column 5 reflects a typical bill
for a residential customer using 1,000 kWh of electricity when all of the
projects are implemented. (EXH 51, p. 1)
|
Table 2L-1
|
|
FPL Typical 1,000-kWh
Residential Customer Bill Comparison For 2018
|
|
(1)
|
|
(2)
|
|
(3)
|
|
(4)
|
|
(5)
|
|
Bill Components
|
|
Present (2017)
|
|
Approved in the
2016 Settlement Agreement
(Jan, 2018)
|
|
Proposed for
the 2017 SoBRA Projects (Jan & Feb, 2018)
|
|
Proposed for
the 2017 & 2018 SoBRA Projects (March, 2018)
|
|
Base Rate Charges
|
|
$63.49
|
|
$65.88
|
|
$66.49
|
|
$67.10
|
|
Fuel Cost Recovery
|
|
$24.91
|
|
$23.35
|
|
$23.17
|
|
$22.97
|
|
Other Charges
|
|
$14.15
|
|
$13.11
|
|
$13.12
|
|
$9.68
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$102.55
|
|
$102.34
|
|
$102.78
|
|
$99.75
|
|
Source: (EXH 51, Exhibit TCC-5, Page 1 of
5)
|
|
|
|
|
FIPUG
FIPUG did not
sponsor a witness to address this issue, and waived cross-examination of FPL
witness Cohen. In its brief, FIPUG presented assertions about FPL’s reserve
margin, the overall cost effectiveness of the 2017 SoBRA projects, and the
appropriate cost recovery mechanism for these projects, but did not
specifically address this issue in its brief. (FIPUG BR 11)
Analysis
Issues 2J, 2K, and
2L all pertain to FPL’s proposed Horizon, Wildflower, Indian River, and Coral
Farms solar generation facilities currently being constructed (2017 SoBRA
projects). This issue addresses the proposed base rate percentage
increase associated with the 2017 SoBRA projects. Staff believes FPL is authorized to seek recovery of the 2017 SoBRA
projects pursuant to the 2016 Agreement, and apply the appropriate base
rate percentage increase (SOBRA Factor) for the 2017 SOBRA projects.
Conclusion
Staff reviewed the
testimony, exhibits, and calculations used by FPL witness Cohen for
determining the appropriate incremental cost recovery factor associated with
the 2017 SoBRA projects. Staff recommends that the appropriate base rate
percentage increase (SoBRA Factor) for the 2017 SoBRA projects is 0.937 percent.
Issue
2M: Are the 2018 SoBRA
projects proposed by FPL (Hammock, Barefoot Bay, Blue Cypress and Loggerhead)
cost effective?
Recommendation:
Yes. Based on the evidence contained in the record,
FPL’s proposed solar projects are projected to produce savings under multiple
scenarios. FPL also has met the terms of 2016 Agreement in regards to keeping
construction cost under the $1,750 per kWac cost cap. (Wooten,
Higgins, Stratis, Wu)
Position of the Parties
FPL:
Yes. The 2017 and 2018 SoBRA projects are cost
effective and are projected to result in $106 million (CPVRR) of customer
savings.
FIPUG:
No.
