IA-11-25

IA-11-25
I. Meeting Packet
State of Florida
Public Service Commission
INTERNAL AFFAIRS AGENDA
Tuesday, November 25, 2014
Immediately Following Commission Conference
Room 105 – Gunter Building
1.
Draft Comments on the U.S. Environmental Protection Agency’s Proposals to Limit Carbon
Emissions from Existing Electric Utility Generating Units. Approval is sought.
(Attachment 1)
2.
Staff’s Review of the 2014 Ten-Year Site Plan. Due December 31. Approval is sought.
(Attachment 2)
3.
Draft 2014 Lifeline Report. Due December 31. Approval is sought. (Attachment 3)
4.
Executive Director’s Report. (No attachment)
5.
Other Matters.
BB/sc
OUTSIDE PERSONS WISHING TO ADDRESS THE COMMISSION ON
ANY OF THE AGENDAED ITEMS SHOULD CONTACT THE
OFFICE OF THE EXECUTIVE DIRECTOR AT (850) 413-6463.
Attachment 1
State of Florida
JuhlkdStt&itt (1!~
CAPITAL CIRCLE OFFICE CENTER • 2540 SHUMARD OAK BOULEVARD
TALLAHASSEE, FLORIDA 32399-0850
-M-E-M -0-R-A-N-D-U-MDATE:
November 14, 2014
TO:
Braulio L. Baez, Executive Director
FROM:
Ana Ortega, Public Utility Analyst III, Division of Economics
Jim Breman, Senior Anal~st, Offic~ of In~u~t~y Developme~t and Market Analysi{JJ>
Judy G. Harlow, Economic Supervisor, DIVISIOn of Economics IJ1Jf{ ~w ·~·
Jim Dean, Director, Division of Economics
1·
Mark Futrell, Director, Office of Industry Development and Market Analysis7J?1Kathryn Cowdery, Senior Attorney, Office of the General Counsel ttL-_;O_{Yi ,C.
RE:
Draft Comments on the U.S. Environmental Protection Agency's Proposal to Limit
Carbon Emissions from Existing Electric Utility Generating Units.
~
+rJ
Critical Information: Please place on the November 25, 2014 Internal Affairs.
Commissioner approval of the attached comments is sought.
On June 18, 2014, the U.S. Environmental Protection Agency (EPA) published proposed
Carbon Pollution Emission Guidelines for Existing Electric Utility Generating Units (Clean
Power Plan) in the Federal Register and opened a comment period that was expected to end on
October 16, 2014. EPA subsequently announced an extension for accepting comments to
December 1, 2014.
Staff seeks approval of the draft comments to the EPA regarding the proposed carbon
rule (Attachment A). Staff provided the Commissioners with a briefing of the proposed rule at
the September 4, 2014 Internal Affairs meeting. During that Internal Affairs meeting,
Commissioners instructed staff to prepare comments to submit to the EPA regarding Floridaspecific concerns with the proposal. Staff has prepared the attached draft comments based on
Commissioner direction provided at the Internal Affairs meeting as well as other concerns with
the proposal.
On October 28, 2014, EPA issued a Notice of Data Availability (NODA) relating to the
Clean Power Plan. The purpose of the NODA was to highlight developing technical issues and
data related to the rulemaking and to provide additional areas for stakeholders to consider in their
comments. The NODA addressed issues relating to three aspects of the Clean Power Plan:
1) the glide path of emissions reductions from 2020-2029,
2) certain aspects of how the building blocks were established such as including new natural
gas combined cycles and the use of co-firing as a part of the Best System of Emission
Reduction and the possibility of phasing-in requirements of Building Blocks 1 and 2, and
1
(!Af
Braulio L. Baez
November 14, 2014
3) how state goals were calculated including the treatment of interstate renewable energy
generation and alternative approaches to applying the assumptions of Building Blocks 3
and 4.
On November 6, 2014, EPA also issued additional information regarding the translation
of the proposed rate-based targets to a mass-based target. This technical support documentation
outlined two methods for converting a state’s rate-based target to a mass-based equivalent target,
one relying solely on 2012 existing affected fossil-fuel generation and the other combining 2012
existing affected fossil-fuel generation and new fossil-fuel generation. This information does
not materially affect the draft comments.
Key Concerns and Recommendations to EPA:
A. FPSC Jurisdiction
•
•
Do not bypass or preempt the FPSC’s exclusive jurisdiction under Florida Statutes.
Defer to the Public Utility Regulatory Policies Act and Florida laws when calculating
renewable energy potential for Florida.
B. Best System of Emission Reduction (BSER)
•
•
The BSER has not been adequately demonstrated based on Florida policies and
circumstances.
Revise the BSER and set standards for affected EGUs based on specific technology and
equipment at these facilities or other onsite actions within a utility’s control.
C. Recognition of Early Actions in Florida
•
Adjust Florida’s requirements to reflect recent actions by Florida’s utilities that have
reduced carbon emissions.
D. Interim Performance Requirement
• Florida’s interim emission performance requirements should not be mandatory.
E. Corrections to Building Blocks
•
•
•
•
Modify Florida’s emission performance requirements applied to Florida’s coal-fired
generation to recognize prior actions taken to improve heat rates.
Correct Florida’s interim and final emission performance requirements to reflect the
natural gas combined cycle net, not gross, capacity.
A multi-year average baseline should be used instead of a single year in the development
of emission performance requirements.
EPA’s assumptions do not adequately account for changes to infrastructure that could
significantly affect the feasibility and cost of meeting the emission performance
requirements in the proposed timeframe.
2
Braulio L. Baez
November 14, 2014
•
•
Adjust the renewable energy generation requirement to reflect Florida-specific policies
and circumstances.
The EPA’s emission performance requirements should not include mandatory
implementation of end-use energy efficiency programs, but should allow for voluntary
inclusion within a State Implementation Plan.
F. FPSC Concerns Regarding Proposed Rule Implementation
•
The effects of EPA’s final rule should not compromise fuel diversity or electric system
reliability. Therefore, allow Florida to incorporate a reliability safety valve into its State
Implementation Plan to guard against unforeseen impacts on reliability and cost.
Attachment
cc: Lisa Harvey
Apryl Lynn
S. Curtis Kiser
3
DRAFT
Attachment A
UNITED STATES OF AMERICA
BEFORE THE
ENVIRONMENTAL PROTECTION AGENCY
Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility
Generating Units
Docket ID No. EPA-HQ-OAR-2013-0602
COMMENTS OF THE FLORIDA PUBLIC SERVICE COMMISSION
The Florida Public Service Commission (FPSC or Commission) appreciates the
opportunity to provide comments on the proposed Carbon Pollution Emission Guidelines for
Existing Stationary Sources: Electric Utility Generating Units, also referred to as the Clean
Power Plan (Proposed Rule).1 We recognize the necessity and role of the U.S. Environmental
Protection Agency (EPA) to address public health and environmental issues. The FPSC is
concerned, however, that the Proposed Rule in its current form will reduce fuel diversity,
adversely impact reliability, and impose unacceptable cost increases for a large number of
Florida’s electric consumers. Even with the clarifications provided with EPA’s October 2014
Notice of Data Availability (NODA), the structure of the rule is such that meaningful comments
require unique knowledge of the state compliance plan and predetermination of the reasonable
achievability of EPA’s modeled emission performance requirements. Without knowing the
structure of the State Implementation Plan, the FPSC cannot address the achievability of EPA’s
proposed emission performance requirements through EPA’s best system of emission reduction
(BSER) approach or any other compliance approach with certainty. The comments below
address the particular attributes of Florida and its electric industry, the FPSC’s statutory
authority, detailed concerns with the Proposed Rule, and areas of concern with Florida’s
proposed interim and final emission performance requirements.
These comments presume EPA will adopt carbon emission rules based on the strategy, or
a similar strategy, in the proposed rule notice. The Commission’s comments contained herein
1
The FPSC previously provided input into EPA’s development of proposed standards for carbon emission
reductions from existing sources by letter of December 13, 2013, The Florida Public Service Commission’s
Responses to EPA’s Questions to States Regarding the Design of a Program to Reduce Carbon Pollution from
Existing Power Plants (FPSC December 13, 2013 Comments).
4
DRAFT
Attachment A
are meant to request Florida-specific considerations for the application of that rule and should
not be construed as support or opposition to EPA adopting carbon emission rules.
FPSC Concerns and Recommendations to EPA:
A. FPSC Jurisdiction
•
•
Do not bypass or preempt the FPSC’s exclusive jurisdiction under Florida Statutes.
Defer to the Public Utility Regulatory Policies Act and Florida laws when calculating
renewable energy potential for Florida.
B. Best System of Emission Reduction (BSER)
•
•
The BSER has not been adequately demonstrated based on Florida policies and
circumstances.
Revise the BSER and set standards for affected EGUs based on specific technology and
equipment at these facilities or other onsite actions within a utility’s control.
C. Recognition of Early Actions in Florida
•
Adjust Florida’s requirements to reflect recent actions by Florida’s utilities that have
reduced carbon emissions.
D. Interim Performance Requirement
•
Florida’s interim emission performance requirements should not be mandatory.
E. Corrections to Building Blocks
•
•
•
•
•
Modify Florida’s emission performance requirements applied to Florida’s coal-fired
generation to recognize prior actions taken to improve heat rates.
Correct Florida’s interim and final emission performance requirements to reflect the
natural gas combined cycle net, not gross, capacity.
A multi-year average baseline should be used instead of a single year in the development
of emission performance requirements.
Adjust the renewable energy generation requirement to reflect Florida-specific policies
and circumstances.
The EPA’s emission performance requirements should not include mandatory
implementation of end-use energy efficiency programs, but should allow for voluntary
inclusion within a State Implementation Plan.
F. FPSC Concerns Regarding Proposed Rule Implementation
•
The effects of EPA’s final rule should not compromise fuel diversity or electric system
reliability. Therefore, allow Florida to incorporate a reliability safety valve into its State
Implementation Plan to guard against unforeseen impacts on reliability and cost.
5
DRAFT
Attachment A
I.
FPSC Jurisdiction
The FPSC is charged with ensuring that Florida’s electric utilities provide safe, reliable
energy for Florida’s consumers in a cost-effective manner. The FPSC regulates five investorowned electric utilities, including aspects of rate setting, operations, and safety. The FPSC
additionally regulates 35 municipally-owned and 18 rural electric cooperatives as to safety, rate
structure, and oversight of generation and transmission planning.
The FPSC’s exclusive jurisdiction in Florida includes jurisdiction to require electric
power conservation and reliability within a coordinated grid, for operational as well as
emergency purposes.2 The FPSC has exclusive jurisdiction over the planning, development, and
maintenance of a coordinated electric power grid throughout Florida to assure an adequate and
reliable source of energy and the avoidance of further uneconomic duplication of generation,
transmission, and distribution facilities.3 The FPSC is charged with determining need for all new
steam electric generating facilities and solar generation over 75 megawatts (MW).4 The FPSC
has the responsibility of allowing an electric utility’s recovery from ratepayers of prudently
incurred environmental compliance costs, including costs incurred in compliance with the Clean
Air Act.5
In addition, the FPSC has exclusive jurisdiction to implement the Florida Energy
Efficiency and Conservation Act (FEECA).6 FEECA emphasizes reducing the growth rates of
weather-sensitive peak demand, reducing and controlling the growth rates of electricity
consumption, and reducing the consumption of expensive resources, such as petroleum fuels.
Pursuant to FEECA, the FPSC has authority to adopt goals for increasing the efficiency of
energy consumption and increasing the development of demand-side renewable energy systems.7
Importantly, in adopting these goals, the FPSC evaluates the full Florida-specific technical
potential of all available demand-side and supply-side conservation and efficiency measures, and
takes into consideration the costs and benefits to participating customers and ratepayers as a
2
Section 366.04(2)(c), Florida Statutes
Section 366.04(5), Florida Statutes
4
Section 403.519, Florida Statutes
5
Section 366.8255(2), Florida Statutes
6
Sections 366.80 – 366.82, Florida Statutes
7
Section 366.81, Florida Statutes
3
6
DRAFT
Attachment A
whole, and the costs imposed by state and federal regulations on greenhouse gas emissions.8
Once goals are established, the utilities must submit for Commission approval cost-effective
demand-side management (DSM) plans, which contain the DSM programs designed to meet
these goals. Among its powers, the FPSC may modify or deny demand-side management plans
or programs that would have an undue rate impact from the costs passed on to customers.9
The Florida Legislature has established policies to encourage the development of
renewable energy resources and to ensure these resources contribute to reliable electric service at
a reasonable cost. Florida law requires utilities to facilitate customer-owned renewable energy
resources through standard interconnection agreements and net metering.10 The Public Utility
Regulatory Policies Act (PURPA) and Florida law establish requirements relating to the
purchase of capacity and energy by investor-owned utilities from renewable energy producers.11
Utilities must purchase capacity and energy at rates that do not exceed the respective utility’s
avoided cost, thus protecting customers from undue rate impacts. Also, renewable energy
producers, which are able to meet minimum performance requirements during a respective
utility’s peak demand period, are eligible for fixed capacity payments. Investor-owned utilities
may recover from customers prudent and reasonable costs associated with renewable energy
purchase power agreements. PURPA and Florida law provide the legal framework for the
interconnection and economic parameters to develop renewable energy. Therefore, the EPA
must defer to existing federal and state-specific policies in its calculation of renewable energy
potential for Florida and other states.
The EPA’s authority to propose pollution control regulations is limited by the scope of its
delegated authority granted under the Clean Air Act (CAA).12 The CAA authorizes EPA to
promulgate regulations on carbon dioxide (CO2) emissions only as they relate to pollutant
emissions. The EPA is not granted regulatory authority over Florida’s planning, development,
and maintenance of a coordinated electric power grid, electric power energy efficiency and
8
Section 366.82(3), Florida Statutes
Section 366.82(7), Florida Statutes
10
Section 366.91(5) and (6), Florida Statutes
11
Sections 366.051 and 366.91(3), Florida Statutes
12
E.g., City of Park City v. Alon USA Energy Inc. (In re Methyl Tertiary Butyl Ether Prods. Liab. Litig), 341 F.
Supp. 2d 386, 406-408 (S.D.N.Y. 2004), citing to Fidelity Fed. Savs. and Loan Association de la Cuesta, 458 U.S.
141, 154 (1982). See also City of Arlington v. FCC, 133 S. Ct. 1863, 1869 (2013) (The power of agencies charged
with administering congressional statutes to act and how they are to act is authoritatively prescribed by Congress).
9
7
DRAFT
Attachment A
conservation, or the development of renewable energy resources in Florida. For this reason, the
FPSC’s exclusive jurisdiction in these areas is not subject to preemption by the CAA, and the
proposed rules may not interfere with, pre-empt, or in any manner attempt to or effect a shift of
the Commission’s jurisdiction to EPA or to any other federal or state agency or department.
Additionally, the FPSC supports the National Association of Regulatory Utility
Commissioners Resolution on Increased Flexibility with Regard to the EPA’s Regulation of
Greenhouse Gas Emissions from Existing Power Plants that states: “EPA should not intrude on
the states’ jurisdiction over decisions regarding integrated resource planning or the mix of fuels
and resources.”13 The proposed emission performance requirements set by EPA necessarily
require compliance and enforcement activities that include changing dispatch methodology,
efficiency measures, the type of generation to be constructed, and renewable energy
considerations, all of which are matters within the FPSC’s exclusive jurisdiction. Intrusion by
EPA into these matters directly through a Federal Implementation Plan or by proxy through a
State Implementation Plan would interfere with the FPSC’s jurisdiction over the generation and
distribution of electricity, Florida’s electricity grid, and economic regulation of electric retail
service. Any changes to this exclusive jurisdiction are a matter for consideration by the Florida
Legislature.
II.
Best System of Emission Reduction (BSER)
The FPSC is greatly concerned with the methodology EPA used to set the BSER and the
resulting Florida performance requirements for existing electric generating units (EGUs). As
previously noted, EPA’s assumptions and analysis supporting its Proposed Rule, and the Florida
CO2 pounds per megawatt-hour (lbs./MWh) emission performance requirements presume an
implementation strategy that either bypasses or preempts the FPSC’s exclusive jurisdiction under
Chapters 366 and 403, Florida Statutes. The EPA’s Proposed Rule establishes CO2 lbs./MWh
emission performance requirements using national or regional averages rather than assessing
what is reasonable and technically achievable in Florida. Moreover, EPA did not consider
13
http://www.naruc.org/Resolutions/EPAsRegulationofGreenhouseGasEmissionsfromExistingPowerPlants.pdf.
8
DRAFT
Attachment A
Florida-specific policies in developing the Proposed Rule.
The CAA requires EPA to set
proposed emissions performance requirements to reflect:
the degree of emission limitation achievable through the application of the best
system of emission reduction which (taking into account the cost of achieving
such reduction and any non-air quality health and environmental impact and
energy requirements) the Administrator determines has been adequately
demonstrated.14 (emphasis added).
When establishing a performance standard based on a BSER determination, EPA must
consider among other factors, the system of emission reduction that is technically feasible15 and
the economic costs to the industry.16 The emission performance requirements must be based on
relevant and adequate data, and technology must be achievable for standards promulgated by
EPA.17 Further, “To be achievable, a standard must be capable of being met under the most
adverse conditions which can reasonably be expected to recur.”18
The FPSC contends that EPA’s proposed BSER in its current form is unreasonable,
extremely difficult to achieve both in scope and timeline, and should not be used to set an
emissions performance requirement for Florida. While EPA’s NODA goes in the direction of
acknowledging some of these concerns, it does not provide solutions. The FPSC’s comments are
intended to offer such solutions.
The proposed emission performance requirements for Florida are not based on a BSER
that has been adequately demonstrated, as required by Section 111(d).
An adequately
demonstrated system is one that has been shown to be reasonably reliable, reasonably efficient,
and that can reasonably be expected to serve the interest of pollution control without becoming
exorbitantly costly in an economic or environmental way.19 The EPA’s basis for stating that its
BSER analysis is adequately demonstrated is that each of the building blocks may be well-
14
CAA, Section 111(a)(1); 40 CFR 60.21(e).
Essex Chemical Corp v. Ruckelshaus, 486 F. 2d 427, 433-434 (D.C. Cir 1973)(stating that an achievable standard
is one which is within the realm of the adequately demonstrated system’s efficiency and which need not necessarily
be routinely achieved within the industry prior to its adoption), cert denied, 416 U.S. 969 (1974).
16
Portland Cement Association v. Ruckelshaus, 486 F. 2d 375, 385, 402 (D.C. Cir. 1973), cert. denied 417 U.S. 921
(1974).
17
Id. p. 393.
18
White Stallion Energy Ctr., LLC v. EPA, 748 F. 3d 1222 (S.D. Cal. 2014), citing to Nat’l Lime Association v.
EPA, 627 F. 2d 416, 431 n. 46, 200 US App. DC 363 (D.C. Cir. 1980).
19
Essex Chemical Corp. 486 F. 2 p. 433.
15
9
DRAFT
Attachment A
established in some, but not all states.20 This basis fails to take into account the Florida-specific
factors discussed throughout these comments. The disclaimer in the Notice of Rulemaking that
none of the building blocks in the BSER “are being mandated, the states are free to use any
compliance strategy” does not alleviate Florida’s concerns.
As a part of the FPSC’s analysis of the Proposed Rule, the FPSC solicited comments
from Florida’s generating utilities and other interested persons.21 Based in part on the responses,
the FPSC believes that EPA’s CO2 emission performance requirements for Florida cannot be met
solely by increased efficiency of operating coal-fired units, increased dispatch of natural gasfired electrical units, and decreased use of coal-fired EGUs. The Proposed Rule would require
Florida’s utilities to attempt to implement all of the proposed building blocks, despite the fact
that these proposed requirements do not take into account Florida’s specific policies and
circumstances.
This combination of actions has not been adequately demonstrated as an
effective approach to achieve EPA’s proposed emission performance requirements for Florida.
Consistent with the FPSC’s December 13, 2013 Comments in this proceeding, the FPSC
continues to maintain that EPA should set Florida’s emission performance requirement based
solely on onsite actions at affected EGUs. As evidenced by both emission rates and mass ton
reductions, Florida utilities have made great progress in CO2 reductions in recent years by
repowering existing units and adding efficient natural gas combined cycle units. The EPA
should only rely on existing EGUs, including the past actions of these EGUs, in establishing
reasonable CO2 reductions.
Since 1981, the FPSC has established DSM and energy efficiency goals for the utilities
serving 85 percent of Florida’s load. The EPA’s national application of energy efficiency
reductions based on existing and new load growth, however, is not an appropriate standard
setting strategy.
Likewise, PURPA and Florida law provide the legal framework for the
development, interconnection, and economic parameters of renewable energy. The EPA must
defer to existing federal and state-specific policies in its calculation of renewable energy
potential for Florida and other states.
The FPSC, however, strongly believes EPA lacks
jurisdiction to include Building Blocks 3 and 4 in its BSER and the proposed emission
20
U.S. Environmental Protection Agency Legal Memorandum on Proposed Carbon Pollution Emission Guidelines
for Existing Electric Utility Generating Units. p. 15.
21
http://www.floridapsc.com/utilities/electricgas/EPAcarbonrules/
10
DRAFT
Attachment A
performance requirements. For these reasons, EPA should revise its BSER and the emission
performance requirements to be based exclusively on onsite actions at affected EGUs.
The FPSC also believes it is inappropriate to select a single year (2012) in the
development of emission performance requirements. This approach does not take into account
anomalies affecting the dispatch of generation in a given year, that could occur in a particular
state or market. For example, 2012 was not a typical year for electricity generation in Florida as
historically low natural gas prices caused an unusual increase in the use of natural gas-fired
generation. During a normal year, more coal-fired generation would have been dispatched,
resulting in a higher CO2 annual emission rate for the state. This is particularly true for utilities
which are more dependent on coal-fired generation. Therefore, EPA’s use of 2012 as the starting
point skews the emissions performance requirements for Florida. The use of a multi-year
average when setting the baseline data can dampen the effect of any electric market production,
weather, or fuel supply anomaly that may occur in a single year.
III.
Recognition of Early Actions in Florida
In the FPSC’s December 13, 2013 Comments in this proceeding, the FPSC asserted that
EPA’s guidelines should avoid setting a performance level that is based on a national uniform
approach and recognize the varying characteristics of specific states and regions of the U.S. By
applying national averages in establishing state-specific emission performance requirements,
EPA did not accurately reflect Florida’s ability to comply with the Proposed Rule. The EPA’s
Proposed Rule does not consider past utility actions by Florida’s utilities that were made to
improve overall generating efficiency. These past actions have had a beneficial impact on air
quality and have resulted in permanent CO2 emission reductions per MWh. Failure by EPA to
consider these early actions is unreasonable.