Staff
Analysis:
Parties’
Arguments
FPL
FPL states that pursuant to the 2016 Stipulation and
Settlement Agreement (2016 Agreement), FPL proposes to construct and operate
596 MW of solar generation by 2018. FPL further states that an economic
analysis was performed to determine the technology with the greatest value for
customers. (FPL BR 5) FPL claims that the choices made for equipment and
technology lowered construction costs. (FPL BR 6)
FPL asserts that the costs for the 2017 and 2018 projects
are reasonable and fall below the $1,750 per kWac cost cap. FPL
states that to ensure reasonable capital costs a competitive bidding process
was completed for equipment to be installed and work to be performed. (FPL BR
7) FPL further asserts that updated efficient designs and reduced
interconnection costs lowered the anticipated costs for the 2017 and 2018
projects. (FPL BR 8)
FPL employs two resource plans for the proposed solar
generation: No Solar Plan and 2017-2018 Solar Plan. FPL further contends that
based on the assumptions made in each plan, there was an estimated cumulative
present value revenue requirement (CPVRR) savings of $38.6 million. (FPL BR 10)
FPL asserts that an updated tax law in August 2017 provided a reduction in
costs in the form of reduced property taxes for three of the four 2018 solar
project sites. FPL states that the efficient designs, reduced interconnection
costs, and reduced property taxes updated the estimated CPVRR savings to $106
Million. (FPL BR 11) FPL asserts that the 2016 Agreement provides that the 2017
and 2018 projects are cost effective if they lower the system CPVRR without
them, which FPL claims the 2017 and 2018 projects do. (FPL BR 7)
FIPUG
FIPUG argues
that the solar projects are not needed to meet the Commission’s 15 percent
reserve margin or FPL’s 20 percent reserve margin. (FIPUG BR 4)
FIPUG contends that
FPL’s efforts to prove that the SoBRA projects are cost effective are only
supported by hearsay evidence. FIPUG adds that FPL customers will lose $127.3 million
if fuel prices remain low and no carbon tax is imposed in the future. (FIPUG BR
5) FIPUG further asserts that the future costs of natural gas and the future
cost of carbon resulting from a carbon tax is uncorroborated. (FIPUG BR 7)
Analysis
The SoBRA projects for 2017 and 2018 for which FPL is
seeking approval and cost recovery are part of its 2016 Agreement approved by
Order No. PSC-16-0560-AS-EI. The 2016 Agreement allows FPL to construct up
to 300 MW per calendar year of solar capacity during the period 2017-2021 and
to recover through base rates the incremental annualized base revenue
requirement for those facilities for the first 12 months of operation
commencing when the facilities are placed into service. There
are several conditions that must be met for recovery in this case. First, FPL
must request recovery for these projects during the term of the 2016 Agreement,
or prior to December 31, 2020. Second, the cost of the components, engineering,
and construction for any solar project is capped at $1,750 per kilowatt
alternating current (kWac).
Third, for projects less than 75 MW (as are all of the projects proposed
in this case): 1) the request for base rate recovery must be filed in the Fuel
Clause docket as part of its final true-up filing; and 2) the issues are
“limited to the cost effectiveness of each such project (i.e., will the project
lower the projected system CPVRR as compared to each CPVRR without the solar
project) and the amount of revenue requirements and appropriate percentage in
base rates needed to collect the estimated revenue requirements.”
If the project meets these requirements, the terms of the 2016 Agreement have
been met.
With this consideration in mind, staff asserts that
FIPUG’s consideration of a reliability need based on a reserve criterion is not
relevant to this issue.
Project Description
FPL witnesses Brannen and Enjamio provided testimony and
exhibits concerning FPL’s proposed 2018 solar generation projects, including
cost effectiveness and the ability to meet the $1,750 per kWac cost
cap. As described in the testimony of
witness Enjamio, FPL is proposing to construct and operate four PV centers with
a total nameplate capacity of 298 MWac (74.5 MWac each)
for an in-service date of March 1, 2018. (TR 426) Construction of the 2018
solar generation projects began on October 21, 2016. (EXH 42) The proposed
solar generation projects are Fixed-Tilt Systems with an average projected first
year net capacity factor of 26.6 percent. (EXH 41, EXH 28) There are no
upgrades to existing transmission infrastructure required as part of the
construction of the 2018 solar generation projects. (EXH 84, p. 122)
The four proposed sites for the 2018 solar project
construction are Loggerhead, Barefoot Bay, Hammock, and Blue Cypress. All parcels
are new purchases. (EXH 87, pp. 185, 186) Staff recognized that not all land
was being used in construction for the four newly purchased sites, and in
response to a staff interrogatory was informed that unused areas could include
both usable and unusable areas for future solar development. (EXH 84, p. 135) To
develop a better understanding of the ratio of land that could be used for
future development, staff requested a more detailed breakdown of each site.
This breakdown included four categories: total acreage, acreage used by the
projects (Site Acreage), non-usable land, and residual land. Residual land
consists of property that could possibly be used in future solar developments
on the site, and for sites with adequate amounts of residual land, FPL will
consider leasing land to parties for farming or cattle grazing activities. (EXH
87, pp. 187-188) The range of acreages of each site is illustrated in Table
2M-1 below:
Table 2M-1
Land Usage
|
Site Name
|
Total Acreage (acres)
|
Site Acreage (acres)
|
Non-Usable Land (acres)
|
Usable Land (acres)
|
|
Loggerhead
|
564
|
425
|
27
|
112
|
|
Barefoot Bay
|
462
|
384
|
52
|
25
|
|
Hammock
|
957
|
407
|
375
|
176
|
|
Blue Cypress
|
424
|
418
|
0
|
6
|
Source: EXHs 87-88
CPVRR Analysis
As discussed in Issue 2J, the CPVRR analysis of the 2018
solar projects was done cumulatively with the 2017 solar projects and
consistent with that issue, is cost effective under a range of scenarios.
Similarly discussed in Issue 2J is the $1,750 per kWac cost cap for
2018 solar projects per the 2016 Agreement.
Conclusion
Based on the evidence contained
in the record, FPL’s proposed solar projects are projected to produce savings
under multiple scenarios. FPL also has met the terms of 2016 Agreement in
regards to keeping construction cost under the $1,750 per kWac cost
cap.
Issue 2N:
What are the revenue requirements associated with
the 2018 SoBRA projects?
Recommendation:
The jurisdictional annualized revenue requirements
associated with the 2018 SoBRA projects are $59.89 million. (Barrett, Vogel)
Position of the Parties
FPL:
$59,890,000.
FIPUG:
Less than $59.89 million.
Staff
Analysis:
Parties’
Arguments
FPL
According to witness
Fuentes, FPL is authorized to seek recovery of the 2018 SoBRA projects pursuant
to the Stipulation and Settlement Agreement reached in FPL’s most recent rate
case proceeding. (TR 174; FPL BR 2) The witness asserted that the
annualized jurisdictional revenue requirements for the first 12 months of
operations related to the 2018 SoBRA projects are $59,890,000. (TR 275; EXH 46, p. 1; FPL BR 17) Witness
Fuentes further stated that the revenue requirement was calculated by
following the methodologies approved by the Commission for FPL’s generation
base rate adjustments (GBRA) for Turkey Point Unit 5 and West County Energy
Center Units 1 and 2 in Order No. PSC-05-0902-S-EI,
West County Energy Center Unit 3 in Order No. PSC-11-0089-S-EI,
and the modernization projects at Canaveral, Riviera Beach, and Port Everglades
in Order No. PSC-13-0023-S-EI. Witness
Fuentes also testified that the same methodology was used with the recently
approved 2019 Okeechobee Limited Scope Adjustment (Okeechobee LSA). (TR 176; FPL BR 17)
The jurisdictional annualized revenue requirement calculation
for the 2018 SoBRA projects used several inputs, including the most current
estimated capital expenditures presented by FPL witness Brannen. (Fuentes, TR 177; Brannen, TR 537; EXHs 43-44, 46, p. 1)
FIPUG
FIPUG did not
sponsor a witness to address this issue, and waived cross-examination of FPL
witness Fuentes. In its brief, FIPUG presented assertions about FPL’s reserve
margin, the overall cost effectiveness of the 2018 SoBRA projects, and the
appropriate cost recovery mechanism for these projects, but did not
specifically address this issue in its brief. (FIPUG BR 11)
Analysis
Issues 2M, 2N, and
2O all pertain to FPL’s proposed Loggerhead, Barefoot Bay, Hammock, and Blue
Cypress solar generation facilities currently being constructed (2018 SoBRA
projects). This issue addresses the revenue requirements associated with
the 2018 SoBRA projects. Although the
projects are different, staff believes this issue is similar in every respect
to Issue 2K. Staff recommends that FPL is authorized to seek recovery of the 2018
SoBRA projects pursuant to the 2016 Agreement.