The proposed emission performance requirements would result in a 38 percent reduction
in CO2 emissions from the 2012 baseline year. This, in effect, penalizes Florida for having taken
early actions to reduce CO2 emissions by requiring stringent, and more difficult to attain,
emission performance requirements relative to EPA’s 2012 baseline year. The long history of
early actions in Florida that has contributed to the declining CO2 emissions restricts the technical
11
DRAFT
Attachment A
feasibility of meeting the national assumptions in EPA’s proposed building blocks. The Florida
Department of Environmental Protection, for example, estimates that Florida’s average CO2
emissions profile, for power produced in Florida, decreased from 1,718 lbs./MWh in 2005 to
1,291 lbs./MWh in 2012, a 25 percent reduction in CO2 emission rates. The requirement of an
additional 38 percent reduction is unreasonable.
Florida’s utilities have invested in generation efficiency improvements, repowerings, and
nuclear uprates, which have had a beneficial impact on Florida’s average CO2 emissions profile.
In addition, Florida’s utilities have invested heavily in compliance with other recent EPA air
rules, including Mercury Air Toxics Standards and the Cross-State Air Pollution Rule. Florida’s
ratepayers have borne the costs for these investments. As a result, a significant portion of costeffective actions to lower emissions that are under each utility’s control has already been
achieved through regulatory and market driven responses. The FPSC urges EPA to adjust
Florida’s emission performance requirements to reflect a BSER that can be achieved in Florida
and accounts for past utility actions.
IV.
Interim Performance Requirement
The FPSC believes the aggressive compliance timeframe is unrealistic. The proposed
interim emission performance requirement for Florida is only marginally different from the final
requirement, and requires a substantial proportion of the 2030 requirement CO2 emissions
reductions to occur beginning in 2020. Although EPA outlines a few avenues for states to have
additional time for submitting their compliance plans, the Proposed Rule does not allow
corresponding flexibility in the interim performance period. Regardless, Florida will have had to
make compliance decisions before there is certainty of EPA’s final rule and before having an
approved state implementation plan.
Compliance with the proposed emission performance
requirements necessitates long-term decisions and investments, potential legislative action, and
must account for the statutory timing of siting and constructing new generation, transmission,
and pipeline capacity that will likely be needed.
Under Florida’s existing statutory and
regulatory regimes, the State as a whole will not be able to achieve EPA’s proposed emission
performance requirements within EPA’s timeline.
12
DRAFT
Attachment A
Compliance with EPA’s proposed emission performance requirements will likely take
more time than EPA envisioned. Particularly problematic is the time required to complete the
necessary infrastructure improvements. Two recent examples are illustrative of project timing in
Florida. A proposed nuclear project in southern Florida was originally scheduled to complete the
Florida Site Certification Application review within 14 months, yet the review schedule was
waived and ultimately extended to almost 60 months.22 The protracted timeline was required in
order to address concerns stemming from electric transmission expansion.
In 2013, the
Commission approved as prudent, a utility’s request to enter into a long-term gas transportation
contract associated with the proposed Sabal Trail pipeline, which is not expected to commence
natural gas delivery until 2017.23 Whether these cases are typical of future projects is uncertain;
however, they illustrate that three years may not be sufficient time to study, permit, and complete
infrastructure additions necessary to comply with the interim emission performance
requirements. The EPA’s 2020 threshold date appears to be more aspirational than realistic
when one considers the scope of detailed reviews and justification necessary to support
additional power plants, transmission, and pipeline investments that could be needed. The FPSC
notes that EPA’s NODA appears to recognize the need for increased flexibility to address the
timing of various infrastructure projects.
The FPSC asserts that even with the flexibility of expanding timelines, Florida’s interim
emission performance requirements should not be mandatory. Florida’s interim goals, used for
tracking or reporting, should be established during the state implementation plan development
process.
This will allow Florida to review appropriate actions to mitigate the impacts of
premature retirements of certain generating units. Florida and the affected entities should be
given
a
more
flexible
glide
path
toward
22
the
ultimate
performance
requirement.
http://www.doah.state.fl.us/ALJ/searchDOAH/default.asp, Florida Division of Administrative Hearings Case No.
09003575.
23
Order No. PSC-13-0505-PAA-EI, in Docket No. 130198-EI, issued October 28, 2013, In re: Proposed Agency
Action Order on Florida Power & Light Company’s Proposed Sabal Trail Transmission, LLC and Florida Southeast
Connection Pipelines.
13
DRAFT
Attachment A
V.
Corrections to Building Blocks
The following analysis addresses each Building Block individually to illustrate how
EPA’s assumptions of the building blocks used to establish the BSER are not technically feasible
and would result in unreasonable costs. Any suggestion to one particular Building Block should
not be interpreted as support to expand other Building Blocks to make up any emissions
reduction shortfalls due to the interactive effects between the various Building Blocks and
potential operational constraints as discussed throughout our comments.
a. Building Block 1
In Building Block 1, EPA assumes that Florida will achieve CO2 reductions through a six
percent heat rate improvement at its coal-fired generating units. The FPSC contends that the
national assumption of a heat rate improvement of six percent for Florida’s coal-fired generating
fleet is not technically feasible, given the long history of efficiency improvements to Florida’s
fleet. In 1980, the FPSC developed a generating performance incentive factor program (GPIF)
for investor-owned utilities,24 which encourages utilities to maximize unit heat rate efficiency of
electric baseload generating units. Unit specific heat rate and availability requirements are set
annually through a formal hearing procedure, and the FPSC has the authority to reward utilities
that reach their requirements and penalize those utilities that do not. Effectively, the GPIF
program provides multi-million dollar incentives for utilities to maximize supply-side energy
efficiency improvements, thus reducing average fuel consumed per MWh at the source of air
emissions.
In over 30 years of offering incentives, the FPSC has not seen consistent heat-rate
improvements in the six percent range as suggested in the Proposed Rule. In the last five years
alone, changes in EGU specific heat rate efficiencies ranged from negative eight percent to
positive four percent, even with the GPIF program incentives. These fluctuations appear to be
driven, in part, by efforts to comply with environmental requirements. Rather than relying on an
across the board six percent assumption, we propose a more Florida-specific analysis of
achievable, permanent and cost-effective CO2 emission reductions. Such an analysis will take
24
Order No. 9558, in Docket No. 800400-CI, issued September 19, 1980, In re: Investigation of Fuel Cost Recovery
Clause Application to Investor-owned Electric Utilities.
14
DRAFT
Attachment A
into account, not only potential for heat rate improvements (which can be verified through
historical data under incentive programs like the GPIF program), but also steps already taken to
increase efficiencies in Florida’s fleet relative to EPA’s baseline year.
The EPA has not adequately demonstrated the feasibility of the proposed emission
requirements for Florida. This is supported in part by a recent communication by Sargent &
Lundy, LLC, which prepared a study on heat rate improvement that was relied on by EPA in its
technical support documentation. Sargent & Lundy, LLC, states that its 2009 report on heat rate
improvements “did not conclude that any individual coal-fired EGU or aggregation of coal-fired
EGUs can achieve six percent heat rate improvement or any broad target, as estimated by
EPA.”25 Moreover, Sargent & Lundy, LLC, notes that the feasibility of heat rate improvements
at an individual generating unit are limited by “a number of factors, including plant design,
previous equipment upgrades, and each plant’s operational restrictions.”26
The FPSC also questions the reasonableness of investing in heat rate improvements only
to then retire the plants based on the re-dispatch assumptions in Building Block 2 and the 2020
interim performance requirements. The EPA fails to adequately address the inconsistency of
using heat rate improvements in coal-fired units to calculate Building Block 1 savings, only to
then substantially negate those savings by re-dispatching from those improved coal-fired units to
natural gas-fired units for the savings presented in Building Block 2. While EPA’s NODA
appears to allow recognition of the remaining book life, EPA did not identify any corresponding
changes to its proposed state interim and final emission performance requirements. The EPA
should allow certain coal units with long, undepreciated remaining useful lives to be exempt
from an interim emission performance requirement and relax the 2030 requirement, as long as
these units are brought into compliance with the state implementation plan at the end of their
useful lives. This would ameliorate much of the stranded cost burden associated with a strict
adherence to a 2030 compliance date. If EPA does not modify the assumptions of Building
Block 1 in the proposed BSER, the rapid retirement of coal-fired generation due to the redispatch envisioned in Building Block 2 would cause significant costs for Florida and its
ratepayers in terms of stranded assets.
25
Letter from Raj Gaikward Ph.D., VP Sargent & Lundy to Mr. Rae Cronmiller, National Rural Electric
Cooperative Association.
26
Id.
15
DRAFT
Attachment A
b. Building Block 2
In EPA’s calculation of Building Block 2, EPA states that Florida’s natural gas-fired
combined cycle (NGCC) plants operated at a capacity factor of 51 percent.27 Based on EPA’s
assumptions of an increase in NGCC capacity factor from 51 percent to 70 percent of capacity,
EPA calculates a re-dispatch of existing 2012 NGCC generation that would result in CO2
emission reductions. EPA’s characterization that Florida’s NGCC fleet operated at a “51 percent
capacity factor” in 2012 is incorrect due to EPA’s use of nameplate capacity. When discussing
generator capacity, system planners and regulators distinguish generator capacity from
nameplate capacity for important reasons. A generator’s nameplate capacity is “the maximum
rated output of a generator, prime mover, or other electric power production equipment under
specific conditions designated by the manufacturer.”28 By contrast, the generator capacity is “the
maximum output, commonly expressed in MW, that generating equipment can supply to system
load, adjusted for ambient conditions.”29 The EPA states it wanted to use net generating capacity
but asserts, incorrectly, that net capacity data was not readily available.30 Therefore, EPA’s
choice to use nameplate capacity for purposes of assessing annual capacity factors is not
supported by its referenced material.31,
32
The FPSC contends that EPA should revise its
calculations of assumed reductions under Building Block 2 to reflect the 2012 natural gas
combined cycle net, not gross capacity.
The EPA’s proposal does not identify the consequences on Florida’s electric service
reliability, transmission load flow, or the scheduling of how its program of displacing existing
27
U.S. Environmental Protection Agency, Data File: Goal Computation – Appendix 1 and 2,
http://www2.epa.gov/carbon-pollution-standards/clean-power-plan-proposed-rule-technical-documents (last updated
June 26, 2014).
28
U.S. Energy Information Administration, Glossary: Generator nameplate capacity,
http://www.eia.gov/tools/glossary/index.cfm?id=G (last visited July 18, 2014).
29
U.S. Energy Information Administration, Glossary: Generator capacity,
http://www.eia.gov/tools/glossary/index.cfm?id=G (last visited July 18, 2014).
30
U.S. Environmental Protection Agency, GHG Abatement Measures, 3-6 (June 2014). The U.S. Energy
Information Agency’s database of Forms EIA-860 contains summer and winter capacities for facilities across the
U.S. The EPA even refers to Form EIA-860 elsewhere in the GHG Abatement Measures; therefore, it is
inexplicable that the EPA chose to use the theoretical nameplate capacity over the known and modeled
summer/winter capacities reported in the documents the EPA used to perform the BSER analysis.
31
Id.
32
U.S. Energy Information Administration, Form EIA-860 for 2012, available at
http://www.eia.gov/electricity/data/eia860/index.html (last visited July 18, 2014).
16
DRAFT
Attachment A
coal-fired baseload facilities could reasonably be implemented.33 Florida’s coal-fired facilities
and NGCC facilities are not typically co-located nor generally located within the same utility
system. In Florida, the existing transmission system has not been developed with the expectation
that NGCC facilities would displace all or most of the baseload coal-fired facilities.
Consequently, it would be necessary to conduct a Florida-specific transmission study to assess
the full effects of such a program, which the EPA does not appear to have included in its
reference material or factored into the proposed compliance schedule. EPA’s NODA appears to
acknowledge these are significant and material issues. However, no changes to the Proposed
Rule were presented. While EPA has assumed future wholesale level transactions between
reliability regions, EPA has not provided the FPSC with any support documentation of electric
reliability within the Florida Reliability Coordinating Council region and the potential impacts to
each of the Florida cooperative, municipal, and investor-owned systems. Absent this type of
data, the FPSC does not believe that electric reliability will be maintained if the Proposed Rule is
implemented.
c. Building Block 3
The EPA’s adoption of North Carolina’s renewable energy and energy efficiency
portfolio standard (REPS) for Florida does not realistically reflect the available renewable
resources or policy framework in Florida. For example, Florida lacks viable wind resources and
has limited biomass opportunities, given competing industrial use of biomass resources.34
Furthermore, EPA has not clarified whether biomass can be used as a compliance option. If this
uncertainty is not resolved, Florida may be limited to the use of solar powered generation. The
FPSC believes EPA should provide guidance as to how it intends to treat biomass generation,
including municipal solid waste, to meet emission performance requirements.
Additionally, EPA elected to group Florida with Alabama, Georgia, Kentucky,
Mississippi, North Carolina, South Carolina, and Tennessee to form its modeled Southeast
region for the purpose of assigning its assumed achievable renewable energy generation
requirement. Of that group, North Carolina is the only state that has a REPS requirement. The
33
http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v513/HRI%20Appendix.pdf and
http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v513/Chapter_3.pdf
34
Florida Department of Agriculture and Consumer Services, Division of Forestry, Woody Biomass Economic
Study, March 10, 2010.
17
DRAFT
Attachment A
FPSC contends that EPA has overestimated the assumption for potential renewable energy
generation for its southeast region by misinterpreting North Carolina’s REPS.35 As a part of
North Carolina’s REPS, the state’s investor-owned utilities are allowed to utilize energy
efficiency programs to achieve up to 25 percent of the annual renewable goal increasing to a
maximum of 40 percent in 2021. Additionally, North Carolina’s REPS allows municipal and cooperative utilities to use energy efficiency programs to achieve all of their annual renewable
goals. By using North Carolina’s REPS as a component of the BSER, EPA has double-counted
the use of energy efficiency, given the interaction between Building Blocks 3 and 4.
The EPA appears to acknowledge the importance of incorporating renewable energy
generation based on the actual potential for each state. The approach described in the technical
support documentation “Alternative Renewable Energy Approach” may be closer to representing
state realities as it relies in part on a technical potential study conducted by National Renewable
Energy Laboratory.36 This approach, however, falls short due to the use of EPA’s Integrated
Planning Model (IPM) to evaluate market potential of each type of renewable generation based
on a regional dispatch area and the use of an estimated incremental cost of renewables. The EPA
did not provide information regarding the impact on the alternative approach to the emission
performance requirements for Florida, specifically whether the adoption of the alternative
approach would affect the other Building Blocks.
In November, EPA released examples on how to convert the rate-based performance
requirement to an equivalent mass-based standard. The calculations show that EPA’s BSER for
existing EGUs presumes that all growth in renewable generation displaces generation from
existing EGUs, rather than avoiding new fossil generation. This is not a realistic assumption for
Florida. Consequently, EPA overstates the level of future renewable generation reasonably
attributable to existing affected EGUs. If EPA continues to include renewable generation in
establishing emission standards, then it should explicitly set standards for renewable generation
that directly displaces existing affected EGU generation.
Furthermore, it appears that EPA has not taken into account requirements under PURPA
and Florida law regarding the purchase of renewable energy by Florida utilities. The FPSC is
35
36
N.C. Gen. Stat. Section 62-133.8 (2013).
http://www2.epa.gov/sites/production/files/2014-06/documents/20140602tsd-alternative-re-approach.pdf
18
DRAFT
Attachment A
required by these laws to take into account the utility’s avoided cost when reviewing the
purchase of renewable energy generation. The FPSC asserts that federal and Florida law, along
with the technical feasibility of renewables in Florida (not in North Carolina or the region),
should determine the extent of renewable generation that could be developed and used to offset
emissions from fossil sources.
d. Building Block 4
The EPA’s BSER determination should not include reductions attributable to energy
efficiency programs because these programs are not under the direct control of the utility and
cannot be traced to solely offsetting CO2 emissions from existing affected EGUs. The EPA
would need to demonstrate a direct correlation to a specific affected EGU using a generating
unit-by-generating unit analysis. To the best of the FPSC’s understanding, EPA has yet to
perform such an analysis. Florida should, however, have the discretion to comply with any
standards by utilizing cost-effective end-use energy efficiency programs that can be
demonstrated to permanently reduce CO2 emission at an affected EGU, while also not sacrificing
reliability or resulting in excessive cost impacts.
If EPA continues to include energy efficiency as a component of its BSER, it should
modify Florida’s energy efficiency requirement to reflect Florida-specific realities. The EPA’s
proposed ten percent reduction in net retail electric sales as a result of Building Block 4 is
unreasonable, in terms of both proposed cost and achievability, based on Florida’s actual historic
data. In over 30 years of offering demand-side management and energy efficiency programs, the
FEECA utilities have reduced winter peak demand by an estimated 6,465 MW and reduced
annual energy consumption by an estimated 8,937 GWh. In 2012, FEECA utilities achieved an
annual energy consumption reduction of 482.3 GWh. However, the FPSC has found that energy
efficiency programs capable of achieving savings of ten percent are not cost-effective.
Additionally, the ten percent MWh savings requirement is becoming increasingly
difficult because federal and state energy efficiency standards and building codes have become
more stringent, leaving less energy savings potential from utility or other third party actions.
Setting an emission performance requirement without considering the Florida-specific technical
or achievable potential or the cost-effectiveness of the necessary programs to achieve the
requirement is contrary to Florida Statutes and the CAA.
19
DRAFT
Attachment A
VI.
FPSC Concerns Regarding Proposed Rule Implementation
Electricity usage in Florida is impacted by the state’s unique weather, customer base, and
high reliance on electricity for cooling and heating. Florida has the highest number of cooling
degree days of any state in the continental U.S., indicating the greatest need for air conditioning
in the summer months. Compared to other states, Florida’s customers rely more heavily on
electricity to meet their energy needs, rather than the direct use of natural gas or other fuels, for
cooling and heating. Residential consumers make up almost 89 percent of Florida’s electricity
customers. Approximately 85 percent of Florida’s residential customers’ energy requirements
are met with electricity, which makes Florida’s customers particularly sensitive to electric rate
increases. This, combined with Florida’s geography and climate, requires the FPSC to carefully
examine all factors related to electricity generation to ensure cost-effective, reliable electricity
for all Floridians.
a. Fuel Diversity Consequences
In 2012, Florida utilities had a net summer generating capacity of 57,454 MW.37
Transmission capability to import energy into peninsular Florida from other states is
approximately 3,600 MW. Florida’s reliance on natural gas as a generation fuel has significantly
increased over time and has resulted in a state policy to seek greater diversification in our fuel
mix. Currently, approximately 60 percent of the electric power in Florida is generated from
natural gas. The concern with Florida’s current dependency on natural gas generation pales in
comparison to EPA’s modeled projection that by 2025 Florida will be using natural gas
generation to serve 85 percent of load.38
Florida law requires the FPSC to determine the need for new generating facilities and
specifically to consider the need for electric system reliability and integrity, adequate electricity
at a reasonable cost, and the need for fuel diversity and supply reliability.39 It is important for
Florida to maintain a diversified generation fuel source mix when seeking to comply with
relevant CO2 standards because a diversified fuel supply can enhance system reliability and
37
Florida Public Service Commission, Facts and Figures of the Florida Utility Industry (Mar. 2014) p. 1.
http://www.floridapsc.com/publications/pdf/general/factsandfigures2014.pdf
38
EPA’s “Parsed File” Option 1 State, 2025.
39
Section 403.519(3), Florida Statutes.
20
DRAFT
Attachment A
significantly mitigate the effects of volatile fuel price fluctuations, extreme weather events and
unplanned plant outages. Additional pipeline capacity would have to be built to accommodate a
further reliance on natural gas as a generating fuel. One of Florida’s primary pipelines crosses
the Gulf of Mexico and is subject to some risk of hurricanes, which adds to the concern of
diminished fuel diversity.
b. Reliability Consequences
The FPSC is also concerned about the impact of additional intermittent resources on
service reliability requirements. Because of the state’s unique characteristics described earlier,
Florida requires a robust, diverse, and dispatchable baseload generating fleet. However, many of
the low- or zero-carbon technologies EPA assumes in its Building Block 3 allocation to Florida
are intermittent, non-dispatchable, non-baseload technologies.
For example, in 2013, the
monthly capacity factor for solar photovoltaics in the U.S. ranged from 13 to 22 percent.40 Due
to operational constraints from the availability of sunshine, there is no currently demonstrated
baseload solar option. The low capacity factors of many low- or zero-carbon technologies
(excluding nuclear and possibly co-firing with biomass) combined with Florida’s need for
dispatchable baseload generation means that Florida would likely need to build additional natural
gas-fired facilities and related infrastructure for use as stand-by units for reliability purposes
simply because of EPA’s assumed requirement.41 A recent report assessing Germany’s efforts to
increase renewable generation resources noted an expected cost increase associated with redispatch, curtailment, and other remediation actions necessary to maintain reliability.42 EPA errs
in failing to account for these additional expenditures or the implementation time needed to
ensure electric reliability.
c. Need for Safety Valve
Given the untested approach EPA has used in developing the BSER and the broad
application of non-state specific assumptions, there remains considerable uncertainty about the
ability of states to comply with these stringent performance requirements. Such uncertainty calls
for some type of off-ramp or safety valve for those states that – despite their best efforts – cannot
40
U.S. Energy Information Agency, Electric Power Monthly (February 2014), Table 6.7.B. available at
http://www.eia.gov/electricity/monthly/current_year/february2014.pdf.
41
http://www.brattle.com/system/publications/pdfs/000/005/060/original/Solar_Energy_Support_in_Germany__A_Closer_Look.pdf?1406753962.
42
Id, pp. 28-37.
21
DRAFT
Attachment A
fully comply with the performance requirements. Safety valve modifications could take the form
of a relaxation of the performance requirements, exemptions for must run or critically needed
units, or extension of time to meet the 2030 requirement. State Implementation Plans should be
allowed to include such provisions to guard against unforeseen impacts on reliability and cost. It
is imperative that any rule EPA adopts contain such flexibility.
d. Cost of Proposal
At this time, states cannot even begin to develop reliable estimates of compliance costs
with the Proposed Rule. Without knowing the final requirements of an EPA approved State
Implementation Plan, individual utilities will not be able to determine their most cost-effective
compliance path. In turn, states will not be able to develop aggregate costs resulting from
consolidation and coordination of each utilities’ compliance plans across the state. However, the
Commission is confident that if EPA’s proposed BSER is not revised, the stringent emission
performance requirements will require substantial compliance costs for Florida. These costs
include compliance costs assumed in the Building Blocks and additional costs such as the
building of new natural gas pipelines, the building of new generation, the possible improvements
and/or building of new transmission lines, and the cost of stranded assets resulting from the
premature retirement of existing baseload generation.
Therefore, any estimate of compliance
costs may be grossly understated at this time.