Conclusion
Staff reviewed the
testimony, exhibits, and calculations used by FPL witness Fuentes for
determining the amount of revenue requirement associated with the 2018 SoBRA
projects, and recommends that the jurisdictional annualized revenue
requirements be set at $59.89 million.
Issue 2O:
What is the appropriate base rate percentage
increase for the 2018 SoBRA projects to be effective when all 2018 projects are
in service, currently projected to be March 1, 2018?
Recommendation:
The appropriate base rate percentage increase (SoBRA
Factor) for the 2018 SoBRA projects is 0.919 percent. (Barrett, Vogel)
Position of the Parties
FPL:
0.919%.
FIPUG:
Less than 0.919%.
Staff Analysis:
Parties’
Arguments
FPL
According to FPL
witness Cohen, the SoBRA factors are incremental cost recovery factors that
will be applied to base rate charges in order for the Company to collect the
revenue necessary to recover the costs associated with building and operating
the 2018 SoBRA projects. (TR 182) Witness Cohen testified that:
SoBRA factors are based on the ratio of (1) the
Company’s jurisdictional revenue requirements for each Project [by year] and
(2) the forecasted retail base revenue from electricity sales for the first
twelve months of each rate year, beginning January 1, 2018 for the 2017 Project
and March 1, 2018 for the 2018 Project.
(Cohen, TR
182)
Additionally, witness Cohen presented an exhibit to
demonstrate the inputs and calculations performed to determine the resulting
incremental cost recovery factor of 0.919 percent for the 2018 SoBRA projects.
(EXH 47)
As noted in a prior issue (Issue 2L), FPL believes that
even when the incremental cost recovery
factors for all of the SoBRA projects are implemented, residential bills
will remain below national and statewide averages. (FPL BR 19) Witness Cohen
presented an exhibit to demonstrate the billing changes projected to occur for
typical residential bills for customers using 1,000 kWh of electricity, which
staff summarized in Table 2L-1. (EXH 51, p. 1)
FIPUG
FIPUG did not
sponsor a witness to address this issue, and waived cross-examination of FPL
witness Cohen. In its brief, FIPUG presented assertions about FPL’s reserve
margin, the overall cost effectiveness of the 2017 SoBRA projects, and the
appropriate cost recovery mechanism for these projects, but did not
specifically address this issue in its brief. (FIPUG BR 11)
Analysis
Issues 2M, 2N, and
2O all pertain to FPL’s proposed Loggerhead, Barefoot Bay, Hammock, and Blue
Cypress solar generation facilities currently being constructed (2018 SoBRA
projects). This issue addresses the proposed base rate percentage
increase associated with the 2018 SoBRA projects. Although the projects are different, staff believes this issue is
similar in every respect to Issue 2L. Staff recommends that FPL is authorized
to seek recovery of the 2018 SoBRA projects pursuant to the 2016 Agreement, and
apply the appropriate base rate percentage increase (SoBRA Factor) for
the 2018 SoBRA projects.
Conclusion
Staff reviewed the
testimony, exhibits, and calculations used by FPL witness Cohen for
determining the appropriate incremental cost recovery factor associated with
the 2018 SoBRA projects. Based on this review, staff recommends that the
appropriate base rate percentage increase (SoBRA Factor) for the 2018 SoBRA
projects should be set at 0.919 percent.
Issue 2P:
Should the Commission approve revised tariffs for
FPL reflecting the base rate percentage increases for the 2017 and 2018 SoBRA
projects determined to be appropriate in this proceeding?