Preliminary estimates from the Florida Electric Power Coordinating Group,
Environmental Committee, support the conclusion that EPA may have understated the potential
range in its estimated direct and indirect costs. These results show that average statewide retail
rates could increase by 25 to 50 percent by 2030 above a business as usual case as a result of the
Proposed Rule.43 This estimated range of potential impact is necessarily based on idealized and
simplifying assumptions for high-level screening purposes.
43
Florida Electric Power Coordinating Group, Environmental Committee, Impact of EPA’s CO2 Proposal on
Florida’s Electric Generation System, October 2014.
22
DRAFT
Attachment A
VII.
Conclusion
We recognize the necessity and role of EPA to address public health and environmental
issues. However, as discussed throughout these comments, the proposed emission reductions do
not reflect what is technically or economically feasible in Florida. There are at least three
critically needed revisions before EPA moves forward with the Proposed Rule.
First, EPA
should set performance requirements on affected EGUs subject to Section 111(d) and those
requirements should be established for these EGUs based on specific technology and equipment
at these facilities or other onsite actions within the control of a utility. Second, any components
of the BSER should be based on Florida-specific policies and circumstances, rather than using
national and regional assumptions. The EPA should only establish a final compliance date.
Interim performance requirements should not be mandatory, to allow time to construct new and
upgraded electric grid and fuel infrastructure so as not to jeopardize reliability. EPA’s failure to
consider and incorporate concerns raised in these comments will result in unreasonable and
costly emission performance requirements for Florida.
23
Attachment 2
State of Florida
Clommtaaicm
Capital Circle Office Center • 2540 Siiumard Oak Boulevard
Tallahassee, Florida 32399-0850
-M-E-M-O-R-A-N-D-U-M-
DATE:
November 13, 2014
TO;
Braulio L. Baez, Executive Director
FROM;
Phillip 0. Ellis, Engineering Specialist III, Division of Engineering
RE:
Draft Review of the 2014 Ten-Year Site Plans of Florida's Electric Utilities
Po^,
CRITICAL INFORMATION: Please place on the November 25, 2014, Internal
Affairs Agenda. Approval by the Commission is required by December 31, 2014.
Pursuant to Section 186.801(2), Florida Statutes, the Commission is required to classify each
generating electric utility's Ten-Year Site Plan as either "suitable" or "unsuitable" within nine
months of its filing. The attached draft satisfies this requirement and its approval by the
Commission is sought.
Please let me or Moni Mtenga know if you have any questions or need additional information in
reference to the attached document.
Thank you,
POE:tj
Attachment
cc:
Moni Mtenga
Paul Vickery
Tom Ballinger
Lisa Harvey
REVIEW OF THE
2014 TEN-YEAR SITE PLANS
OF FLORIDA’S ELECTRIC UTILITIES
NOVEMBER 2014
Table of Contents
List of Figures ................................................................................................................................ iii
List of Tables .................................................................................................................................. v
List of Ten-Year Site Plan Utilities ............................................................................................... vi
List of Acronyms .......................................................................................................................... vii
Executive Summary ...................................................................................................................... 1
Review of the 2014 Ten-Year Site Plans .................................................................................... 1
Future Concerns .......................................................................................................................... 5
Conclusion .................................................................................................................................. 5
Introduction ................................................................................................................................... 7
Statutory Authority ..................................................................................................................... 7
Additional Resources .................................................................................................................. 8
Structure of the Commission’s Review ...................................................................................... 9
Conclusion .................................................................................................................................. 9
Statewide Perspective ................................................................................................................. 10
Load Forecasting......................................................................................................................... 11
Electric Customer Composition ................................................................................................ 11
Growth Projections ................................................................................................................... 12
Peak Demand ............................................................................................................................ 13
Electric Vehicles ....................................................................................................................... 15
Demand-Side Management ....................................................................................................... 17
Forecast Load & Peak Demand ................................................................................................ 19
Renewable Generation................................................................................................................ 24
Existing Renewable Resources ................................................................................................. 24
Non-Utility Renewable Generation .......................................................................................... 25
Utility Owned Renewable Generation ...................................................................................... 26
Customer Owned Renewable Generation ................................................................................. 26
Planned Renewable Additions .................................................................................................. 27
Renewable Outlook ................................................................................................................... 28
Traditional Generation ............................................................................................................... 29
Existing Generation .................................................................................................................. 29
Impact of EPA Rules ................................................................................................................ 30
i
Table of Contents (cont.)
Modernization and Efficiency Improvements .......................................................................... 32
Planned Retirements ................................................................................................................. 32
Reliability Requirements .......................................................................................................... 34
Fuel Price Forecast .................................................................................................................... 35
Fuel Diversity............................................................................................................................ 37
New Generation Planned .......................................................................................................... 38
New Power Plants by Fuel Type............................................................................................... 39
Commission’s Authority over Siting ........................................................................................ 41
Transmission ............................................................................................................................. 42
Utility Perspectives...................................................................................................................... 43
Florida Power & Light Company (FPL) ................................................................................... 44
Duke Energy Florida, Inc. (DEF) ............................................................................................. 51
Tampa Electric Company (TECO) ........................................................................................... 56
Gulf Power Company (GPC) .................................................................................................... 61
Florida Municipal Power Agency (FMPA) .............................................................................. 66
Gainesville Regional Utilities (GRU) ....................................................................................... 70
JEA............................................................................................................................................ 75
Lakeland Electric (LAK) .......................................................................................................... 80
Orlando Utilities Commission (OUC) ...................................................................................... 84
Seminole Electric Cooperative (SEC) ...................................................................................... 88
City of Tallahassee Utilities (TAL) .......................................................................................... 93
ii
List of Figures
Figure 1: Florida Growth in Customers and Sales .......................................................................... 2
Figure 2: Natural Gas Contribution to Florida Energy Consumption............................................. 3
Figure 3: Florida Current and Projected Installed Capacity by Fuel and Technology ................... 4
Figure 4: Comparison of Reporting Electric Utility Size ............................................................... 8
Figure 5: Florida Electric Customer Composition in 2013 ........................................................... 11
Figure 6: Climate Data by State (Continental US) ....................................................................... 12
Figure 7: Florida Growth in Customers and Sales ........................................................................ 13
Figure 8: Example Daily Load Curves ......................................................................................... 14
Figure 9: Daily Peak Demand (2013 Actual) ............................................................................... 15
Figure 10: Historic and Forecast for Statewide Seasonal Peak Demand and Annual Energy...... 20
Figure 11: Florida Electric Utility Installed Capacity by Decade................................................. 30
Figure 12: State of Florida Reserve Margin with New Units ....................................................... 35
Figure 13: Average Reporting Electric Utility Fuel Price ............................................................ 36
Figure 14: Fuel Price Comparison for Coal and Natural Gas ....................................................... 36
Figure 15: Natural Gas Contribution to Florida Energy Consumption......................................... 37
Figure 16: Florida Historic and Forecast Fuel Consumption........................................................ 38
Figure 17: Florida Current and Projected Installed Capacity by Fuel and Technology ............... 39
Figure 18: FPL Growth Rate......................................................................................................... 44
Figure 19: FPL Demand and Energy Forecasts ............................................................................ 45
Figure 20: FPL Reserve Margin Forecast ..................................................................................... 47
Figure 21: DEF Growth Rate ........................................................................................................ 51
Figure 22: DEF Demand and Energy Forecasts ........................................................................... 52
Figure 23: DEF Reserve Margin Forecast .................................................................................... 54
Figure 24: TECO Growth Rate ..................................................................................................... 56
Figure 25: TECO Demand and Energy Forecasts......................................................................... 57
Figure 26: TECO Reserve Margin Forecast ................................................................................. 59
Figure 27: GPC Growth Rate........................................................................................................ 61
Figure 28: GPC Demand and Energy Forecasts ........................................................................... 62
Figure 29: GPC Reserve Margin Forecast .................................................................................... 64
Figure 30: FMPA Growth Rate..................................................................................................... 66
Figure 31: FMPA Demand and Energy Forecasts ........................................................................ 67
iii
List of Figures (cont.)
Figure 32: FMPA Reserve Margin Forecast ................................................................................. 69
Figure 33: GRU Growth Rate ....................................................................................................... 70
Figure 34: GRU Demand and Energy Forecasts........................................................................... 71
Figure 35: GRU Reserve Margin Forecast ................................................................................... 73
Figure 36: JEA Growth Rate......................................................................................................... 75
Figure 37: JEA Demand and Energy Forecasts ............................................................................ 76
Figure 38: JEA Reserve Margin Forecast ..................................................................................... 78
Figure 39: LAK Growth Rate ....................................................................................................... 80
Figure 40: LAK Demand and Energy Forecasts ........................................................................... 81
Figure 41: LAK Reserve Margin Forecast.................................................................................... 83
Figure 42: OUC Growth Rate ....................................................................................................... 84
Figure 43: OUC Demand and Energy Forecasts........................................................................... 85
Figure 44: OUC Reserve Margin Forecast ................................................................................... 87
Figure 45: SEC Growth Rate ........................................................................................................ 88
Figure 46: SEC Demand and Energy Forecasts ............................................................................ 89
Figure 47: SEC Reserve Margin Forecast .................................................................................... 91
Figure 48: TAL Growth Rate........................................................................................................ 93
Figure 49: TAL Demand and Energy Forecasts ........................................................................... 94
Figure 50: TAL Reserve Margin Forecast .................................................................................... 96
iv
List of Tables
Table 1: Planned Units Requiring a Determination of Need .......................................................... 5
Table 2: Estimated Number of Electric Vehicles by Service Territory ........................................ 16
Table 3: Estimates for Electric Vehicle Annual Energy Consumption (GWh) ............................ 16
Table 4: State of Florida - Existing Renewable Resources........................................................... 24
Table 5: State of Florida - Net Metering Growth ......................................................................... 27
Table 6: State of Florida - Planned Renewable Resources ........................................................... 27
Table 7: Planned Firm Renewables .............................................................................................. 28
Table 8: Electric Generating Units to be Retired .......................................................................... 33
Table 9: Planned Nuclear Units .................................................................................................... 40
Table 11: Planned Natural Gas Units............................................................................................ 41
Table 12: Planned Units Requiring a Determination of Need ...................................................... 42
Table 13: Planned Transmission Lines ......................................................................................... 42
Table 14: FPL Energy Consumption by Fuel Type ...................................................................... 46
Table 15: FPL Unit Retirements and Additions ........................................................................... 50
Table 16: DEF Energy Consumption by Fuel Type ..................................................................... 53
Table 17: DEF Unit Retirements and Additions ........................................................................... 55
Table 18: TECO Energy Consumption by Fuel Type .................................................................. 58
Table 19: TECO Unit Additions ................................................................................................... 60
Table 20: GPC Energy Consumption by Fuel Type ..................................................................... 63
Table 21: GPC Unit Retirements and Additions........................................................................... 65
Table 22: FMPA Energy Consumption by Fuel Type .................................................................. 68
Table 23: GRU Energy Consumption by Fuel Type .................................................................... 72
Table 24: GRU Unit Retirements ................................................................................................. 74
Table 25: JEA Energy Consumption by Fuel Type ...................................................................... 77
Table 26: JEA Unit Retirements ................................................................................................... 79
Table 27: LAK Energy Consumption by Fuel Type ..................................................................... 82
Table 28: OUC Energy Consumption by Fuel Type .................................................................... 86
Table 29: SEC Energy Consumption by Fuel Type...................................................................... 90
Table 30: SEC Unit Retirements and Additions ........................................................................... 92
Table 31: TAL Energy Consumption by Fuel Type ..................................................................... 95
Table 32: TAL Unit Retirements and Additions........................................................................... 97
v
List of Ten-Year Site Plan Utilities
Name
Abbreviation
Investor-Owned Electric Utilities
Florida Power & Light Company
FPL
Duke Energy Florida, Inc.
DEF
Tampa Electric Company
TECO
Gulf Power Company
GPC
Municipal Electric Utilities
Florida Municipal Power Agency
FMPA
Gainesville Regional Utilities
GRU
JEA
JEA
Lakeland Electric
LAK
Orlando Utilities Commission
OUC
City of Tallahassee Utilities
TAL
Rural Electric Cooperatives
Seminole Electric Cooperative
SEC
vi
List of Acronyms
Acronym
CC
Term
Combined Cycle
CT
Combustion Turbine
DACS
Florida Department of Agriculture and Consumer Services
DEP
Florida Department of Environmental Protection
DSM
Demand-Side Management
EIA
Energy Information Administration
EPA
Environmental Protection Agency
F.A.C.
Florida Administrative Code
F.S.
Florida Statutes
FEECA
Florida Energy Efficiency & Conservation Act
FRCC
Florida Reliability Coordinating Council
GWh
Gigawatt-hour
LFG
Landfill Gas
MMBtu
Million British Thermal Units
MSW
Municipal Solid Waste
MW
Megawatt
NSB
Utilities Commission of New Smyrna Beach
NEL
Net Energy for Load
NUG
Non-Utility Generator
OBS
Other Biomass Solids
PPSA
Power Plant Siting Act
QF
Qualifying Facilities
RPS
Renewable Portfolio Standard
TLSA
Transmission Line Siting Act
TYSP
Ten-Year Site Plan
WDS
Wood and Wood Waste Solids
vii
Executive Summary
Pursuant to Section 186.801(1), Florida Statutes (F.S.), each generating electric utility must
submit to the Florida Public Service Commission (Commission) a Ten-Year Site Plan (TYSP or
Plan) which estimates the utility’s power generating needs and the general locations of its
proposed power plant sites over a ten-year planning horizon. The Ten-Year Site Plans of
Florida’s electric utilities are designed to give state, regional, and local agencies advance notice
of proposed power plants and transmission facilities. The Commission is required to perform a
preliminary study of each plan and classify each one as either “suitable” or “unsuitable.” This
document represents the study of the 2014 Ten-Year Site Plans for Florida’s electric utilities,
filed by 11 reporting utilities. 1
All findings of the Commission are made available to the Florida Department of Environmental
Protection for its consideration at any subsequent certification proceedings pursuant to the Power
Plant Siting Act or the Transmission Line Siting Act. 2 In addition, this document is forwarded to
the Florida Department of Agriculture and Consumer Services pursuant to Section 377.703(2)(e),
F.S., which requires the Commission to provide a report on electricity and natural gas forecasts.
Review of the 2014 Ten-Year Site Plans
The Commission has divided this review into two portions: a Statewide Perspective, which
covers the whole of Florida, and Utility Perspectives, which address each of the reporting
utilities. From a statewide perspective, the Commission has reviewed the implications of the
combined trends of Florida’s electric utilities regarding load forecasting, renewable generation,
and traditional generation.
Load Forecasting
Forecasting load growth is an important component of system planning for Florida’s electric
utilities. Over the past ten years, the total number of electric customers has increased by 9.46
percent above 2004. However, growth in the number of customers has not necessarily resulted
in growth in customer load. As of 2013, retail energy sales have only increased 0.52 percent
above 2004, down from a historic 2007 peak. Florida’s electric utilities project the economy to
recover over the planning period, with growth remaining slower than before the financial crisis.
Based on current projections, Florida’s electric utilities anticipate exceeding the historic 2007
peak by 2017. Figure 1 below details these trends.
1
Investor-owned utilities filing 2014 TYSPs include Florida Power & Light Company (FPL), Duke Energy Florida,
Inc. (DEF), Tampa Electric Company (TECO), and Gulf Power Company (GPC). Municipal utilities filing 2014
TYSPs include Florida Municipal Power Agency (FMPA), Gainesville Regional Utilities (GRU), JEA (formerly
Jacksonville Electric Authority), Lakeland Electric (LAK), Orlando Utilities Commission (OUC), and City of
Tallahassee Utilities (TAL). Seminole Electric Cooperative (SEC) also filed a 2014 TYSP.
2
The Power Plant Siting Act is Sections 403.501 through 403.518, F.S. Pursuant to Section 403.519, F.S., the
Commission is the exclusive forum for the determination of need for an electrical power plant. The Transmission
Line Siting Act is Sections 403.52 through 403.5365, F.S. Pursuant to Section 403.537, F.S., the Commission is the
sole forum for the determination of need for a transmission line.
1
Figure 1: Florida Growth in Customers and Sales
Source: FRCC 2014 Load & Resource Plan
Florida’s electric utilities reduce the rate of growth in customer peak demand and annual energy
consumption through demand-side management. The Commission, through its authority granted
by Sections 366.80 through 366.85 and Section 403.519, F.S., otherwise known as the Florida
Energy Efficiency and Conservation Act (FEECA), encourages demand-side management by
establishing goals for the reduction of seasonal peak demand and annual energy consumption for
those utilities under its jurisdiction. The Commission establishes goals at least once every five
years, and is scheduled to establish goals by the end of 2014, which would be reflected in the
2015 Ten-Year Site Plans.
Based on current proposals, Florida’s electric utilities project that by 2023 demand-side
management programs will reduce the system’s total summer peak demand by approximately
8,000 megawatts (MW), and annual energy consumption by over 11,000 gigawatt-hours (GWh).
Including these reductions, Florida is forecasted to experience by 2023 a net firm summer peak
demand of 52,633 MW and annual net energy for load of 270,773 GWh.
Renewable Generation
Renewable resources continue to expand in Florida, with approximately 1,620 MW of renewable
generating capacity currently installed in Florida. The majority of installed renewable capacity is
represented by biomass and municipal solid waste, making up approximately 60 percent of
Florida’s renewables. Other major renewable types, in order of capacity contribution, include
waste heat, solar, hydroelectric, and landfill gas. Notably, Florida had 63 MW of demand-side
renewable energy systems installed and using net metering by the end of 2013, an increase in
capacity of 50 percent from 2012.
2
Over the next ten years, Florida’s electric utilities have reported that 722 MW of additional
renewable generation is planned in Florida, excluding any potential net metering additions.
Almost half of the projected capacity additions are solar generation, the remainder consisting of
solid biomass, municipal solid waste, and landfill gas. While these new projects represent a
significant increase from the existing total, renewable generation continues to provide a
relatively small contribution towards the reduction of the state’s reliance upon fossil fuels.
Traditional Generation
Natural gas remains the dominant fuel over the planning horizon, with usage in 2013 at
approximately 60 percent of the state’s net energy for load (NEL). Figure 2 below illustrates the
use of natural gas as a generating fuel for electricity production in Florida. Natural gas usage is
expected to remain approximately at its current level, on a percentage basis, and decline
somewhat at the end of the planning period due to an increase in nuclear generation.
Figure 2: Natural Gas Contribution to Florida Energy Consumption
Source: 2005-2014 FRCC Load & Resource Plans
Generating capacity within the state of Florida is anticipated to grow to meet the increase in
customer demand, with approximately 12,570 MW of new utility-owned generation added over
the planning horizon. This figure represents an increase from the previous year, which estimated
the need for about 9,960 MW new generation. Based on the 2014 Ten-Year Site Plans, Figure 3
below illustrates the present and future aggregate capacity mix of the state of Florida. The
capacity values in Figure 3 incorporate all proposed additions, changes, and retirements planned
during the ten-year period. As in previous planning cycles, natural gas-fired generating units
make up a majority of the generation additions and now represent a majority of capacity within
the state.
3
Figure 3: Florida Current and Projected Installed Capacity by Fuel and Technology
Source: 2014 FRCC Load & Resource Plan and TYSP Utilities Data Responses
As noted previously, the primary purpose of this review of the utilities’ plans is to provide
information regarding new electric power plants for local and state agencies to assist in the
certification process. Table 1 displays those generation facilities that had not yet received from
the Commission a certification under the Power Plant Siting Act. A petition for a determination
of need is generally anticipated at four years in advance of the in-service date for a natural gasfired combined cycle unit. The Commission most recently approved a determination of need for
DEF’s proposed Citrus plant, which will still have to seek approval from DEP and the Siting
Board.
4
Table 1: Planned Units Requiring a Determination of Need
Net Capacity
(MW)
Sum
Win
In-Service
Year
Utility
Name
Plant Name
& Unit Number
Unit Type
2018
DEF
Citrus
Combined Cycle
1,640
1,820
2019
FPL
Unsited
Combined Cycle
1,269
1,429
2020
SEC
Unsited
Combined Cycle
440
523
2021
DEF
Unsited
Combined Cycle
793
866
Notes
See Order No.
PSC-14-0557-FOF-EI
Source: 2014 Ten-Year Site Plans
While the Commission certifies transmission lines under the Transmission Line Siting Act
(TLSA), there are none projected during the planning period that have not already been approved
by the Commission.
Future Concerns
Florida’s electric utilities must also consider environmental concerns associated with existing
generators and planned generation to meet Florida’s electric needs. The U.S. Environmental
Protection Agency (EPA) has finalized or proposed several new rules in recent years that have a
sizeable impact on Florida’s existing generation fleet, as well as on its proposed new facilities.
Notably, the EPA proposed a rule in June 2014 associated with carbon pollution for existing
power plants, also known as the Clean Power Plan. Due to the timing of the Ten-Year Site Plan
filings, these proposed EPA Rules, though they may have a large effect on Florida’s electric
utilities, are not considered as part of this review. The Commission anticipates that the 2015
Ten-Year Site Plan will include more discussion of potential impacts to Florida’s electric utilities
from the Clean Power Plan, but uncertainty would remain as Florida’s implementation plan
would not be completed.
Regarding reliability, FPL is proposing using a third reliability criterion, a generation only
planning reserve margin that excludes the benefits of demand response and incremental energy
efficiency programs. While the proposed criterion has only a minor effect in the 2014 TYSP, it
generally would result in higher installed or purchased capacity requirements for FPL to meet
summer peak demand. At this time, FPL has not requested approval of this criterion, nor has the
Commission approved its use. The Commission will continue to monitor annually FPL’s reserve
margin, demand response, and energy efficiency accomplishments. The Commission will have
an opportunity to review FPL’s proposed metric if it becomes a controlling factor for a
determination of need of a new electrical power plant.
Conclusion
The Commission has reviewed the 2014 Ten-Year Site Plans and finds that the projections of
load growth appear reasonable. The reporting utilities have identified sufficient additional
generation facilities to maintain an adequate supply of electricity at a reasonable cost. The
5
Commission will continue to monitor the impact of current and proposed EPA Rules and the
state’s dependence on natural gas for electricity production.
Based on its review, the Commission finds the 2014 Ten-Year Site Plans to be suitable for
planning purposes. Since the Plans are not a binding plan of action for electric utilities, the
Commission’s classification of these Plans as suitable or unsuitable does not constitute a finding
or determination in docketed matters before the Commission. The Commission may address any
concerns raised by a utility’s Ten-Year Site Plan at a public hearing.
6
Introduction
The Ten-Year Site Plans of Florida’s electric utilities are designed to give state, regional, and
local agencies advance notice of proposed power plants and transmission facilities. The
Commission receives comments from these agencies regarding any issues with which they may
have concerns. The Plans are planning documents that contain tentative data that is subject to
change by the utilities upon written notification to the Commission.
For any new proposed power plants and transmission facilities, certification proceedings under
the Power Plant Siting Act, Sections 403.501 through 403.518, Florida Statutes (F.S.) or the
Transmission Line Siting Act, Sections 403.52 through 403.5365, F.S., will include more
detailed information than is provided in the Plans. The Commission is the exclusive forum for
determination of need for electrical power plants, pursuant to Section 403.519, F.S., and for
transmission lines, pursuant to Section 403.537, F.S. The Plans are not intended to be
comprehensive, and therefore may not have sufficient information to allow regional planning
councils, water management districts, and other reviewing state and local agencies to evaluate
site-specific issues within their respective jurisdictions. Other regulatory processes may require
the electric utilities to provide additional information as needed.
Statutory Authority
All major generating electric utilities are required by Section 186.801, F.S., to annually submit
for review a Ten-Year Site Plan to the Commission. Based on these filings, the Commission
performs a preliminary study of each plan and makes a non-binding determination as to whether
it is suitable or unsuitable. The results of the Commission’s study are contained in this report,
the Review of the 2014 Ten-Year Site Plans, and are forwarded to the Florida Department of
Environmental Protection for use in subsequent proceedings. In addition, Section 377.703(2)(e),
F.S., requires the Department of Agriculture and Consumer Services in consultation with the
Commission to collect and analyze energy forecasts. The Commission has adopted Rules 2522.070 through 25-22.072, Florida Administrative Code (F.A.C.) in order to fulfill these
statutory requirements.
Applicable Utilities
Florida is served by 58 electric utilities, including 5 investor-owned utilities, 35 municipal
utilities, and 18 rural electric cooperatives. Pursuant to Rule 25-22.071(1), F.A.C., only
generating electric utilities with an existing capacity above 250 megawatts (MW) or a planned
unit with a capacity of 75 MW or greater are required to file with the Commission a Ten-Year
Site Plan, at least once every two years.
In 2014, 11 utilities met these requirements and filed a Ten-Year Site Plan, including 4 investorowned utilities, 6 municipal utilities, and 1 rural electric cooperative. The investor-owned
utilities, in order of size, are Florida Power & Light Company (FPL), Duke Energy Florida, Inc.
(DEF), Tampa Electric Company (TECO), and Gulf Power Company (GPC). The municipal
utilities, in alphabetical order, are Florida Municipal Power Agency (FMPA), Gainesville
Regional Utilities (GRU), JEA (formerly Jacksonville Electric Authority), Lakeland Electric
7
(LAK), Orlando Utilities Commission (OUC), and City of Tallahassee Utilities (TAL). The sole
rural electric cooperative filing a 2014 Plan is Seminole Electric Cooperative (SEC).
Collectively, these utilities are referred to as the Ten-Year Site Plan Utilities (TYSP Utilities).
Figure 4 below illustrates the comparative size of the TYSP Utilities, in terms of each utility’s
percentage share of the state’s retail energy sales in 2013. Combined, the reporting investorowned utilities account for 77.7 percent of the state’s retail energy sales. Non-reporting utilities
make up approximately 1.5 percent of the State’s retail energy sales.
Figure 4: Comparison of Reporting Electric Utility Size
Source: 2014 Ten-Year Site Plans, 2014 Load & Resource Plan
Required Content
The Commission requires each reporting utility to provide information on a variety of topics.
Schedules describe the utility’s existing generation fleet, customer composition, demand and
energy forecasts, fuel requirements, reserve margins, changes to existing capacity, and proposed
power plants and transmission lines. The utilities also provide a narrative documenting the
methodologies used to forecast customer demand and the identification of resources to meet that
demand over the ten-year planning period. This information, supplemented by additional data
requests, provides the basis of the Commission’s review.
Additional Resources
The Commission’s Rule also task the reporting electric utilities with collecting information on
both a statewide basis and for Peninsular Florida, which excludes the area east of the
Apalachicola River. The Florida Reliability Coordinating Council (FRCC) provides this
aggregate data for the Commission’s review. Each year, the FRCC publishes a Regional Load
and Resource Plan, which contains historic and forecast data on demand and energy, capacity
and reserves, and proposed new generating units and transmission line additions. In addition, the
FRCC publishes an annual Reliability Report which is also relied upon by the Commission.
8
For certain comparisons additional data from various governmental agencies is relied upon,
including the Energy Information Administration and the Florida Department of Highway Safety
and Motor Vehicles.
The Commission held a public workshop on August 12, 2014, to facilitate discussion of the
annual planning process and allow for public comments. A presentation was conducted by the
FRCC summarizing the 2014 Load and Resource Plan and other related matters, including fuel
reliability, environmental regulations, and physical security of infrastructure. Public comments
were provided by the Sierra Club, which focused on the need to evaluate alternative energy
options, planning for compliance with existing and future environmental regulations, and fuel
diversity.
Structure of the Commission’s Review
The Commission’s review is divided into multiple sections. The Statewide Perspective provides
an overview of the state of Florida as a whole, including discussions of load forecasting,
renewable generation, and traditional generation. The Utility Perspectives provides more focus,
discussing the various issues facing each electric utility and its unique situation. Lastly, the
comments collected from various review agencies, local governments, and other organizations
are included as Appendix A.
Conclusion
Based on its review, the Commission finds all 11 reporting utility’s 2014 Ten-Year Site Plans to
be suitable for planning purposes. During its review, the Commission has determined that the
projections for load growth appear reasonable and that the reporting utilities have identified
sufficient generation facilities to maintain an adequate supply of electricity at a reasonable cost.
The Commission notes that, as the Ten-Year Site Plans are non-binding, the classification of
suitable does not constitute a finding or determination in any docketed matter before the
Commission, nor an approval of all planning assumptions contained within the Ten-Year Site
Plans. The Commission may address any concerns raised by a utility’s Ten-Year Site Plan at a
public hearing.
9
STATEWIDE PERSPECTIVE
10
Load Forecasting
Forecasting load growth is an important component of system planning for Florida’s electric
utilities. In order to maintain system reliability, utilities must be prepared for future changes in
electricity consumption, including changes to the number of electric customers, customer usage
patterns, building codes and appliance efficiency standards, new technologies such as electric
vehicles, and the role of demand-side management.
Electric Customer Composition
The residential class represent the majority in terms of number of customers, at 88.7 percent of
customers, and retail energy sales, at 52.3 percent of sales, for the three major customer classes,
as illustrated in Figure 5 below. Both commercial and industrial customers make up a sizeable
percentage of energy sales, due to each class’ higher energy usage per customer account.
Figure 5: Florida Electric Customer Composition in 2013
Source: FRCC 2014 Load & Resource Plan
Florida’s residential customers make up a larger portion of retail energy sales than the United
States as a whole, with a national average of 38 percent for residential retail sales. As a result,
Florida’s utilities are impacted more by trends in residential energy usage, which tend to be
associated with weather conditions. Florida’s residential customers rely more upon electricity
for heating than the national average, with only a small portion using alternate fuels such as
natural gas or oil for home heating needs.
Florida’s unique climate plays an important role in electric utility planning. Florida is an outlier
in terms of climate, with the highest number of cooling degree days and lowest number of
heating degree days within the continental United States, as shown below by Figure 6. Other
11
states tend to rely upon alternative fuels for heating, but Florida’s heavy use of electricity results
in high winter peak demand.
Figure 6: Climate Data by State (Continental US)
Source: National Oceanic & Atmospheric Administration, Historical Climatology Series 5-1 and
5-2 (30 year period)
Growth Projections
Florida traditionally has been a high growth state, with significant annual increases in both
customers and retail energy sales. The financial crisis and resulting economic impact to Florida
resulted in a freezing of customer growth and decline in retail energy sales from the 2007 peak.
While customer growth has resumed, albeit at a slower pace, retail sales have declined since
2007 excluding a spike in usage associated with extreme winter weather in 2010. The result of
both of these trends has been that over the last ten year period, the number of Florida’s electric
customers have risen 9.46 percent, while retail energy sales have risen only 0.52 percent. Since
2004, the effective average annual growth rate for electric sales during the past ten years was
0.06 percent. These trends are illustrated in Figure 7, below.
12
Figure 7: Florida Growth in Customers and Sales
Source: FRCC 2014 Load & Resource Plan
For the next ten year period, Florida’s customer base and retail sales are anticipated by the
reporting utilities to grow at a faster pace than the last few years, reversing a trend of small
population increases with declining retail sales. While this rate remains below those experienced
before the financial crisis, it would set the state on track to exceed its previous 2007 retail sales
peak in 2017. The current divide between customers and retail sales is anticipated to remain
similar over the ten-year period, with customers growing at an average annual rate of 1.41
percent while retail sales increase by 1.36 percent annually. Florida’s electric utilities are
projecting an increase in economic growth in the state, but at levels below those experienced
before the financial crisis.
Peak Demand
The aggregation of each individual customer’s electric consumption must be met at all times by
Florida’s electric utilities to ensure reliable service. The time at which customers demand the
most energy simultaneously is referred to as peak demand. While retail energy sales primarily
vary the amount of fuel consumed by the electric utilities to deliver energy, peak demand
determines the amount of generating capacity required to deliver that energy at a single moment
in time.
A primary factor in this is seasonal weather patterns, with peak demands calculated separately
for the summer and winter periods annually. The influence of residential customers is evident in
the determination of these seasonal peaks, as they correspond to times of increased usage to meet
home heating (winter) and cooling (summer) demand. Figure 8 below, illustrates a daily load
curve for a typical day for each season. In the summer, air-conditioning needs increase
throughout the day, climbing steadily until a peak is reached in the late afternoon and then
declining into the evening. In the winter, electric heat and electric water heating produces a
higher base level of usage, with a large spike in the morning and a smaller spike in the evening.
13
Figure 8: Example Daily Load Curves
Source: TYSP Utility Data Responses
Florida is typically a summer-peaking state, meaning that the summer peak demand generally
exceeds winter peak demand, and therefore controls the amount of generation required. Weather
conditions impact generation capacity in ways that cause summer demand to control. Higher
temperatures in the summer reduce the efficiency of generation, with high water temperatures
reducing the quality of cooling provided, and can sometimes limit the quantity as units may be
required to operate at reduced power or go offline based on environmental permits. Conversely,
in the winter, utilities can take advantage of lower ambient air and water temperatures to produce
more electricity from a power plant.
As daily load varies, so do seasonal loads. Figure 9 below, illustrates this for 2013, showing the
daily peak demand as a percentage of the annual peak demand for the reporting investor-owned
utilities combined. As 2013 featured a mild winter, so summer peak demand set the annual peak
demand. Typically, winter peaks are short events while summer demand tends to stay at near
peak levels for longer periods. The periods between seasonal peaks are referred to as shoulder
months, in which the utilities take advantage of lower demand to perform maintenance without
impacting their ability to meet daily peak demand.
14
Figure 9: Daily Peak Demand (2013 Actual)
Source: TYSP Utilities Data Responses (Investor-Owned Utilities Only)
While the utilities assume normalized weather in forecasts of peak demand, during operation of
the system utilities continuously monitor the short-term weather patterns. Utilities adjust
maintenance schedules to ensure the highest unit availability during the utility’s projected peak
demand, bringing units back online if necessary or delaying maintenance until after a weather
system has passed.
Electric Vehicles
Utilities also examine other trends that may impact the amount of customer peak demand and
energy consumption. This includes new sources of energy consumption, such as electric
vehicles, which can be considered analogous to a home air conditioning system in terms of
system load. The reporting electric utilities estimate approximately 8,000 electric plug-in
vehicles were operating in Florida by the end of 2013. The Florida Department of Highway
Safety and Motor Vehicles lists the number of registered vehicles in Florida as of December 31,
2013, as 18.9 million vehicles, resulting in 0.042 percent penetration rate of electric vehicles of
Florida’s registered vehicle fleet.
Florida’s electric utilities anticipate growth in the electric vehicle market, as illustrated in Table
2 below. Electric vehicles are anticipated to grow rapidly throughout the planning period,
resulting in almost a half-million electric vehicles operating within the electric service territories
by the end of 2023. The projected increase in electric vehicle ownership would result in
approximately 2 percent share of Florida’s vehicles being fueled by electricity.
15
Table 2: Estimated Number of Electric Vehicles by Service Territory
Year
FPL
DEF
TECO
GPC
JEA
OUC
TAL
Total
2013
4,603
1,647
382
196
111
1,030
24
7,993
2014
8,787
3,125
N/A
445
173
1,624
36
14,190
2015
14,662
5,256
N/A
873
212
2,689
45
23,737
2016
22,628
8,273
N/A
1,442
282
4,037
54
36,716
2017
35,374
12,273
N/A
2,053
385
5,685
65
55,835
2018
48,200
17,482
N/A
2,836
520
7,646
84
76,768
2019
689
9,937
110
103,182
64,525
24,228
N/A
3,693
2020
97,425
32,893
N/A
4,626
891
12,574
142
148,551
2021
146,771
43,882
N/A
5,684
1,156
15,570
185
213,248
2022
220,792
57,338
N/A
6,872
1,485
18,859
250
305,596
2023
331,824
73,187
N/A
8,111
1,879
22,630
325
437,956
Source: TYSP Utilities Data Responses
In terms of energy consumed by electric vehicles, Table 3 below illustrates the estimates
provided by the reporting utilities. The anticipated growth would result in an annual energy
consumption of 2,266 GWh, or approximately 0.9 percent of retail sales for the state of Florida.
Table 3: Estimates for Electric Vehicle Annual Energy Consumption (GWh)
Year
FPL
DEF
TECO
GPC
JEA
OUC
TAL
Total
2013
22
9
N/A
1
1
0
8
41
2014
42
21
N/A
2
1
1
12
79
2015
70
41
N/A
4
1
2
15
133
2016
108
70
N/A
7
2
2
18
207
2017
169
107
N/A
10
3
3
22
314
2018
230
152
N/A
13
5
5
28
433
2019
309
207
N/A
17
7
6
37
583
2020
466
273
N/A
21
9
8
48
825
2021
702
349
N/A
26
13
9
62
1,162
2022
1,056
421
N/A
32
17
11
84
1,621
2023
1,587
495
N/A
37
23
14
110
2,266
Source: TYSP Utilities Data Responses
The effect of increased electric vehicle ownership on peak demand is more difficult to determine.
While comparable in electric demand to a home air conditioning system, the time of charging
and whether charging would be shifted away from periods of peak demand are uncertainties that
must be clarified to determine impact on system peak. As electric vehicle ownership increases,
16
the effects of electric vehicles on system peak should become clearer and able to be addressed by
the electric utilities.
Demand-Side Management
Florida’s electric utilities also must consider how the efficiency of customer energy consumption
changes over the planning period. Changes in government mandates, such as building codes and
appliance efficiency standards, reduce the amount of energy consumption for new construction
and electric equipment. Electric customers, through the power of choice, can elect to engage in
behaviors that decrease peak load or annual energy usage. Examples include, turning off lights
and fans in vacant rooms, increasing thermostat settings, and purchasing appliances that go
beyond efficiency standards. While a certain portion of customers will engage in these activities
without incentives due to economic, aesthetic, or environmental concerns, other customers may
lack information or require additional incentives. Demand-side management represents an area
where Florida’s electric utilities can empower and educate its customers to make choices that
reduce peak load and annual energy consumption.
Florida Energy Efficiency and Conservation Act (FEECA)
The Florida Legislature has directed the Commission to encourage utilities to decrease the
growth in seasonal peak demand and annual energy consumption by FEECA, which consists of
Sections 366.80 through 366.85 and Section 403.519, F.S. Under FEECA, the Commission is
required to set goals for seasonal demand and annual energy reduction for seven electric utilities,
known as the FEECA Utilities. These include the five investor-owned electric utilities
(including Florida Public Utility Company, which is a non-generating utility and therefore does
not file a Ten-Year Site Plan) and two municipal electric utilities (JEA and OUC). The FEECA
utilities represented approximately 86 percent of 2013 retail sales in Florida.
The FEECA utilities currently offer demand-side management programs for residential,
commercial, and industrial customers. Energy audit programs are designed to provide an
overview of customer energy usage and to evaluate conservation opportunities, including
behavioral changes, low-cost measures customers can undertake themselves, and participation in
utility-sponsored DSM programs.
The last FEECA goal-setting proceeding was completed in December 2009, establishing goals
for the period 2010 through 2019. As the Commission is required to establish goals once every
five years, the Commission opened dockets in 2013 to begin the review process, and held a
hearing in July 2014, with a final decision on annual goals anticipated by December 2014. Each
FEECA Utility’s 2014 Ten-Year Site Plan includes either a continuation of existing programs or
the utility’s proposed goals. The 2015 Ten-Year Site Plans should reflect the impact of the goals
established by the Commission for the period 2015 through 2024.
17
Demand Side Management Programs
DSM Programs generally are divided into three categories: interruptible load, load management,
and energy efficiency. The first two are considered dispatchable, and are collectively known as
demand response, meaning that the utility can call upon them during a period of peak demand or
other reliability concerns, but otherwise they are not utilized. In contrast, energy efficiency
measures are considered passive and are always working to reduce customer demand and energy
consumption.
Interruptible load is achieved through the use of agreements with large customers to allow the
utility to interrupt the customer’s load, reducing the generation required to meet system demand.
Interrupted customers may use back-up generation to fill their energy needs, or cease operation
until the interruption has passed. A subtype of interruptible customers is curtailable customers,
which allow the utility to interrupt only a portion of the customer’s load. In exchange for the
ability to interrupt these customers, the utility offers a discounted rate for energy or other credits
which are paid for by all ratepayers.
Load management is similar to interruptible customers, but focuses on smaller customers and
targets individual appliances. The utility installs a device on an electric appliance, such as a
water heater or air conditioner that allows for remote deactivation for a short period of time.
Load management activations tend to have less advanced notice than those for interruptible
customers, but tend to be activated only for short periods and are cycled through groups of
customers to reduce the impact to any single customer. Due to the focus on specific appliances,
certain appliances would be more appropriate for addressing certain seasonal demands. For
example, load management programs targeting air conditioning units would be more effective to
reduce a summer peak, while water heaters are more effective for reducing a winter peak. As of
2014, demand response available for reduction of peak load is 3,105 MW for summer peak and
2,987 MW for winter peak. Demand response is anticipated to increase to approximately 3,500
for summer peak and 3,300 for winter peak by the end of the planning period in 2023.
Energy efficiency or conservation measures also have an impact on peak demand, and due to
their passive nature do not require activation by the utility. Conservation measures include
improvements in a home or business’ building envelope to reduce heating or cooling needs, or
the installation of more efficient appliances. By installing additional insulation, energy-efficient
windows or window films, and more efficient appliances, customers can reduce both their peak
demand and annual energy consumption, leading to reductions in customer bills. Demand-side
management programs work in conjunction with building codes and appliance efficiency
standards to increase energy savings above the minimum required by local, state, or federal
regulations. As of 2014, energy efficiency is responsible for peak load reduction of 3,766 MW
for summer peak and 3,519 MW for winter peak. Energy Efficiency is anticipated to increase to
approximately 4,454 MW for summer peak and 4,223 MW for winter peak by the end of the
planning period in 2023.
18
Forecast Load & Peak Demand
The historic and forecasted seasonal peak demand and annual energy consumption values for the
state of Florida are illustrated below in Figure 10. It should be noted that the forecasts shown
below are based upon normalized weather conditions, while the historic demand and energy
values represent the actual impact of weather conditions on Florida’s electric customers. Florida
relies heavily upon both air conditioning in the summer and electric heating in the winter, so
both seasons experience a great deal of variability due to severe weather conditions.
Demand-side management, including demand response and energy efficiency, along with selfservice generation is included in each figure for seasonal peak demand and annual energy for
load. The total demand or total energy for load represents what otherwise would need to be
served if not for the impact of these programs and self-service generators. The net firm demand
is used as a planning number for the calculation of generating reserves and determination of
generation needs for Florida’s electric utilities.
Demand response is included in Figure 10 in two different ways based upon the time period
considered. For historic values of seasonal demand, the actual rates of demand response
activation are shown, not the full amount demand response that was available at the time.
Overall, demand response has only been partially activated as sufficient generation assets were
available during the annual peak. Residential load management has been called upon to a limited
degree during peak periods, with a lesser amount of interruptible load activated. The primary
exception to this trend was the summer of 2008 and winter of 2009, when a larger portion of the
available demand response resources were called upon.
For forecast values of seasonal demand, it is assumed that all demand response resources will be
activated during peak. The assumption of all demand response being activated reduces
generation planning need. Based on operating conditions in the future, if an electric utility has
sufficient generating units and it is economic to serve all customer load demand response would
not be activated or only partially activated in the future.
As previously discussed, Florida is normally a summer-peaking state. Only three of the past ten
years have had higher winter net firm demand than summer, and all ten of the forecast years are
anticipated to be summer peaking. Based upon current forecasts using normalized weather data,
Florida’s electric utilities do not anticipate exceeding the winter 2009 peak during the planning
period.
19
Figure 10: Historic and Forecast for Statewide Seasonal Peak Demand and Annual Energy
Source: 2014 FRCC Load & Resource Plan
Forecast Methodology
20
Florida’s electric utilities perform forecasts of peak demand and annual energy sales using
historical data from several variables to infer relationships through multiple linear regressions.
These variables include historic energy consumption, customer data such as square footage of
housing, climate data such as cooling-degree-days or heating-degree days, and economic
indicators such as income and employment. For some customer classes, such as industrial
customers, surveys may periodically be conducted to determine the customer’s expectations for
their own future electricity consumption.
Florida’s electric utilities rely upon econometric techniques for load forecasting, incorporating a
variety of tools such as advanced software and analysis from independent experts from public
and private sources for historic and forecast values of specific variables. Public resources such
as the University of Florida’s Bureau of Economic and Business Research, which provides data
on population growth, and the Bureau of Labor Statistics, which publishes the Consumer Price
Index, are utilized along with private forecasts for economic growth from macroeconomic
experts. By combining historic and forecast macroeconomic data with customer and climate
data, Florida’s electric utilities project future load conditions.
Through multiple linear regressions, Florida’s electric utilities demonstrate historical
relationships between dependent variables such as load and retail energy sales, and independent
variables such as economic conditions and climate.
Projecting peak loads is more
mathematically complicated and depends on the interrelationships between these variables.
Overall, while each of Florida’s electric utilities forecast peak load and retail energy sales
differently, the econometric techniques utilized appear to be sound. The forecasts allow each
electric utility to evaluate its individual needs for new generation, transmission, and distribution
resources to meet customers’ current and future needs reliably and affordably.
Historic Forecast Accuracy
For each reporting electric utility, the Commission reviewed the historic forecast accuracy of
past retail energy sales forecasts. The review methodology, previously used by the Commission,
involves comparing actual retail sales for a given year to energy sales forecasts made three, four,
and five years prior. For example, the actual 2013 retail energy sales were compared to the
forecasts made in 2010, 2009, and 2008. These differences, expressed as a percentage error rate,
are used to determine each utility’s historic forecast accuracy using a five year rolling average.