Recommendation:
Yes. The Commission should approve revised tariffs
for FPL reflecting the base rate percentage increases for the 2017 and 2018 SoBRA
projects determined to be appropriate in this proceeding. (Guffey, Barrett)
Position of the Parties
FPL:
Yes.
FIPUG:
No.
Staff Analysis:
Parties’
Arguments
FPL
FPL witness Cohen
sponsored exhibits that summarize the tariff changes for all SoBRA projects.
(EXHs 49-50) The 2017 SoBRA projects are scheduled to enter commercial service is
December 31, 2017, and the 2018 SoBRA projects is March 1, 2018. Witness Cohen
testified that:
If the SoBRA and the associated charges are approved
for both [2017 and 2018] Projects, the Company will submit revised tariff
sheets reflecting the Commission-approved charges.
(Cohen, TR 183)
Witness Cohen asserted that the Company will formally
notify the Commission by letter of the specific in-service dates for each set
of projects, and the base rate changes will become effective on or after that
date. (TR 184) In its brief, FPL stated:
The economic
analyses performed demonstrate that the 2017 and 2018 Projects generate $106
million in customer savings (CPVRR) and are thus cost-effective. Finally, the
revenue requirements and SoBRA factors for each Project were calculated as
prescribed in the Rate Settlement Agreement. Accordingly, FPL should be
authorized to implement revised tariffs reflecting the SoBRA factors when the
2017 and 2018 Projects enter commercial operation.
(FPL BR 20)
FIPUG
FIPUG did not
sponsor a witness to address this issue, and waived cross-examination of FPL
witness Cohen. In its brief, FIPUG asserted that FPL’s Solar Projects are not
needed to meet FPL’s Reserve Margin, and spending the capital on these projects
is not a prudent decision. FIPUG contends that the tariffs should not be
approved. (FIPUG BR 3, 11)
Analysis
This issue
addresses approving the tariffs for the 2017 and 2018 SoBRA projects. As set forth in the preceding issues, staff
observes that FPL’s 2016 Agreement states that the issues for determination are
limited to three principle considerations:
1. Cost effectiveness, as discussed in Issues 2J
(for the 2017 Projects) and 2M (for the 2018 Projects).
2. The amount of revenue requirements, as
discussed in Issues 2K (for the 2017 Projects) and 2N (for the 2018 Projects).
3.
The appropriate
percentage increase in base rates needed to recover the revenue requirement
amounts identified above. These percentage increases are reflected as recovery
factors, as discussed in Issues 2L (for the 2017 Projects) and 2O (for the 2018
Projects).
Based on
recommendations in Issues 2J-2O, staff recommends the Commission approve
revised tariffs for FPL reflecting the base rate percentage increases for the
2017 and 2018 SoBRA projects determined to be appropriate in this proceeding.
Conclusion
Staff recommends the
Commission approve revised tariffs for FPL reflecting the base rate percentage
increases for the 2017 and 2018 SoBRA projects determined to be appropriate in
this proceeding.
Issue 36: Should this docket be closed?
Recommendation:
No. While a separate docket number is assigned each year for
administrative convenience, this is a continuing docket and should remain open.
(Brownless)
Staff
Analysis:
While a separate docket number is assigned each year
for administrative convenience, this is a continuing docket and should remain
open.
Order No. PSC-05-0902-S-EI, issued September 14, 2005, in Docket No.
20050045-EI, In re: Petition for rate
increase by Florida Power & Light Company, and in Docket No.
20050188-EI, In re: 2005 comprehensive
depreciation study by Florida Power & Light Company.
Order No. PSC-11-0089-S-EI, issued February 1, 2011,
in Docket No. 20080677-EI, In re:
Petition for increase in rates by Florida Power & Light Company, and in
Docket No. 20090130-EI, In re: 2009
depreciation and dismantlement study by Florida Power & Light Company.
Order No. PSC-13-0023-S-EI, issued January 14, 2013,
in Docket No. 20120015-EI, In re:
Petition for increase in rates by Florida Power & Light Company.