An average error with a negative value indicates an under-forecast, while a positive value
represents an over-forecast. An absolute average error provides an indication of the total
magnitude of error, regardless of the tendency to under or over forecast.
For the 2014 Ten-Year Site Plans, determining the accuracy of the five year rolling average
forecasts involves comparing the actual retail energy sales for the period 2013 through 2009 to
forecasts made between 2010 and 2004. As discussed previously, the period before the financial
crisis experienced a higher annual growth rate for retail energy sales than the post-crisis period.
As most electric utilities and macroeconomic forecasters did not predict the financial crisis, the
economic impact and its resulting effect on retail energy sales of Florida’s electric utilities was
21
not included in these projections. Therefore, the use of a metric that compares pre-crisis
forecasts with post-crisis actual data has a high rate of error.
Table 5 below, confirms that the forecast error is increasing with time due to the unexpected
impact of the financial crisis on retail energy sales in Florida due to decreased population
growth, decreased economic growth, and decreased usage of electricity per capita. However, the
forecast error should start to return to its historically normal lower levels as utility retail sales
forecasts include more years after the financial crisis.
Table 5: TYSP Utilities – Accuracy of Retail Energy Sales Forecasts
TYSP
Year
2009
2010
2011
2012
2013
2014
Five Year
Analysis
Period
2008 - 2004
2009 - 2005
2010 - 2006
2011 - 2007
2012 - 2008
2013 - 2009
Forecast
Years
Analyzed
2005-1999
2006-2000
2007-2001
2008-2002
2009-2003
2010-2004
Forecast Error (%)
Absolute
Average
Average
1.74%
3.56%
4.98%
5.70%
8.28%
8.29%
11.93%
11.93%
15.13%
15.13%
16.16%
16.16%
Source: 1999-2014 Ten-Year Site Plans
To verify whether more recent forecasts lowered these error rates, an additional analysis was
conducted to determine with more detail the source of high error rates in terms of forecast
timing. Table 6 below, provides the forecast error rate for forecasts made between one and six
years prior, along with the average and absolute average error rates for the three- to five-year
period used in the analysis above.
Table 6: TYSP Utilities – Accuracy of Retail Energy Sales Forecasts – Annual Analysis
Year
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
6
-5.82%
-3.29%
0.57%
7.02%
11.95%
12.93%
21.56%
26.31%
28.55%
Annual Forecast Error Rate (%)
Years Prior
5
4
3
2
-5.08% -3.18%
0.19% -0.59%
-4.03% -0.69% -0.64%
0.71%
-0.03%
1.03%
2.30%
2.43%
2.26%
3.49%
3.59%
4.20%
8.40%
8.56%
9.97%
9.24%
12.15% 14.48% 13.91% 12.68%
15.57% 14.89% 13.70% 10.55%
20.79% 20.09% 17.02%
3.79%
25.97% 23.04%
8.47%
3.90%
26.29% 10.00%
5.98%
5.58%
Source: 1999-2014 Ten-Year Site Plans
22
1
0.93%
0.90%
2.37%
3.05%
8.34%
10.18%
-0.73%
0.08%
3.71%
2.97%
3-5 Year Error (%)
Absolute
Average
Average
-2.69%
2.81%
-1.79%
1.79%
1.10%
1.12%
3.11%
3.11%
8.98%
8.98%
13.51%
13.51%
14.72%
14.72%
19.30%
19.30%
19.16%
19.16%
14.09%
14.09%
As displayed in Table 6, the companies retail energy sales forecasts show a consistent positive
error rate beginning in 2007 and extending through 2013 for forecasts prepared 2 to 6 years
prior. However, 2013 sales forecasted in 2009 and 2010 reveal that 3 and 4 year error rates (5.98
percent and 10.00 percent, respectively) have declined considerably compared to the 3 and 4 year
forecast error rates associated with 2009-2012 sales. The fact that 3 and 4 year forecast errors
started to decline in 2009 and 2010 forecasts is not surprising because by 2009 the inputs to the
utilities’ forecast models reflected the impacts of the financial crisis and population growth
decline.
On a going forward basis (2014 and beyond), average forecasted energy sales error rates for
forecasts prepared 3 to 5 years prior are likely to continue to decline as the older forecasts drop
out of the analysis. Florida’s electric utilities, however, have responded to the recent declines in
customer load growth by delaying and cancelling new generation, and by taking opportunities to
modernize existing plants, as discussed in previous annual reviews of the Ten-Year Site Plans.
23
Renewable Generation
Pursuant to Section 366.91, F.S., it is in the public interest to promote the development of
renewable energy resources in Florida. Section 366.91(2)(d), F.S., defines renewable energy in
part, as follows:
“Renewable energy” means electrical energy produced from a method that uses
one or more of the following fuels or energy sources: hydrogen produced from
sources other than fossil fuels, biomass, solar energy, geothermal energy, wind
energy, ocean energy, and hydroelectric power.
Although not considered a traditional renewable resource, some industrial plants take advantage
of waste heat, produced in production processes, to also provide electrical power via
cogeneration. Phosphate fertilizer plants, which produce large amounts of heat in the
manufacturing of phosphate from the input stocks of sulfuric acid, are a notable example of this
type of renewable resource. The Section 366.91(2) (b), F.S., definition also includes the
following language which recognizes the aforementioned cogeneration process:
The term [Renewable Energy] includes the alternative energy resource, waste
heat, from sulfuric acid manufacturing operations and electrical energy produced
using pipeline-quality synthetic gas produced from waste petroleum coke with
carbon capture and sequestration.
Existing Renewable Resources
Currently, renewable energy facilities provide approximately 1,617 MW of firm and non-firm
generation capacity, which represents 2.8 percent of Florida’s overall generation capacity of
57,375 MW in 2013. Table 4 below, is a table that summarizes Florida’s existing renewable
energy sources.
Table 4: State of Florida - Existing Renewable Resources
Renewable Type
Municipal Solid Waste
Waste Heat
Solar
Hydro
Wind
Solid Biomass
Landfill Gas
Total of All
MW
398
308
218
64
0
581
49
1,617
% Total
24.6%
19.0%
13.5%
3.9%
0.0%
35.9%
3.1%
100.0%
Source: FRCC 2014 Load & Resource Plan and TYSP Utilities Data Responses
24
Of the total 1,617 MW of renewable generation, approximately 490 MW are considered firm
based on either operational characteristics or contractual agreement. Firm renewable generation
can be relied on to serve customers and can contribute toward the deferral of new fossil fueled
power plant construction.
The remaining renewable generation can generate energy on an as-available basis or for internal
use (self-service). As-available energy is considered non-firm, and cannot be counted on for
reliability purposes; however, it can contribute to the avoidance of burning fossil fuels in existing
generators. Self-Service generation reduces demand on Florida’s utilities.
Non-Utility Renewable Generation
The majority of Florida’s existing renewable energy generation, approximately 84 percent,
comes from non-utility generators. In 1978, the US Congress enacted the Public Utility
Regulatory Policies Act (PURPA). PURPA requires utilities to purchase electricity from
cogeneration facilities and renewable energy power plants with a capacity no greater than 80
MW (collectively referred to as Qualifying Facilities or QFs). PURPA required utilities to buy
electricity from qualifying QFs at the utility’s full avoided cost. These costs are defined in
Section 366.051, F.S., which provides in part that:
A utility’s “full avoided costs” are the incremental costs to the utility of the
electric energy or capacity, or both, which, but for the purchase from cogenerators
or small power producers, such utility would generate itself or purchase from
another source.
If a renewable energy generator can meet certain deliverability requirements, it can be paid for
by its capacity and energy output under a firm contract. Rule 25-17.250, F.A.C., requires each
IOU to establish a standard offer contract with timing and rate of payments based on each fossilfueled generating unit type identified in the utility’s TYSP. In order to promote renewable
energy generation, the Commission requires the IOUs to offer multiple options for capacity
payments, including the options to receive early (prior to the in-service date of the avoided-unit)
or levelized payments. The different payment options allow renewable energy providers the
option to select the payment option that best fits its financing requirements and provides a basis
from which negotiated contracts can be developed. On July 8, 2014, the Commission approved
standard offer contracts resulting in the continuous offering of nearly 3,484 MW for Florida’s
four largest IOUs.
As previously discussed, large amounts of renewable energy is generated on an as-available
basis. As-available energy is energy produced and sold by a renewable energy generator on an
hour-by-hour basis for which contractual commitments as to the quantity and time of delivery are
not required. As-available energy is purchased at a rate equal to the utility’s hourly incremental
system fuel cost, which reflects the highest fuel cost of generation each hour.
25
Utility Owned Renewable Generation
Utility owned renewable generation also contributes to the State’s total renewable capacity. The
majority of this generation is from solar facilities. Due to the intermittent nature of solar
resources, capacity from these facilities is considered non-firm for planning purposes.
In 2008, Section 366.92(4), F.S., was enacted and provides, in part, the following:
In order to demonstrate the feasibility and viability of clean energy systems, the
commission shall provide for full cost recovery under the environmental costrecovery clause of all reasonable and prudent costs incurred by a provider for
renewable energy projects that are zero greenhouse gas emitting at the point of the
generation, up to a total of 110 MW statewide.
In 2008, the Commission approved a petition by FPL seeking installation of the full 110 MW
across three solar energy facilities. The solar projects consisted of, a pair of solar PV facilities
and a single solar thermal facility. In response to staff interrogatories, FPL estimated that the
three solar facilities would cost an additional $573 million above traditional generation costs
over the life of the facilities. In 2012, Section 366.92, F.S., was revised and no longer includes
the passage described above.
Based on actual data provided by FPL, the combined cost of generation of the three solar
facilities was $.45/kWh in 2013. These facilities make up a significant portion of the utility
owned renewable generation. Since full operation began, the two solar PV facilities have
operated largely as expected; however, the solar thermal facility has experienced multiple
outages which have hindered its performance. Based on actual data collected from the three
facilities, the maximum output does not appear to be coincident with the system’s peak demand.
Hydroelectric units at two sites, one owned by the City of Tallahassee Utilities, and one operated
by the Federal government, supply 63 MW of renewable capacity. Because of Florida’s
geography, however, new hydroelectric power generation is largely limited.
Customer Owned Renewable Generation
With respect to customer owned renewable generation, Rule 25-6.065, F.A.C., requires the IOUs
to offer net metering for all types of renewable generation up to 2 MW in capacity and a standard
interconnection agreement with an expedited interconnection process. Net metering allows a
customer, with renewable generation capability, to offset their energy usage. In 2008, the
effective year of the discussed Rule, customer owned renewable generation accounted for 3 MW
of renewable capacity. As of 2013, approximately 63 MW of renewable capacity from nearly
6,700 systems has been installed statewide. Table 5 below, summarizes the growth of customer
owned renewable generation interconnections.
26
Table 5: State of Florida - Net Metering Growth
Year
Number of Installations
Installed Capacity (MW)
2008
577
2009
1,625
2010
2,833
2011
3,994
2012
5,302
2013
6,697
2.8
13.0
19.9
28.4
42.2
63.0
Source: Annual Net Metering Reports
Planned Renewable Additions
Florida’s utilities plan to construct or purchase an additional 722 MW of renewable generation
over the ten-year planning period. Table 6 below, summarizes the planned renewable capacity
increases by generation type.
Table 6: State of Florida - Planned Renewable Resources
Renewable Type
Municipal Solid Waste
Waste Heat
Solar
Hydro
Wind
Solid Biomass
Landfill Gas
Total of All
MW
90
0
332
0
0
272
28
722
% Total
12.4%
0.0%
46.1%
0.0%
0.0%
37.6%
3.9%
100%
Source: FRCC 2014 Load & Resource Plan and TYSP Utilities Data Responses
Of the 722 MW of planned renewable capacity, 361.5 MW is projected to be from firm
resources. All of the projected firm capacity additions are from renewable contracts with nonutility generators. Table 7 below, summarizes the firm capacity renewable resources that are
planned over the ten-year planning horizon. The remaining planned capacity from renewable
resources is projected to be from non-firm resources including several 50 MW solar facilities.
27
Table 7: Planned Firm Renewables
Purchasing
Utility
Facility Name
Fuel
Type
Capacity
(MW)
In-Service
Date
JEA
Trailridge
LFG
9.0
2014
JEA
Sarasota County
LFG
6.4
2014
RCI
Harvest Power
OBS
2.4
2014
GPC
Perdido
LFG
1.5
2015
JEA
New River
LFG
3.2
2015
OUC
LFG
9.0
2015
MSW
90.0
2015
DEF
Shaw Environmental
Solid Waste Authority of Palm Beach
County
Unknown - US EcoGen
WDS
60.0
2017
FPL
Ecogen Clay
OBS
60.0
2021
FPL
Ecogen Martin
OBS
60.0
2021
FPL
Ecogen Okeechobee
OBS
60.0
2021
FPL
Total of All
361.5
Source: FRCC 2014 Load & Resource Plan and TYSP Utilities Data Responses
More than 170 MWs of contracted firm renewable capacity are projected to expire within the
ten-year planning. If new contracts are signed in the future to replace those that expire, these
resources will once again be included in the state’s capacity mix to serve future demand. If these
contracts are not extended, the renewable facilities could still deliver energy on an as-available
basis.
Renewable Outlook
The Commission, in conjunction with the U.S. Department of Energy and the Lawrence
Berkeley National Laboratory, retained Navigant Consulting, Inc. (Navigant) to prepare a
detailed assessment of Florida’s renewable potential in 2008. Navigant’s assessment identified
several key drivers that impact renewable energy development in Florida. Three of the “key
drivers” were the cost of the natural gas, the cost of CO2, and the adoption of a Renewable
Portfolio Standard (RPS).
Under the scenario considered to be favorable in fostering renewable generation, Navigant
assumed natural gas prices between $11-$14/MMBTU, CO2 emission costs ($2/ton initially,
then scaling to $50/ton by 2020) and the adoption of an RPS in Florida. At this time, natural gas
prices are projected at $4.40/MMBTU in 2014, there is no current federal pricing for CO2
emissions, and no RPS legislation has been enacted. Therefore, current market conditions do not
favor the development of renewable generation.
Even with these difficulties, Florida’s renewable generation is projected to increase over the
planning period. Renewable generation contributes to the state’s fuel diversity and reduces
dependence on fossil fuels. While current economic conditions may prevent more expensive
forms of renewable generation, those cost-effective forms of renewable generation will continue
to increase the state’s share of renewable generation.
28
Traditional Generation
While renewable generation increases its contribution to the state’s generating capacity, a
majority of generation is projected to come from traditional sources, such as fossil-fueled steam
and turbine generators that have been added to Florida’s electric grid over the last several
decades. Due to forecasted increases in peak demand, further traditional resources are
anticipated over the planning period.
Florida’s electric utilities have historically relied upon several different fuel types to serve
customer load. Previous to the oil embargo, Florida used oil-fired generation as its primary
source of electricity until the increase in oil prices made this undesirable. Since that time,
Florida’s electric utilities have sought a variety of other fuel sources to diversify the state’s
generation fleet to more reliably and affordably serve customers. Numerous factors, including
swings in fuel prices, availability, environmental concerns, and other factors have resulted in a
variety of capacity on Florida’s electric grid. Solid fuels such as coal and nuclear increased
during the shift away from oil-fired generation, and more recently natural gas has emerged as the
dominant fuel type in Florida.
Existing Generation
Florida’s generating fleet includes incremental new additions to a historic base fleet, with units
retiring as they become uneconomical to operate or maintain. Currently, Florida’s existing
capacity ranges greatly in age and fuel type, and legacy investments continue. The weighted
average age of Florida’s generating units is 23 years. While the original commercial in-service
date may be in excess of 60 years for some units, they are constantly maintained as necessary in
order to ensure safe and reliable operation, including uprates from existing capacity which may
have been added after the original in-service date. Figure 11 below, illustrates the decade
currently operating generating capacity was originally added to the grid, with the largest
additions occurring in the 2000s.
29
Figure 11: Florida Electric Utility Installed Capacity by Decade
Source: 2014 FRCC Load & Resource Plan
The existing generating fleet will be impacted by several events over the planning period. New
and proposed environmental regulations may require changes in unit dispatch, fuel switching, or
installation of pollution control equipment which may reduce net capacity. Modernizations will
allow more efficient resources to replace older generation while potentially reusing power plant
assets such as transmission and other facilities, switching to more economic fuel types, or uprates
at existing facilities to improve power output. Lastly, retirements of units which can no longer
be economically operated and maintained or meet environmental requirements will reduce the
existing generation.
Impact of EPA Rules
In addition to maintaining a fuel efficient and diverse fleet, Florida’s utilities must also comply
with changing environmental requirements.
During the past several years, the U.S.
Environmental Protection Agency (EPA) has finalized or proposed several rules which will
impact both existing and planned generating units in the state. Environmental requirements and
associated costs must be considered to fully evaluate any new supply-side resources, as well as
the operation of existing generating units.
Six EPA rules are anticipated to affect electric generation in Florida:
•
Carbon Pollution Emissions Standards for Modified and Reconstructed Secondary
Sources: Electric Utility Generating Units – Sets carbon dioxide emissions limits for
modified or reconstructed electric generators. These limits vary by type of fuel
(coal/IGCC or natural gas), size of unit (less than or above approximately 100
megawatts), and whether the unit is modified or reconstructed. This rule was proposed
by the EPA on June 18, 2014, and has not yet been finalized.
30
•
Carbon Pollution Emission Guideline for Existing Electric Generating Units – Requires
each state to submit a plan to EPA that outlines how the state’s existing electric
generation fleet will meet a series of goals, in terms of pounds of carbon dioxide emitted
per generated megawatt-hour, to reduce the state’s carbon dioxide emissions. The
guidelines will apply to a statewide average of all generating units over 25 megawatts.
EPA proposed this rule on June 18, 2014, and anticipates finalizing it by June 2015, with
state plans to be filed by June 2016, with possible one-year extensions. The Commission
has sought comments from interested parties to be filed with the EPA, which has
extended the period to file comments until December 1, 2014.
•
Mercury and Air Toxics Standards (MATS) - Sets limits for air emissions from existing
and new coal- and oil-fired electric generators with a capacity greater than 25 megawatts.
Covered emissions include: mercury and other metals, acid gases, and organic air toxics
for all generators, as well as particulate matter, sulfur dioxide, and nitrogen oxide from
new and modified coal and oil units. On April 15, 2014, U.S. Court of Appeals for the
D.C. Circuit fully upheld the rule. This decision will not become active, however, until
all appeals have been resolved.
•
Cross-State Air Pollution Rule (CSAPR) - Requires 28 states, including Florida, to
reduce air emissions that contribute to ozone and/or fine particulate pollution in other
states. The rule applies to all fossil-fueled (i.e., coal, oil, and natural gas) electric
generators with a capacity over 25 megawatts within these states. Florida is only subject
to the rule’s seasonal NOx emissions requirements. On April 29, 2014, the U.S. Supreme
Court upheld the rule by a 6-2 vote. On June 26, 2014, EPA asked the U.S. Court of
Appeals for the D.C. Circuit to lift its stay on the rule. The court has not yet acted on this
request, and it is not clear at this time if or when the stay will be lifted.
•
Cooling Water Intake Structures (CWIS) - Sets impingement standards to reduce harm to
aquatic wildlife pinned against cooling water intake structures at electric generating
facilities. All existing electric generators that use water for cooling with an intake
velocity of at least two million gallons per day must meet impingement standards.
Generating units with higher intake velocity may have additional requirements to reduce
the damage to aquatic wildlife due to entrapment in the cooling water system
(entrainment). On May 28, 2014, the final rule was published in the Federal Register.
•
Coal Combustion Residuals (CCR) - Requires liners and ground monitoring to be
installed on new landfills in which coal ash is deposited. A Consent Decree, filed
January 29, 2014, in the U.S. District Court for the District of Columbia, requires EPA to
publish notice of a final action by December 19, 2014.
For many of the units that will remain in operation, these new rules will result in an increased
cost of operations. Each utility will need to evaluate whether these additional costs or new
operational limitations allow the continued economic operation of each affected unit, and
whether installation of emissions control equipment, fuel switching, or retirement is the proper
course of action.
31
Modernization and Efficiency Improvements
Modernizations involve removing existing generator units that may no longer be economical to
operate, such as oil-fired steam units, and reusing the power plant site’s transmission or fuel
handling facilities with a new set of generating units. The modernization of existing plant sites
allows for significant improvement in both performance and emissions, typically at a lower price
than new construction at a greenfield site. Not all sites are candidates for modernization due to
site layout and other concerns, and to minimize rate impacts, modernization of existing units
should be considered along with new construction at greenfield sites.
The Commission has previously granted determinations of need for several conversations of oilfired steam units to natural gas-fired combined cycle units, including FPL’s Cape Canaveral,
Riviera, and Port Everglades power plants. DEF has also recently conducted a conversion of its
Bartow power plant, but this did not require a determination of need from the Commission.
Utilities also plan several efficiency improvements to existing generating units. An example is
the conversion of existing simple cycle combustion turbines into a combined cycle unit, which
captures the waste heat and uses it to generate additional electricity using a steam turbine. The
Commission has granted a determination of need for the conversion of TECO’s Polk Units 2
through 5 to a single combined cycle unit. FPL plans on upgrades to its existing combined cycle
fleet by improving the performance of the integrated combustion turbines at many of its current
and planned power plants. DEF plans to upgrade the capacity of its Hines combined cycle units
by installing chiller modules.
Planned Retirements
Power plant retirements occur when the electric utility is unable to economically operate or
maintain a generating unit due to environmental, economic, or technical concerns. Table 8
below, lists the 4,252 MW of existing generation that is scheduled to be retired during the
planning period, a majority of which is natural gas-fired peaking units. Approximately 1,260
MW of the planned retirements are three dozen small peaking units at two power plant sites
operated by FPL.
A notable retirement is DEF’s Crystal River Units 1 and 2. Originally scheduled to retire in
2016, the retirement of these units have been delayed until 2018. This delay is due in part to a
temporary averaging of emissions across the existing four units at the Crystal River site to meet
environmental regulations, as Crystal River Units 4 and 5 have pollution controls installed.
Some retired units will continue operation in a different form. FPL intends to retire Turkey Point
1, a large oil-fired steam unit, and convert it to a synchronous condenser to support the
transmission system and provide voltage regulation. FPL previously converted Turkey Point 2 to
operate as a synchronous condenser.
32
Table 8: Electric Generating Units to be Retired
Year
Utility
Name
Plant Name
& Unit Number
Unit Type
Fuel Type
Net
Summer
Capacity
(MW)
2014
NSB
Smith (3-4,6-11)
Internal Combustion
Oil
13
2014
NSB
Swoope Station (2-4)
Internal Combustion
Oil
5
2014
DEF
G. E. Turner P3
Combustion Turbine
Oil
53
2014
JEA
Girvin Landfill
Internal Combustion
Landfill Gas
1
2014 Subtotal
72
2015
FPL
Municipal Plant 1 & 3-4
Steam
Natural Gas
94
2015
JEA
Northside
Steam
Natural Gas
524
2015
TAL
Hopkins GT1
Combustion Turbine
Natural Gas
12
2015
TAL
Purdom GT1&2
Combustion Turbine
Natural Gas
20
2015
FPL
Putnam 1 & 2
Combined Cycle
Natural Gas
498
2015
GULF
Scholz 1 & 2
Steam
Coal
92
2015 Subtotal
1,240
2016
DEF
Avon Park P2
Combustion Turbine
Oil
24
2016
DEF
Rio Pinar P1
Combustion Turbine
Oil
12
2016
DEF
G. E. Turner P1&2
Combustion Turbine
Oil
20
2016
DEF
Avon Park
Combustion Turbine
Natural Gas
24
2016 Subtotal
80
2017
FPL
Turkey Point 1
Steam
Oil
396
2017
TAL
Hopkins GT2
Combustion Turbine
Natural Gas
24
2017 Subtotal
2018
DEF
Crystal River 1 & 2
2018
DEF
Suwannee River 1-3
2018
GPC
Pea Ridge 1-3
2018
FPL
Lauderdale 1-24
2018
FPL
2018
FPL
420
Steam
Coal
740
Steam
Natural Gas
128
Combustion Turbine
Natural Gas
12
Combustion Turbine
Natural Gas
840
Port Everglades 1-12
Combustion Turbine
Natural Gas
420
Municipal Plant 2&5
Combined Cycle
Natural Gas
44
2018 Subtotal
2020
DEF
Higgins P1-4
2020
TAL
2022
GRU
2,184
Combustion Turbine
Natural Gas
105
Hopkins
Steam
Natural Gas
76
Deerhaven
Steam
Natural Gas
75
2022 Subtotal
75
Total Retirements
4,252
2020 Subtotal
Source: 2014 FRCC Load & Resource Plan, 2014 Ten-Year Site Plans
33
181
JEA’s Northside 5, a natural gas and oil-fired steam unit, was scheduled for retirement in 2019 in
the utility’s Ten-Year Site Plan, but subsequently JEA announced that the retirement would be
accelerated by four years to 2015.
Reliability Requirements
Florida’s electric utilities are expected to have enough generating assets available at the time of
peak demand to meet forecasted customer demand. Potential instabilities could occur if
customer demand exceeds the forecast or if generating units are unavailable due to maintenance
or forced outages. To address these circumstances, utilities are required to maintain additional
planned generating capacity above the forecasted customer demand, referred to as the reserve
margin.
Electric utilities within the Florida Reliability Coordinating Council region, which consists of
Peninsular Florida, must maintain a minimum of 15 percent reserve margin for planning
purposes. Certain utilities have elected to have a higher reserve margin, either on an annual or
seasonal basis. The three largest reporting electric utilities, FPL, DEF, and TECO, are party to a
stipulation approved by the Commission that utilizes a 20 percent reserve margin for planning.
While Florida’s electric utilities are separately responsible for maintaining an adequate planning
reserve margin, a statewide view illustrates the degree to which capacity may be available for
purchases during periods of high demand or unit outages. Figure 12 below, is a projection of the
statewide seasonal reserve margin including all proposed power plants.
Role of Demand Response in Reserve Margin
The Commission also considers the planning reserve margin without demand response. As
illustrated in Figure 12 below, the statewide seasonal reserve margin exceeds the FRCC’s
required 15 percent planning reserve margin without activation of demand response. Demand
response activation increases the reserve margin in the summer by 8 percent on average, and
represents 30 percent of the planning reserve margin.
Demand response participants receive discounted rates or credits regardless of activation, with
these costs recovered from all ratepayers. Because of the voluntary nature of demand response, a
concern exists that a heavy reliance upon this resource would make participants eschew the
discounted rates or credits for firm service. For interruptible customers, participants must
provide notice that they intend to leave the demand response program, with a notice period of
three or more years being typical. For load management participants, usually residential or small
commercial customers, no advanced notice is typically required to leave. Historically, demand
response participants have rarely been called upon during the peak hours, but are more
frequently called upon during off-peak periods due to other reliability concerns. This trend is
assumed to continue during the planning period.
34
Figure 12: State of Florida Reserve Margin with New Units
Source: 2014 FRCC Load & Resource Plan
Fuel Price Forecast
In general, the capital cost of a power plant is inversely proportional to the cost of the fuel used
to generate electricity from that unit. However, fuel price is an important economic factor
affecting the dispatch of the existing generating fleet and the selection of new generating units.
The major fuels consumed by Florida’s electric utilities are natural gas, coal, uranium, and oil.
Figure 13 below, illustrates the weighted average fuel price history and forecasts for the
reporting electric utilities.
35
Figure 13: Average Reporting Electric Utility Fuel Price
Source: 2014 TYSP Utilities Data Responses
As Figure 14 below shows, the price of natural gas declined rapidly after the financial crisis, and
is forecasted to remain near historically low levels. The smaller differential and higher
efficiency of natural gas has shifted the dispatch order, with natural gas units displacing coal
units. The trend has also encouraged utilities to modify existing units to be capable of burning
natural gas, either as a starter fuel, supplemental fuel, or primary fuel.
Figure 14: Fuel Price Comparison for Coal and Natural Gas
Source: 2014 TYSP Utilities Data Responses
36
Fuel Diversity
The volatility of natural gas in the early 2000s led to concern regarding escalating customer bills
and an expectation that natural gas prices would remain high. While Florida’s electric utilities
made plans to build coal-fired units rather than continuing to increase the reliance on natural gas,
concerns regarding potential environmental regulations and other projected costs lead to
cancellation of new coal-fired generation. Traditionally, coal was the lowest cost fuel besides
nuclear and was dispatched before most natural gas-fired units. Natural gas has since risen to
become the dominant fuel in Florida within the last ten years, displacing coal, and since 2010 has
generated more net energy for load than all other fuels combined. As Figure 15 illustrates,
natural gas is the source of approximately 60 percent of electric energy consumed in Florida,
down from its peak in 2012 of 65 percent. The 2012 spike in natural gas usage was associated
with extended outages at FPL’s nuclear plants for uprates, with gas usage decreasing as the
nuclear units returned to operation. Natural gas generation is anticipated to serve future growth
until the end of the planning period, when additional nuclear generation comes online.
Figure 15: Natural Gas Contribution to Florida Energy Consumption
Source: 2005-2014 FRCC Load & Resource Plans
Because a balanced fuel supply can enhance system reliability and mitigate the effects of
volatility in fuel price fluctuations, it is important that utilities have a level of flexibility in their
generation mix. Maintaining fuel diversity on Florida’s system faces several difficulties.
Existing coal units will require additional emissions control equipment leading to reduced
output, or retirement, if the emissions controls are uneconomic to install or operate. New solid
fuel generating units such as nuclear and coal have long lead times and high capital costs. New
coal units face challenges relating to new environmental compliance requirements, making it
unlikely they could be permitted without novel emissions control technology.
Figure 16, shows Florida’s historic and forecast percent net energy for load by fuel type for the
actual years 2003 and 2013, and forecast year 2023. Oil has declined significantly, with its uses
37
reduced to start-up fuel, peaking, and back-up for dual-fuel units in case of a fuel outage.
Nuclear generation was reduced beginning in 2010 by the outage and eventual retirement of
Crystal River 3 and extended outages for uprates at FPL’s St. Lucie and Turkey Point power
plants. The uprates of Florida’s four remaining nuclear units were completed by 2013, and
added approximately 520 MW of capacity, reducing the impact of the loss of Crystal River 3.
While coal generation has declined somewhat, it is expected to rebound slightly and remain at a
plateau throughout the planning period. This rebound was based upon the Utility’s filings before
the announcement of the EPA’s Clean Power Plan. The 2015 Ten-Year Site Plans should
include some considerations of the potential impacts of this regulation on each utility’s fuel
consumption. Natural gas has been the primary fuel used to meet the growth energy
consumption, and this trend is anticipated to continue throughout the planning period.
Figure 16: Florida Historic and Forecast Fuel Consumption
Source: 2005-2014 FRCC Load & Resource Plans
New Generation Planned
Current demand and energy forecasts continue to indicate that in spite of increased levels of
conservation, energy efficiency, renewable generation, and existing traditional generation
resources, the need for additional generating capacity still exists. While reductions in demand
have been significant, the total demand for electricity is expected to increase, making the
addition of traditional generating units necessary to satisfy reliability requirements and provide
sufficient electric energy to Florida’s consumers. Because any capacity addition has certain
economic impacts based on the capital required for the project, and due to increasing
environmental concerns relating to solid fuel-fired generating units, Florida’s utilities must
carefully weigh the factors involved in selecting a supply-side resource for future traditional
generation projects.
In addition to traditional economic analyses, utilities also consider several strategic factors, such
as fuel availability, generation mix, and environmental compliance prior to selecting a new
38
supply-side resource. Limited supplies, access to water or rail delivery points, pipeline capacity,
water supply and consumption, land area limitations, cost of environmental controls, and
fluctuating fuel costs are all important considerations.
Figure 17 below, illustrates the present and future aggregate capacity mix. The capacity values
in Figure 17 incorporate all proposed additions, changes, and retirements contained in the
reporting utilities’ 2014 Ten-Year Site Plans and the FRCC’s 2014 Load and Resource Plan.
Figure 17: Florida Current and Projected Installed Capacity by Fuel and Technology
Source: 2014 FRCC Load & Resource Plan and TYSP Utilities Data Responses
New Power Plants by Fuel Type
Nuclear
Nuclear capacity, while an alternative to natural gas-fired generation, is capital-intensive and
requires a long lead time to construct. Only a single Florida electric utility, Florida Power &
Light, is projecting additional nuclear power plants during the planning period. Table 9 below,
39
lists the two new nuclear units anticipated in the planning period, Turkey Point units 6 and 7.
Florida Power & Light had previously uprated its existing four nuclear generating units, with the
last uprate completed in early 2013. While Duke Energy Florida had previously projected the
addition of two nuclear units, Levy 1 and 2, it has discontinued this project but continues its
efforts to obtain a combined operating license from the Nuclear Regulatory Commission.
Table 9: Planned Nuclear Units
Net Capacity
(MW)
Sum
Win
In-Service
Year
Utility
Name
Plant Name
& Unit Number
Unit Type
2022
FPL
Turkey Point 6
Nuclear Steam
1,100
1,100
2023
FPL
Turkey Point 7
Nuclear Steam
1,100
1,100
Source: 2014 Ten-Year Site Plans
Natural Gas
All remaining new utility owned power plants are natural gas-fired combustion turbines or
combined cycle units. Natural gas-fired combined cycle units represent 39.1 percent of installed
capacity in 2013. Combustion turbines, which run in simple cycle mode as peaking units,
represent the third most abundant type of generating capacity, behind only coal-fired steam
generation. Because combustion turbines are not a form of steam generation, they do not require
siting under the Power Plant Siting Act. Table 10 below, lists the approximate 10,363 MW net
summer capacity of proposed new natural gas-fired generation included in the 2014 Ten-Year
Site Plans.
40
Table 10: Planned Natural Gas Units
Net Capacity
(MW)
Sum
Win
In-Service
Year
Utility
Name
Plant Name
& Unit Number
Unit Type
2014
FPL
Riviera Beach
Combined Cycle
1,212
1,344
2016
FPL
Port Everglades
Combined Cycle
1,237
1,346
2017
TECO
Polk
Combined Cycle
459
463
2018
DEF
Citrus
Combined Cycle
1,640
1,820
2019
FPL
Unsited
Combined Cycle
1,269
1,429
2020
SEC
Unsited
Combined Cycle
440
523
2021
DEF
Unsited
Combined Cycle
793
866
7,050
7,791
316
375
Combined Cycle Subtotal
2016
DEF
Suwannee River 3 & 4 Combustion Turbine
2019
FPL
Lauderdale CT1-5
Combustion Turbine
1,005
1,000
2020
TAL
Hopkins 5
Combustion Turbine
46
48
2020
TECO
Future CT1
Combustion Turbine
190
220
2020
SEC
Unsited CT 1 & 2
Combustion Turbine
402
450
2021
SEC
Unsited CT 3-7
Combustion Turbine
1,005
1,125
2023
GPC
Unsited CT
Combustion Turbine
349
360
3,313
Total Planned Natural Gas Units 10,363
3,578
11,369
Combustion Turbine Subtotal
Source: 2014 Ten-Year Site Plans
Commission’s Authority over Siting
The Commission has been given exclusive jurisdiction to determine the need for new electric
power plants by the Legislature through the Power Plant Siting Act (PPSA) at Section 403.519,
F.S. Any proposed steam or solar generating unit of at least 75 MW requires a certification
under the PPSA. Upon receipt of a determination of need, the electric utility would then seek
approval from the Florida Department of Environmental Protection, which addresses land use
and environmental concerns. Finally, the Governor and Cabinet, sitting as the Siting Board,
must approve or deny the overall certification of a proposed power plant.
Approximately 12,565 MW of new utility-owned generating units are planned to enter service
over the next ten-year period, with 74 percent of that capacity, 9,250 MW, subject to the PPSA.
However, a majority of the proposed units have already received a determination of need from
the Commission. The Commission most recently approved the determination of need for DEF’s
proposed Citrus plant, which will still have to seek approval from DEP and the Siting Board. A
total of 2,502 MW still requires a determination of need, as shown in Table 11 below.
41
Table 11: Planned Units Requiring a Determination of Need
Net Capacity
(MW)
Sum
Win
In-Service
Year
Utility
Name
Plant Name
& Unit Number
Unit Type
2018
DEF
Citrus
Combined Cycle
1,640
1,820
2019
FPL
Unsited
Combined Cycle
1,269
1,429
2020
SEC
Unsited
Combined Cycle
440
523
2021
DEF
Unsited
Combined Cycle
793
866
Notes
See Order No.
PSC-14-0557-FOF-EI
Source: 2014 Ten-Year Site Plans
Transmission
The Commission has been given broad authority pursuant to Chapter 366, F.S., to require
reliability within Florida’s coordinated electric grid and to ensure the planning, development, and
maintenance of adequate generation, transmission, and distribution facilities within the state. As
generation capacity increases, the transmission system must grow accordingly to maintain the
capability of delivering energy to end users.
The Commission has been given sole jurisdiction to determine the need for new electric
transmission lines by the Legislature through the Florida Electric Transmission Line Siting Act
(TLSA) at Section 403.537, F.S. To require certification under Florida’s TLSA, a proposed
transmission line must meet the following criteria: a nominal voltage rating of at least 230 kV,
crossing a county line, and a length of at least 15 miles. Proposed lines in an existing corridor
are exempt from TLSA requirements. The Commission determines the reliability need and the
proposed starting and end points for lines requiring TLSA certification. The proposed corridor
route is subsequently determined by the Florida DEP during the certification process. Much like
the PPSA, the Governor and Cabinet sitting as the Siting Board ultimately must approve or deny
the overall certification of a proposed line.
Table 12 below, lists all proposed transmission lines in the 2014 Ten-Year Site Plans that require
TLSA certification. All planned lines have already received the approval of the Commission,
either independently or as part of a PPSA determination of need.
Table 12: Planned Transmission Lines
Line
Nominal
Date
Date
In-Service
Utility
Transmission Line
Length
Voltage
Need
TLSA
Date
FPL
FPL
TECO
TECO
Manatee – Bobwhite
St Johns – Pringle
Thonotosassa - Wheeler
Wheeler - Willow Oak
(Miles)
30
25
8
17
(kV)
230
230
230
230
Approved
8/28/2006
5/13/2005
6/22/2007
6/23/2007
Certified
11/06/2008
4/01/2006
8/08/2008
8/09/2008
12/01/2014
12/01/2018
TBD
TBD
Source: 2014 Ten-Year Site Plans
42
UTILITY PERSPECTIVES
43
Florida Power & Light Company (FPL)
FPL is an investor-owned utility and Florida’s largest electric utility. The utility’s service
territory is within the FRCC region and is primarily in south Florida and along the east coast. As
an investor-owned utility, the Commission has regulatory authority over all aspects of
operations, including rates, reliability, and safety. Pursuant to Section 186.801(2), F.S., the
Commission finds FPL’s 2014 Ten-Year Site Plan suitable for planning purposes.
Load & Energy Forecasts
In 2013, FPL had approximately 4,627,000 customers and annual retail energy sales of 102,784
GWh, or approximately 47.4 percent of Florida’s annual retail energy sales. Figure 18,
illustrates the company’s historic and forecast number of customers and retail energy sales, in
terms of percentage growth from 2004. Over the last ten years, FPL’s customer base has
increased by 9.5 percent, while retail sales have grown by only 3.7 percent. Since 2009, FPL has
been outperforming the state average in retail energy sale growth, a trend it projects to continue
into the future. As illustrated below, retail energy sales are anticipated to exceed their historic
2007 peak in 2014, three years faster than the state as a whole. This forecast includes FPL’s
acquisition of the Vero Beach electric system beginning in 2015, which is estimated to represent
0.6 percent of FPL’s 2023 net energy for load.
Figure 18: FPL Growth Rate
Source: 2014 Ten-Year Site Plan
The three graphs in Figure 19 shows, FPL’s seasonal peak demand and net energy for load for
the historic years of 2004 through 2013 and forecast years 2014 through 2023. These graphs
include the impact of demand-side management, and for future years assume that all available
demand response resources will be activated during the seasonal peak. Historically, demand
response was not activated during the seasonal peak demand, excluding the winters of 2010 and
2011.
44
Figure 19: FPL Demand and Energy Forecasts
Source: 2014 Ten-Year Site Plan and Data Responses
45
As an investor-owned utility, FPL is subject to FEECA and currently offers energy efficiency
and demand response programs to customers to reduce peak demand and annual energy
consumption. For planning purposes, FPL utilized its proposed demand-side management goals
for the forecast period. The utility’s 2015 Ten-Year Site Plan should include revised values that
would reflect the Commission’s decision in the currently open FEECA goal-setting Docket No.
130199-EI.
Fuel Diversity
Table 13 below shows, FPL’s actual net energy for load by fuel type as of 2013, and the
projected fuel mix for 2023. FPL relies primarily upon natural gas and nuclear for energy
generation, making up approximately 90 percent of net energy for load.
Table 13: FPL Energy Consumption by Fuel Type
Net Energy for Load
Fuel Type
2013
GWh
2023
%
GWh
%
Natural Gas
75,208
67.4%
76,379
Coal
5,981
5.4%
6,779
5.1%
Nuclear
25,243
22.6%
42,915
32.4%
Oil
196
0.2%
123
0.1%
Renewable
155
0.1%
192
0.1%
Interchange
4,445
4.0%
0
0.0%
428
0.4%
5,968
4.5%
NUG & Other
Total
111,656
57.7%
132,356
Source: 2014 Ten-Year Site Plan and Data Responses
Reliability Requirements
While previously only reserve margin has been discussed, Florida’s utilities use multiple indices
to determine the reliability of the electric supply. An additional metric is the Loss of Load
Probability (LOLP), which is a probabilistic assessment of the duration of time electric customer
demand will exceed electric supply, and is measured in units of days per year. FPL uses a
maximum LOLP of no more than 0.1 days per year, or approximately 1 day of outage per ten
years. Between the two reliability indices, LOLP and reserve margin, the reserve margin
requirement is typically the controlling factor for the addition of capacity.
Since 1999, FPL has utilized a 20 percent planning reserve margin criterion. Figure 20 below,
displays the forecast planning reserve margin for FPL through the planning period for both
seasons, with and without the use of demand response. As shown in the figure, FPL’s generation
needs are controlled by its summer peak throughout the planning period.
46
Figure 20: FPL Reserve Margin Forecast
Source: 2014 Ten-Year Site Plan
Proposed Third Reliability Requirement
In addition to these two reliability indices, FPL is proposing in its 2014 Ten-Year Site Plan to
introduce a third reliability criterion. FPL’s proposed requirement would be to have available
firm capacity 10 percent greater than the sum of customer seasonal demand, without
consideration of incremental energy efficiency and all existing and incremental demand response
resources. FPL refers to this as its 10 percent generation-only reserve margin. Currently, no
other utility has proposed a similar metric. While TECO includes a minimum supply-side
contribution in its planning methodology, TECO uses a lower value of seven percent and
incremental energy efficiency is included in its calculation.
47
While FPL proposes to not include incremental energy efficiency resources and cumulative
demand response in its resource planning for the proposed metric, the utility would remain
subject to FEECA and the conservation goals established by the Commission. FPL would
continue paying rebates and other incentives to participants, which are collected from all
ratepayers through the Energy Conservation Cost Recovery Clause, but would not consider the
potential capacity reductions of any future participation in energy efficiency or demand response
programs during the ten-year planning period for planning purposes with this new reliability
criterion.
Energy efficiency, which includes installation of equipment designed to reduce peak demand and
annual energy consumption, is considered a passive resource. While demand response must be
activated by the utility, energy efficiency provides benefits consistently for the duration of the
installation, reducing annual energy consumption, and if usage is coincident with system peak,
peak demand. Customers do not remove building envelope improvements or newly installed
equipment until the end of its service life for replacement.
As noted in the Statewide Perspective, the Commission does review the impact on reserve
margin of demand response resources. At this time, FPL offers two types of demand response
programs. The first type is interruptible and curtailable load programs, consisting of the
Commercial/Industrial Load Control Program (CILC) and Commercial/Industrial Demand
Reduction Rider (CDR) tariffs. The second type is load management programs, including the
Residential On-Call and Business On-Call Programs.
FPL expresses a that an over-reliance upon demand response will result in frequent customer
interruptions, which will in turn, cause customers to end their voluntary participation, which
could negatively impact reliability. FPL addresses this concern for large commercial and
industrial customers by including minimum noticing requirements for customers to leave the
CILC and CDR tariffs. Customers must provide five years notice before the customer is able to
end participation, excluding special provisions. This is sufficient time for a utility to plan a unit
to provide firm capacity. In contrast, the Residential On-Call and Business On-Call programs
have only a seven day advanced notice requirement. However, each individual customer’s
demand reduction for these programs is much smaller.
As previously noted, FPL has historically not activated demand response customers during
seasonal peaks, excluding two winter peaks in which only CILC and CDR customers were
activated. Regardless of whether or not demand response capacity is activated, participants
receive bill credits or discounted rates. It should be noted that peak reductions during annual
peaks, which is the focus of a reserve margin, are not the only use for demand response. In fact,
FPL reports a total of 144 activations within the past ten years of its demand response resources,
with an average 11 activations per summer and 4 activations per winter. Only seven of the 144
activations included CILC and CDR participants.
While FPL’s proposed generation-only reserve margin would increase the amount of capacity
required for all years of the planning period, based upon the timing of other unit additions, it is
the controlling factor for two years of the ten-year planning period. In 2020 and 2021, FPL
would increase firm capacity purchases by 113 MW and 130 MW, respectively, to meet the
48
proposed metric. At this time, FPL has not yet entered into purchased power agreements for this
additional capacity. Without these additional purchases, FPL’s generation only reserve margin,
excluding demand response and incremental energy efficiency would be 9.6 percent in 2020 and
9.5 percent in 2021. If the impact of incremental energy efficiency is included, the generationonly reserve margin would exceed 10 percent for both 2020 and 2021. During the years of 2020
and 2021, the statewide summer reserve margin would be in excess of 17 percent without
activating demand response, so it is likely that additional power would be available for purchase
in case of high demand.
As part of FEECA, the Commission annually publishes a report on the accomplishments of the
FEECA Utilities, of which FPL is one, towards meeting conservation goals established by the
Commission. The Commission monitors and tracks the anticipated and actual program
participation and savings associated with the utility’s conservation programs, including energy
efficiency and demand response. If participation in a program is less than anticipated, the utility
has the opportunity to respond by modifying the program. This annual review mechanism would
therefore alert the Commission if a utility were not meeting its conservation goals and allow
steps to be taken to adjust as necessary.
At this time, while FPL has noted its use of this metric in several dockets before the
Commission, the utility has not requested approval to use this metric or its value, nor does the
Commission’s suitability finding of FPL’s 2014 Ten-Year Site Plan constitute approval. The
Commission will have an opportunity to review FPL’s proposed metric if it becomes a
controlling factor for a determination of need of a new electrical power plant.
Generation Resources
FPL plans multiple unit retirements and additions during the planning period, as described below
in Table 14. Three dozen of the retirements are small natural gas-fired combustion turbines used
as peakers, to be replaced by five new units that will offer superior efficiency and emissions
profiles. FPL’s 2014 Ten-Year Site Plan includes the acquisition of Vero Beach’s generating
units, which are all planned for retirement by 2018. Lastly, FPL is converting Turkey Point 1 to
operate as a synchronous condenser to support the transmission system in South Florida.
In addition to the peaking units discussed above, FPL included the addition of three new natural
gas-fired combined cycle units and two new nuclear steam units. Only one of the combined
cycles has yet to receive a determination of need from the Commission, with a filing anticipated
sometime during 2015.
49
Table 14: FPL Unit Retirements and Additions
Year
Plant Name
& Unit Number
Unit Type
Net Capacity
(MW)
Sum
Win
Notes
Retiring Units
2017
Turkey Point 1
2015
2015
2018
2018
2018
Municipal Plant 1 & 3-4
Putnam 1 & 2
Lauderdale 1-24
Port Everglades 1-12
Municipal Plant 2&5
Oil
Steam
Natural Gas
Steam
Combined Cycle
Combustion Turbine
Combustion Turbine
Combined Cycle
396
398
Synchronous Condenser
94
498
840
420
44
98
529
917
458
46
From Vero Beach
1,212
1,237
1,269
1,005
1,344
1,346
1,429
1,000
In Service
Previously Approved
Requires Approval
1,100
1,100
1,100
1,100
Previously Approved
Previously Approved
From Vero Beach
New Units
2014
2016
2019
2019
Riviera Beach Energy Center
Port Everglades Modernization
Unsited Combined Cycle
Lauderdale CT1-5
2022
2023
Turkey Point 6
Turkey Point 7
Natural Gas
Combined Cycle
Combined Cycle
Combined Cycle
Combustion Turbine
Nuclear
Steam
Steam
Source: 2014 Ten-Year Site Plan and Data Responses
50
Duke Energy Florida, Inc. (DEF)
DEF is an investor-owned utility and Florida’s second largest electric utility. The utility’s
service territory is within the FRCC region and is primarily in central and west central Florida.
As an investor-owned utility, the Commission has regulatory authority over all aspects of
operations, including rates, reliability, and safety. Pursuant to Section 186.801(2), F.S., the
Commission finds DEF’s 2014 Ten-Year Site Plan suitable for planning purposes.
Load & Energy Forecasts
In 2013, DEF had approximately 1,657,000 customers and annual retail energy sales of 36,616
GWh, or approximately 16.9 percent of Florida’s annual retail energy sales. Figure 21,
illustrates the company’s historic and forecast number of customers and retail energy sales, in
terms of percentage growth from 2004. Over the last ten years, DEF’s customer base has
increased by 6.88 percent, while retail sales have declined by 4.13 percent. As illustrated below,
retail energy sales are anticipated to exceed the historic 2006 peak by 2020, three years later than
the state as a whole.
Figure 21: DEF Growth Rate
Source: 2014 Ten-Year Site Plan
The three graphs in Figure 22 show, DEF’s seasonal peak demand and net energy for load for the
historic years of 2004 through 2013 and forecast years 2014 through 2023. These graphs include
the full impact of demand-side management, and assume that all available demand response
resources were or will be activated during the seasonal peak. Historically, demand response has
not been activated during seasonal peak demand excluding extreme weather events. As an
investor-owned utility, DEF is subject to FEECA and currently offers energy efficiency and
demand response programs to customers to reduce peak demand and annual energy
consumption. DEF based its estimated conservation values off of its existing demand-side
management portfolio. The utility’s 2015 Ten-Year Site Plan should include revised values that
would reflect the Commission’s decision in the currently open FEECA goal-setting docket.
51
Figure 22: DEF Demand and Energy Forecasts
Source: 2014 Ten-Year Site Plan and Data Responses
52
Fuel Diversity
Table 15 below shows, DEF’s actual net energy for load by fuel type as of 2014 and the
projected fuel mix for 2023. DEF relies primarily upon natural gas and coal for energy
generation, making up approximately 80 percent of net energy for load. DEF plans to
substantially reduce coal usage over the planning period, but coal usage will be greater than all
other energy types excluding natural gas.
Table 15: DEF Energy Consumption by Fuel Type
Net Energy for Load
Fuel Type
2013
2023
GWh
GWh
%
%
23,061
35,370
56.6%
77.8%
Natural Gas
10,577
6,585
25.9%
14.5%
Coal
0
0
0.0%
0.0%
Nuclear
220
57
0.5%
0.1%
Oil
1,132
1,256
2.8%
2.8%
Renewable
1,409
687
3.5%
1.5%
Interchange
4,373
1,505
10.7%
3.3%
NUG & Other
40,772
45,459
Total
Source: 2014 Ten-Year Site Plan and Data Responses
Reliability Requirements
Since 1999, DEF has utilized a 20 percent planning reserve margin criterion. Figure 23 below,
displays the forecast planning reserve margin for DEF through the planning period for both
seasons, with and without the use of demand response. As shown in the figure, DEF’s
generation needs are controlled by its summer peaking throughout the planning period. While
the utility’s summer planning reserve margin dips below 20 percent in 2018, the deficiency is
only 19.6 MW and is anticipated to be resolved by 2019.
53
Figure 23: DEF Reserve Margin Forecast
Source: 2014 Ten-Year Site Plan
Generation Resources
DEF plans multiple unit retirements and additions during the planning period, as described below
in Table 16. DEF’s 2014 Ten-Year Site Plan includes the retirement of the coal-fired Crystal
River Units 1 and 2, to be replaced by a pair of natural gas-fired combined cycle units. DEF’s
Plan also includes the addition of two combustion turbines at the Suwannee River plant site, but
this is subject to change based upon the outcome of a potential purchase of merchant capacity.
In addition to the units discussed above, DEF includes the retirement of five oil-fired units and
eight natural gas-fired units at multiple power plant sites. An additional new combined cycle is
planned for 2021 which will require a determination of need from the Commission
54
Table 16: DEF Unit Retirements and Additions
Year
Plant Name
& Unit Number
Unit Type
Net Capacity
(MW)
Sum
Win
Notes
Retiring Units
2018
Crystal River 1 & 2
2014
2016
2016
2016
G. E. Turner P3
Avon Park P2
Rio Pinar P1
G. E. Turner P1&2
2016
2018
2020
Avon Park
Suwannee River 1-3
Higgins P1-4
Coal
Steam
Oil
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combustion Turbine
Natural Gas
Combustion Turbine
Steam
Combustion Turbine
740
743
53
24
12
20
77
35
15
26
24
128
105
35
129
116
New Units
2016
2018
2021
Suwannee River
Citrus Combined Cycle
Unsited Combined Cycle
Natural Gas
Combustion Turbine
Combined Cycle
Combined Cycle
Source: 2014 Ten-Year Site Plan
55
316
1,640
793
375
1,820
866
Docket No. 140111-EI
Docket No. 140110-EI
Requires Approval
Tampa Electric Company (TECO)
TECO is an investor-owned utility and Florida’s third largest electric utility. The utility’s
service territory is within the FRCC region and consists primarily of the Tampa metropolitan
area. As an investor-owned utility, the Commission has regulatory authority over all aspects of
operations, including rates, reliability, and safety. Pursuant to Section 186.801(2), F.S., the
Commission finds TECO’s 2014 Ten-Year Site Plan suitable for planning purposes.
Load & Energy Forecasts
In 2013, TECO had approximately 695,000 customers and annual retail energy sales of 18,418
GWh, or approximately 8.5 percent of Florida’s annual retail energy sales. Figure 24 below,
illustrates the company’s historic and forecast number of customers and retail energy sales, in
terms of percentage growth from 2004. Over the last ten years, TECO’s customer base has
increased by 12.01 percent, while retail sales have declined by 0.10 percent. As illustrated
below, retail energy sales are anticipated to exceed the historic 2007 peak by 2020, three years
later than the state as a whole.
Figure 24: TECO Growth Rate
Source: 2014 Ten-Year Site Plan
The three graphs in Figure 25 below shows, TECO’s seasonal peak demand and net energy for
load for the historic years of 2004 through 2013 and forecast years 2014 through 2023. These
graphs include the full impact of demand-side management, and assume that all available
demand response resources were or will be activated during the seasonal peak. Historically,
demand response has not been activated during seasonal peak demand excluding extreme
weather events.
56
Figure 25: TECO Demand and Energy Forecasts
Source: 2014 Ten-Year Site Plan and Data Responses
57
As an investor-owned utility, TECO is subject to FEECA and currently offers energy efficiency
and demand response programs to customers to reduce peak demand and annual energy
consumption. The utility’s 2015 Ten-Year Site Plan should include revised values that would
reflect the Commission’s decision in the currently open FEECA goal-setting docket.
Fuel Diversity
Table 17 below, shows TECO’s actual net energy for load by fuel type as of 2014 and the
projected fuel mix for 2023. TECO uses coal for a majority of energy generation, and based on
the 2014 Ten-Year Site Plan, energy from coal is anticipated to be equal to all other sources
combined. Natural gas is the second largest source of energy for the utility, at approximately 40
percent of net energy for load.
Table 17: TECO Energy Consumption by Fuel Type
Net Energy for Load
Fuel Type
2013
GWh
2023
%
GWh
%
Natural Gas
7,601
39.6%
9,009
42.4%
Coal
9,647
50.3%
10,650
50.1%
Nuclear
0
0.0%
0
0.0%
Oil
8
0.0%
0
0.0%
Renewable
0
0.0%
0
0.0%
Interchange
200
1.0%
0
0.0%
NUG & Other
1,720
9.0%
1,604
7.5%
Total
19,177
21,263
Source: 2014 Ten-Year Site Plan and Data Responses
Reliability Requirements
Since 1999, TECO has utilized a 20 percent planning reserve margin criterion. TECO also elects
to maintain a minimum supply-side reserve margin of 7 percent. Figure 26 below, displays the
forecast planning reserve margin for TECO through the planning period for both seasons, with
and without the use of demand response. As shown in the figure, TECO’s generation needs are
controlled by its summer peaking throughout the planning period.
58
Figure 26: TECO Reserve Margin Forecast
Source: 2014 Ten-Year Site Plan
Generation Resources
TECO plans a pair of unit additions during the planning period, as described below in Table 18.
TECO plans to convert a set of four natural gas-fired simple cycle combustion turbines at its
Polk power plant to combined cycle operation. The additional capacity associated with the
modernization is listed below, and has already been certified through the Power Plant Siting Act.
TECO also plans the addition of a peaking unit, a natural gas-fired combustion turbine in 2020.
59
Table 18: TECO Unit Additions
Year
Plant Name
& Unit Number
Unit Type
Net Capacity
(MW)
Sum
Win
Notes
New Units
2017
2020
Polk CC Conversion
Future CT1
Natural Gas
Combined Cycle
Combustion Turbine
Source: 2014 Ten-Year Site Plan
60
459
190
463
220
Previously Approved
Gulf Power Company (GPC)
GPC is an investor owned utility, and is Florida’s sixth largest electric utility. It represents the
smallest of the generating investor-owned utilities, and the only one inside the Southern
Company electric system. As GPC plans and operates its system in conjunction with the other
Southern Company utilities, not all of the energy generated by GPC is consumed within Florida.
As an investor-owned utility, the Commission has regulatory authority over all aspects of
operations, including rates, reliability, and safety. Pursuant to Section 186.801(2), F.S., the
Commission finds GPC’s 2014 Ten-Year Site Plan suitable for planning purposes.
Load & Energy Forecasts
In 2013, GPC had approximately 438,000 customers and annual retail energy sales of 10,620
GWh, or approximately 4.9 percent of Florida’s annual retail energy sales. Figure 27 below,
illustrates the company’s historic and forecast number of customers and retail energy sales, in
terms of percentage growth from 2004. Over the last ten years, GPC’s customer base has
increased by 9.90 percent, while retail sales have declined by 3.86 percent. As illustrated below,
retail energy sales are anticipated to exceed the historic 2008 peak by 2020, three years later than
the state as a whole.
Figure 27: GPC Growth Rate
Source: 2014 Ten-Year Site Plan
The three graphs in Figure 28 below shows, GPC’s seasonal peak demand and net energy for
load for the historic years of 2004 through 2013 and forecast years 2014 through 2023. These
graphs include the full impact of demand-side management.
61
Figure 28: GPC Demand and Energy Forecasts
Source: 2014 Ten-Year Site Plan and Data Responses
62
As an investor-owned utility, GPC is subject to FEECA and currently offers energy efficiency
and demand response programs to customers to reduce peak demand and annual energy
consumption. The utility’s 2015 Ten-Year Site Plan should include revised values that would
reflect the Commission’s decision in the currently open FEECA goal-setting docket.
Fuel Diversity
Table 19 below, shows GPC’s actual net energy for load by fuel type as of 2013, and the
projected fuel mix for 2023. GPC is an energy exporter, producing over a quarter more energy
than it requires for native load. While natural gas was the dominant fuel source in 2013, coal
made up approximately half of energy produced. By 2023, GPC’s 2014 Ten-Year Site Plan
projects a decline in sales to only 11.1 percent of native load, with coal representing
approximately 70 percent of system energy. GPC projects a greater percent of energy
consumption from coal in 2023 than any other investor-owned utility and all but two other TYSP
Utilities, JEA and OUC.
Table 19: GPC Energy Consumption by Fuel Type
Net Energy for Load
Fuel Type
2013
GWh
2023
%
GWh
%
Natural Gas
8,834
76.5%
5,258
39.9%
Coal
5,601
48.5%
9,078
68.9%
Nuclear
0
0.0%
0
0.0%
Oil
1
0.0%
1
0.0%
Renewable
0
0.0%
0
0.0%
Interchange
-3,174
-27.5%
-1,469
-11.1%
290
2.5%
311
2.4%
NUG & Other
Total
11,552
13,179
Source: 2014 Ten-Year Site Plan and Data Responses
Reliability Requirements
As previously noted, GPC is the only Ten-Year Site Plan Utility outside of the FRCC region. As
part of Southern Company’s electric system, GPC plans to maintain a 15 percent seasonal
planning reserve margin beginning in 2017. Figure 29 below, displays the forecast planning
reserve margin for GPC through the planning period for both seasons, including the impact of
energy efficiency programs. As shown in the figure, GPC’s generation needs are typically
determined by its summer peak, but in 2014 the winter peak is the controlling factor. Notably,
GPC’s 2014 Ten-Year Site Plan projects a low reserve margin for its summer 2023 period, with
a reserve margin of only 1.1 percent. The decline in reserve margin is associated with the
expiration of a purchased power agreement of approximately 885 MW of natural gas-fired
generation in June 2023. It is anticipated that GPC would either construct additional generation
63
beyond the units identified above or contract for purchased power to meet its planning reserve
requirement in 2023.
Figure 29: GPC Reserve Margin Forecast
Source: 2014 Ten-Year Site Plan
Generation Resources
GPC plans multiple unit retirements and additions during the planning period, as described
below in Table 20. A pair of coal-fired steam units and three natural gas-fired combustion
turbines would be retired during the planning period. Based on its 2014 Ten-Year Site Plan,
GPC plans to add a single natural gas-fired combustion turbine in 2023, after the expiration of a
purchased power agreement expires. In addition, GPC plans on the addition of utility-owned
renewable generation from a landfill gas-fired internal combustion unit, which would provide
firm capacity.
64
Table 20: GPC Unit Retirements and Additions
Year
Plant Name
& Unit Number
Unit Type
Net Capacity
(MW)
Sum
Win
Notes
Retiring Units
2015
Scholz 1 & 2
2018
Pea Ridge 1-3
Coal
Steam
Natural Gas
Combustion Turbine
92
92
12
15
349
360
2
2
New Units
2023
Unsited CT
2015
Perdido
Natural Gas
Combustion Turbine
Landfill Gas
Internal Combustion
Source: 2014 Ten-Year Site Plan
65
Florida Municipal Power Agency (FMPA)
FMPA is a governmental wholesale power company owned by several Florida municipal utilities
throughout Florida. Collectively, FMPA is Florida’s eighth largest electric utility and third
largest municipal electric utility. While FMPA has 31 member systems, only those members
who are participants of the All-Requirements Power Supply Project (ARP) are addressed in the
utility’s Ten-Year Site Plan. FMPA is responsible for planning activities associated with ARP
member systems. As a municipal utility, the Commission’s regulatory authority is limited to
safety, rate structure, territorial boundaries, bulk power supply, operations, and planning.
Pursuant to Section 186.801(2), F.S., the Commission finds FMPA’s 2014 Ten-Year Site Plan
suitable for planning purposes.
Load & Energy Forecasts
In 2013, FMPA had approximately 267,000 customers and annual retail energy sales of 5,688
GWh, or approximately 2.6 percent of Florida’s annual retail energy sales. Figure 30 below,
illustrates the company’s historic and forecast number of customers and retail energy sales, in
terms of percentage growth from 2004. Over the last ten years, FMPA’s customer base has
decreased by 3.68 percent, while retail sales have decreased by 14.04 percent. As illustrated
below, retail energy sales are not anticipated to exceed the historic 2007 peak during the
planning period, and will, in fact, be below 2004 retail energy sale levels by 7.56 percent. The
reduction in sales is associated with several ARP member systems modifying their contractual
agreements with FMPA, such that FMPA no longer provides for the system’s capacity and
energy needs. Those member systems modifying agreements include the City of Vero Beach in
2010, the City of Lake Worth in 2014, and the City of Fort Meade in 2015.
Figure 30: FMPA Growth Rate
Source: 2014 Ten-Year Site Plan
66
Figure 31: FMPA Demand and Energy Forecasts
Source: 2014 Ten-Year Site Plan and Data Responses
67
The three graphs in Figure 31 above, shows FMPA’s seasonal peak demand and net energy for
load for the historic years of 2004 through 2013 and forecast years 2014 through 2023. As
FMPA is a wholesale power company, it does not directly engage in energy efficiency or
demand response programs. ARP member systems do offer demand-side management
programs, the impacts of which are included in the graphs below.
Fuel Diversity
Table 21 below, shows FMPA’s actual net energy for load by fuel type as of 2014 and the
projected fuel mix for 2023. FMPA uses natural gas as its primary fuel, supplemented by coal
and nuclear generation. FMPA projects an increase in purchased power and energy from coal in
2023, but 70 percent of energy would still be sourced from natural gas and nuclear.
Table 21: FMPA Energy Consumption by Fuel Type
Net Energy for Load
Fuel Type
2013
GWh
2023
%
GWh
%
4,527
73.8%
4,336
66.8%
Coal
734
12.0%
960
14.8%
Nuclear
618
10.1%
287
4.4%
Oil
2
0.0%
1
0.0%
Renewable
46
0.8%
23
0.4%
Interchange
0
0.0%
0
0.0%
206
3.4%
881
13.6%
Natural Gas
NUG & Other
Total
6,133
6,488
Source: 2014 Ten-Year Site Plan and Data Responses
Reliability Requirements
FMPA utilizes an 18 percent planning reserve margin criterion for summer peak demand, and a
15 percent planning reserve margin criterion for winter peak demand. Figure 32 below, displays
the forecast planning reserve margin for FMPA through the planning period for both seasons,
with the impact of energy efficiency programs. As shown in the figure, FMPA’s generation
needs are controlled by its summer peak throughout the planning period.
68
Figure 32: FMPA Reserve Margin Forecast
Source: 2014 Ten-Year Site Plan
Generation Resources
FMPA plans no unit additions or retirements during the planning period. However, as discussed
above, several ARP member systems have elected to modify their contractual agreements with
FMPA, such that FMPA no longer utilizes the member system’s generation resources.
69
Gainesville Regional Utilities (GRU)
GRU is a municipal utility and the smallest electric utility required to file a Ten-Year Site Plan.
The utility’s service territory is within the FRCC region and consists of the City of Gainesville
and its surrounding area. GRU also provides wholesale power to the City of Alachua and Clay
Electric Cooperative. As a municipal utility, the Commission’s regulatory authority is limited to
safety, rate structure, territorial boundaries, bulk power supply, operations, and planning.
Pursuant to Section 186.801(2), F.S., the Commission finds GRU’s 2014 Ten-Year Site Plan
suitable for planning purposes.
Load & Energy Forecasts
In 2013, GRU had approximately 93,000 customers and annual retail energy sales of 1,694
GWh, or approximately 0.8 percent of Florida’s annual retail energy sales. Figure 33 below,
illustrates the company’s historic and forecast number of customers and retail energy sales, in
terms of percentage growth from 2004. Over the last ten years, GRU’s customer base has
increased by 7.96 percent, while retail sales have decreased by 7.41 percent. As illustrated
below, retail energy sales are not anticipated to exceed their historic 2007 peak during the
planning period.
Figure 33: GRU Growth Rate
Source: 2014 Ten-Year Site Plan
The three graphs in Figure 34 below, shows GRU’s seasonal peak demand and net energy for
load for the historic years of 2004 through 2013 and forecast years 2014 through 2023. GRU
engages in multiple energy efficiency programs to reduce customer peak demand and annual
energy for load. The graphs in Figure 34 include the impact of these demand-side management
programs.
70
Figure 34: GRU Demand and Energy Forecasts
Source: 2014 Ten-Year Site Plan and Data Responses
71
Fuel Diversity
Table 22 below, shows GRU’s actual net energy for load by fuel type as of 2013 and the
projected fuel mix for 2023. In 2013, natural gas and coal were approximately equal in terms of
contribution to net energy for load, with the remaining energy split between renewable
generation and non-utility generators. By 2023, GRU projects a decline in natural gas and an
increase in renewable energy to over 40 percent of net energy for load. This increase in
renewables is primarily associated with the Gainesville Renewable Energy Center, a biomass
facility that GRU has a long-term purchased power agreement with for approximately 100 MW
of firm capacity and energy.
Table 22: GRU Energy Consumption by Fuel Type
Net Energy for Load
Fuel Type
2013
GWh
2023
%
GWh
%
Natural Gas
696
37.1%
426
20.5%
Coal
626
33.4%
756
36.3%
Nuclear
81
4.3%
0
0.0%
Oil
0
0.0%
0
0.0%
215
11.5%
901
43.3%
0
0.0%
0
0.0%
255
13.6%
0
0.0%
Renewable
Interchange
NUG & Other
Total
1,873
2,083
Source: 2014 Ten-Year Site Plan and Data Responses
Reliability Requirements
GRU utilizes a 15 percent planning reserve margin criterion for seasonal peak demand. Figure
35 below, displays the forecast planning reserve margin for GRU through the planning period for
both seasons, including the impacts of demand-side management. As shown in the figure,
GRU’s generation needs are controlled by its summer peak throughout the planning period. As a
smaller utility, the reserve margin is an imperfect measure of reliability due to the relatively large
impact a single unit may have on reserve margin. For example, GRU’s largest single unit,
Deerhaven 2, a coal-fired steam unit, represents 56.3 percent of summer net firm peak demand in
2014, almost the entirety of the utility’s reserve margin.
72
Figure 35: GRU Reserve Margin Forecast
Source: 2014 Ten-Year Site Plan
Generation Resources
GRU currently plans to retire a natural gas-fired steam unit towards the end of the planning
period, as described below in Table 23. As a smaller utility, single units can have a large impact
upon reserve margin, discussed below. GRU does not plan to add additional generating capacity
during the planning period.
73
Table 23: GRU Unit Retirements
Year
Plant Name
& Unit Number
Unit Type
Net Capacity
(MW)
Sum
Win
Retiring Units
2022
Deerhaven
Natural Gas
Steam
Source: 2014 Ten-Year Site Plan
74
75
75
Notes
JEA
JEA, formerly known as Jacksonville Electric Authority, is Florida’s largest municipal utility and
fifth largest electric utility. JEA’s service territory is within the FRCC region, and includes all of
Duval County as well as portions of Clay and St. Johns Counties. As a municipal utility, the
Commission’s regulatory authority is limited to safety, rate structure, territorial boundaries, bulk
power supply, operations, and planning. Pursuant to Section 186.801(2), F.S., the Commission
finds JEA’s 2014 Ten-Year Site Plan suitable for planning purposes.
Load & Energy Forecasts
In 2013, JEA had approximately 425,000 customers and annual retail energy sales of 11,556
GWh, or approximately 5.3 percent of Florida’s annual retail energy sales. Figure 36 below,
illustrates the company’s historic and forecast number of customers and retail energy sales, in
terms of percentage growth from 2004. Over the last ten years, JEA’s customer base has
increased by 11.36 percent, while retail sales have declined by 6.14 percent. As illustrated
below, JEA exceeded its 2007 peak for retail energy sales in 2010, but does not forecast
returning to that level of energy sales during the planning period.
Figure 36: JEA Growth Rate
Source: 2014 Ten-Year Site Plan and 2014 FRCC Load & Resource Plan
The three graphs in Figure 37 below, shows JEA’s seasonal peak demand and net energy for load
for the historic years of 2004 through 2013 and forecast years 2014 through 2023. These graphs
include the full impact of demand-side management, and assume that all available demand
response resources were or will be activated during the seasonal peak.
75
Figure 37: JEA Demand and Energy Forecasts
Source: 2014 Ten-Year Site Plan and Data Responses
76
While a municipal utility, JEA is subject to FEECA and currently offers energy efficiency and
demand response programs to customers to reduce peak demand and annual energy
consumption. The utility’s 2015 Ten-Year Site Plan should include revised values that would
reflect the Commission’s decision in the currently open FEECA goal-setting docket.
Fuel Diversity
Table 24 below, shows JEA’s actual net energy for load by fuel type as of 2013 and the projected
fuel mix for 2023. In 2013, a majority JEA’s net energy for load came from coal and petroleum
coke, which is listed in the “NUG & Other” category in Table 24. While the utility plans on
eliminating petroleum coke usage over the planning period, JEA projects the highest percent
energy consumption from coal in 2023 of the Ten-Year Site Plan utilities, almost doubling its
usage of the solid fuel.
Table 24: JEA Energy Consumption by Fuel Type
Net Energy for Load
Fuel Type
2013
GWh
2023
%
GWh
%
Natural Gas
3,890
31.7%
1,090
8.2%
Coal
5,376
43.8%
10,440
78.6%
Nuclear
0
0.0%
0
0.0%
Oil
3
0.0%
2
0.0%
Renewable
92
0.7%
101
0.8%
Interchange
841
6.8%
1,654
12.4%
NUG & Other
2,084
17.0%
0
0.0%
Total
12,286
13,286
Source: 2014 Ten-Year Site Plan and Data Responses
Reliability Requirements
JEA utilizes a 15 percent planning reserve margin criterion for seasonal peak demand. Figure 38
below, displays the forecast planning reserve margin for JEA through the planning period for
both seasons, with and without the use of demand response. As shown in the figure, JEA’s
generation needs are controlled by its summer peak throughout the planning period.
77
Figure 38: JEA Reserve Margin Forecast
Source: 2014 Ten-Year Site Plan
Generation Resources
JEA plans to retire a pair of units during the planning period, as described below in Table 25.
The Northside Unit 3, a natural gas-fired steam unit is planned for retirement in 2019 based on
the utility’s Ten-Year Site Plan, but JEA subsequently announced that its retirement would be
accelerated to 2015. JEA also has retired its Girvin landfill units due to a decline in gas flows.
78
Table 25: JEA Unit Retirements
Year
Plant Name
& Unit Number
Unit Type
Net Capacity
(MW)
Sum
Win
Notes
Retiring Units
2019
Northside
2014
Girvin Landfill
Natural Gas
Steam
Landfill Gas
Internal Combustion
Source: 2014 Ten-Year Site Plan
79
524
524
1
1
Accelerated to 2015
2014
Lakeland Electric (LAK)
LAK is a municipal utility and the state’s third smallest electric utility required to file a Ten-Year
Site Plan. The utility’s service territory is within the FRCC region and consists of the City of
Lakeland and surrounding areas. As a municipal utility, the Commission’s regulatory authority
is limited to safety, rate structure, territorial boundaries, bulk power supply, operations, and
planning. Pursuant to Section 186.801(2), F.S., the Commission finds LAK’s 2014 Ten-Year
Site Plan suitable for planning purposes.
Load & Energy Forecasts
In 2013, LAK had approximately 123,000 customers and annual retail energy sales of 2,831
GWh, or approximately 1.3 percent of Florida’s annual retail energy sales. Figure 39 below,
illustrates the company’s historic and forecast number of customers and retail energy sales, in
terms of percentage growth from 2004. Over the last ten years, LAK’s customer base has
increased by 7.82 percent, while retail sales have grown by 3.47 percent. As illustrated below,
retail energy sales exceed their historic 2007 peak in 2010, and are anticipated to again exceed
this value in 2015.
Figure 39: LAK Growth Rate
Source: 2014 Ten-Year Site Plan
The three graphs in Figure 40 below shows, LAK’s seasonal peak demand and net energy for
load for the historic years of 2004 through 2013 and forecast years 2014 through 2023. LAK
offers energy efficiency programs, the impacts of which are included in the graphs below.
80
Figure 40: LAK Demand and Energy Forecasts
Source: 2014 Ten-Year Site Plan and Data Responses
81
Fuel Diversity
Table 26 below, shows LAK’s actual net energy for load by fuel type as of 2013 and the
projected fuel mix for 2023. LAK uses natural gas as its primary fuel type for energy, with coal
representing slightly more than a quarter of net energy for load. While natural gas usage is
anticipated to increase somewhat as a percent of net energy for load, coal is projected to remain
at a similar level to 2013.
Table 26: LAK Energy Consumption by Fuel Type
Net Energy for Load
Fuel Type
2013
GWh
2023
%
GWh
%
2,018
69.1%
2,705
80.6%
786
26.9%
926
27.6%
Nuclear
0
0.0%
0
0.0%
Oil
0
0.0%
0
0.0%
Renewable
6
0.2%
21
0.6%
Interchange
0
0.0%
0
0.0%
109
3.7%
-297
-8.9%
Natural Gas
Coal
NUG & Other
Total
2,919
3,355
Source: 2014 Ten-Year Site Plan and Data Responses
Reliability Requirements
LAK utilizes a 15 percent planning reserve margin criterion for seasonal peak demand. Figure
41 below, displays the forecast planning reserve margin for LAK through the planning period for
both seasons, including the impacts of demand-side management. As shown in the figure,
LAK’s generation needs are controlled by its winter peak throughout the planning period. As a
smaller utility, the reserve margin is an imperfect measure of reliability due to the relatively large
impact a single unit may have on reserve margin. For example, LAK’s largest single unit,
McIntosh 5, a natural gas-fired combined cycle unit, represents 51.4 percent of winter net firm
peak demand in 2014, in excess of the utility’s reserve margin.
82
Figure 41: LAK Reserve Margin Forecast
Source: 2014 Ten-Year Site Plan
New Units
LAK plans no unit additions or retirements during the planning period.
83
Orlando Utilities Commission (OUC)
OUC is a municipal utility and Florida’s seventh largest electric utility and second largest
municipal utility. The utility’s service territory is within the FRCC region and primarily consists
of the Orlando metropolitan area. As a municipal utility, the Commission’s regulatory authority
is limited to safety, rate structure, territorial boundaries, bulk power supply, operations, and
planning. Pursuant to Section 186.801(2), F.S., the Commission finds OUC’s 2014 Ten-Year
Site Plan suitable for planning purposes.
Load & Energy Forecasts
In 2013, OUC had approximately 215,000 customers and annual retail energy sales of 6,025
GWh, or approximately 2.8 percent of Florida’s annual retail energy sales. Figure 42 below,
illustrates the company’s historic and forecast number of customers and retail energy sales, in
terms of percentage growth from 2004. Over the last ten years, OUC’s customer base has
increased by 17.28 percent, while retail sales have grown by 6.62 percent. As illustrated below,
retail energy sales are anticipated to exceed their historic 2008 peak in 2015.
Figure 42: OUC Growth Rate
Source: 2014 Ten-Year Site Plan
The three graphs in Figure 43 below, shows OUC’s seasonal peak demand and net energy for
load for the historic years of 2004 through 2013 and forecast years 2014 through 2023. These
graphs include the impact of the utility’s demand side management programs. While a
municipal utility, OUC is subject to FEECA and currently offers energy efficiency and demand
response programs to customers to reduce peak demand and annual energy consumption. The
utility’s 2015 Ten-Year Site Plan should include revised values that would reflect the
Commission’s decision in the currently open FEECA goal-setting docket.
84
Figure 43: OUC Demand and Energy Forecasts
Source: 2014 Ten-Year Site Plan and Data Responses
85
Fuel Diversity
Table 27 below, shows OUC’s actual net energy for load by fuel type as of 2013 and the
projected fuel mix for 2023. In 2013, OUC used approximately equal portions of natural gas and
coal as fuel to meet the utility’s net energy for load. However, OUC projects to significantly
increase the quantity of energy consumed from coal, while decreasing natural gas usage by 2023.
Based upon this projection, OUC as a percent of net energy for load would be the second largest
user of coal in Florida by 2023.
Table 27: OUC Energy Consumption by Fuel Type
Net Energy for Load
Fuel Type
2013
GWh
2023
%
GWh
%
Natural Gas
3,040
43.0%
839
12.4%
Coal
3,030
42.9%
5,284
77.9%
569
8.1%
462
6.8%
Oil
0
0.0%
0
0.0%
Renewable
91
1.3%
194
2.9%
Interchange
0
0.0%
0
0.0%
336
4.8%
0
0.0%
Nuclear
NUG & Other
Total
7,065
6,779
Source: 2014 Ten-Year Site Plan and Data Responses
Reliability Requirements
OUC utilizes a 15 percent planning reserve margin criterion for seasonal peak demand. Figure
44 below, displays the forecast planning reserve margin for OUC through the planning period for
both seasons, including the impact of demand-side management programs. As shown in the
figure, OUC’s generation needs are controlled by its summer peak demand throughout the
planning period.
86
Figure 44: OUC Reserve Margin Forecast
Source: 2014 Ten-Year Site Plan
Generation Resources
OUC plans no unit additions or retirements during the planning period.
87
Seminole Electric Cooperative (SEC)
SEC is a generation and transmission rural electric cooperative that serves its member
cooperatives, and is collectively Florida’s fourth largest utility. SEC’s generation and member
cooperatives are within the FRCC region, with member cooperatives located in central and north
Florida. As a rural electric cooperative, the Commission’s regulatory authority is limited to
safety, rate structure, territorial boundaries, bulk power supply, operations, and planning.
Pursuant to Section 186.801(2), F.S., the Commission finds SEC’s 2014 Ten-Year Site Plan
suitable for planning purposes.
Load & Energy Forecasts
In 2013, SEC had approximately 865,000 customers and annual retail energy sales of 14,631
GWh, or approximately 6.7 percent of Florida’s annual retail energy sales. Figure 45 below,
illustrates the company’s historic and forecast number of customers and retail energy sales, in
terms of percentage growth from 2004. Over the last ten years, SEC’s customer base has
increased by 9.15 percent, while retail sales have grown by only 0.67 percent. As illustrated
below, retail energy sales are anticipated to exceed their historic 2007 peak by 2022,
approximately five years later than Florida as a whole. The decline shown in 2014 is associated
with one member cooperative, Lee County Electric Cooperative, electing to end its membership
with SEC.
Figure 45: SEC Growth Rate
Source: 2014 Ten-Year Site Plan
88
Figure 46: SEC Demand and Energy Forecasts
Source: 2014 Ten-Year Site Plan and Data Responses
89
The three graphs in Figure 46 above, shows SEC’s seasonal peak demand and net energy for
load for the historic years of 2004 through 2013 and forecast years 2014 through 2023. As SEC
is a generation and transmission company, it does not directly engage in energy efficiency or
demand response programs. Member cooperatives do offer demand-side management programs,
the impacts of which are included in the graphs below.
Fuel Diversity
Table 28 below, shows SEC’s actual net energy for load by fuel type as of 2013 and the
projected fuel mix for 2023. In 2013, SEC uses a combination of coal and natural gas to meet its
member cooperatives’ net energy for load, with coal use slightly higher than natural gas. By
2023, SEC projects this to reverse, with natural gas usage somewhat higher than coal.
Table 28: SEC Energy Consumption by Fuel Type
Net Energy for Load
Fuel Type
2013
GWh
2023
%
GWh
%
Natural Gas
7,071
44.7%
9,814
53.7%
Coal
7,725
48.9%
7,859
43.0%
Nuclear
0
0.0%
0
0.0%
Oil
54
0.3%
61
0.3%
Renewable
962
6.1%
550
3.0%
Interchange
0
0.0%
0
0.0%
NUG & Other
0
0.0%
0
0.0%
Total
15,812
18,284
Source: 2014 Ten-Year Site Plan and Data Responses
Reliability Requirements
SEC utilizes a 15 percent planning reserve margin criterion for seasonal peak demand. Figure 47
below, displays the forecast planning reserve margin for SEC through the planning period for
both seasons, with and without the use of demand response. Member cooperatives allow SEC to
coordinate demand response resources to maintain reliability. As shown in the figure, SEC’s
generation needs are determined by winter peak demand more often than summer peak demand
during the planning period.
90
Figure 47: SEC Reserve Margin Forecast
Source: 2014 Ten-Year Site Plan
Generation Resources
SEC plans the addition of several generating units during the planning period, as described
below in Table 29. All unsited natural gas-fired units, SEC plans the addition of a total of seven
combustion turbines and a single combined cycle unit over the planning period.
91
Table 29: SEC Unit Retirements and Additions
Year
Plant Name
& Unit Number
Unit Type
Net Capacity
(MW)
Sum
Win
Notes
New Units
2020
2020
2021
Unsited Combined Cycle
Unsited CT 1 &2
Unsited CT 3-7
Combined Cycle
Combustion Turbine
Combustion Turbine
Source: 2014 Ten-Year Site Plan
92
440
402
1,005
523
450
1,125
Requires Approval
City of Tallahassee Utilities (TAL)
TAL is a municipal utility and the second smallest electric utility and municipal electric utility.
The utility’s service territory is within the FRCC region and primarily consists of the City of
Tallahassee and surrounding areas. As a municipal utility, the Commission’s regulatory
authority is limited to safety, rate structure, territorial boundaries, bulk power supply, operations,
and planning. Pursuant to Section 186.801(2), F.S., the Commission finds TAL’s 2014 TenYear Site Plan suitable for planning purposes.
Load & Energy Forecasts
In 2013, TAL had approximately 116,000 customers and annual retail energy sales of 2,558
GWh, or approximately 1.2 percent of Florida’s annual retail energy sales. Figure 48 below,
illustrates the company’s historic and forecast number of customers and retail energy sales, in
terms of percentage growth from 2004. Over the last ten years, TAL’s customer base has
increased by 12.59 percent, while retail sales have declined by 4.63 percent. As illustrated
below, retail energy sales are not anticipated to exceed their historic 2007 peak until 2023, six
years later than the state as a whole.
Figure 48: TAL Growth Rate
Source: 2014 Ten-Year Site Plan
The three graphs in Figure 49 below, shows TAL’s seasonal peak demand and net energy for
load for the historic years of 2004 through 2013 and forecast years 2014 through 2023. These
graphs include the impact of demand-side management, and for future years assume that all
available demand response resources will be activated during the seasonal peak. TAL offers
energy efficiency and demand response programs to customers to reduce peak demand and
annual energy consumption. Currently TAL only offers demand response programs targeting
appliances that contribute to summer peak, and therefore have no effect upon winter peak.
93
Figure 49: TAL Demand and Energy Forecasts
Source: 2014 Ten-Year Site Plan and Data Responses
94
Fuel Diversity
Table 30 below, shows TAL’s actual net energy for load by fuel type as of 2013 and the
projected fuel mix for 2023. TAL relies almost exclusively on natural gas for its generation,
excluding some purchases from other utilities and qualifying facilities and the use of oil as a
backup fuel. Natural gas is anticipated to remain the sole fuel on the system, with only natural
gas-fired generation to be added.
Table 30: TAL Energy Consumption by Fuel Type
Net Energy for Load
Fuel Type
2013
GWh
2023
%
GWh
%
2,662
99.2%
2,903
99.5%
Coal
0
0.0%
0
0.0%
Nuclear
0
0.0%
0
0.0%
Oil
2
0.1%
0
0.0%
Renewable
23
0.8%
11
0.4%
Interchange
1
0.0%
27
0.9%
NUG & Other
-3
-0.1%
-23
-0.8%
Natural Gas
Total
2,684
2,918
Source: 2014 Ten-Year Site Plan and Data Responses
Reliability Requirements
TAL utilizes a 17 percent planning reserve margin criterion for seasonal peak demand. Figure
50 below, displays the forecast planning reserve margin for TAL through the planning period for
both seasons, with and without the use of demand response. As discussed above, TAL only
offers demand response programs applicable to the summer peak. As shown in the figure,
TAL’s generation needs are controlled by its summer peak throughout the planning period.
95
Figure 50: TAL Reserve Margin Forecast
Source: 2014 Ten-Year Site Plan
Generation Resources
TAL plans multiple unit retirements and a single addition during the planning period, as
described below in Table 31. Several older combustion turbines at two plant sites and a single
steam unit, all natural gas-fired, are anticipated to be retired during the planning period. Based
upon its current planning, TAL intends to add a new natural gas-fired combustion turbine in
2020.
96
Table 31: TAL Unit Retirements and Additions
Year
Plant Name
& Unit Number
Unit Type
Net Capacity
(MW)
Sum
Win
Retiring Units
2015
2015
2017
2020
Hopkins GT1
Purdom GT1&2
Hopkins GT2
Hopkins
Natural Gas
Combustion Turbine
Combustion Turbine
Combustion Turbine
Steam
12
20
24
76
14
20
26
78
46
48
New Units
2020
Hopkins 5
Natural Gas
Combustion Turbine
Source: 2014 Ten-Year Site Plan
97
Notes
APPENDIX A
REVIEW OF THE
2014 TEN-YEAR SITE PLANS
OF FLORIDA’S ELECTRIC UTILITIES
NOVEMBER 2014
Appendix A
Ten-Year Site Plan Comments
State Agencies
• Department of Economic Opportunity
• Department of Environmental Protection
• Fish and Wildlife Conservation Commission
Regional Planning Councils
• Central Florida Regional Planning Council
• East Central Florida Regional Planning Council
• Treasure Coast Regional Planning Council
• West Florida Regional Planning Council
Water Management Districts
• Northwest Florida Water Management District
• Southwest Florida Water Management District
• Suwannee River Water Management District
Local Governments
• Leon County
• Suwannee County
1
Appendix A
State Agencies
• Department of Economic Opportunity
• Department of Environmental Protection
• Fish and Wildlife Conservation Commission
2
Appendix A
3
Appendix A
4
Appendix A
5
Appendix A
6
Appendix A
7
Appendix A
8
Appendix A
Phillip Ellis
From:
Sent:
To:
Cc:
Subject:
Green, Justin B. <[email protected]>
Wednesday, June 18, 2014 2:58 PM
Phillip Ellis
Bull, Robert
DEP Siting Coordination Office Ten-Year Site Plan Review
Mr. Ellis The Department of Environmental Protection’s Siting Coordination Office has reviewed the 2014 Ten-Year Site Plans for
Florida’s Electric Utilities and found the documents to be adequate for planning purposes. Thank you for the opportunity
to review and comment on the plans. If you have any questions for our office, feel free to contact me.
Justin B. Green
Program Administrator
Siting Coordination Office
Division of Air Resource Management
Florida Department of Environmental Protection
(850) 717-9024
Right-click here to download
pictures. To help protect y our
priv acy , Outlook prev ented
auto matic downlo ad o f this
picture from the Internet.
Dep Customer Surv ey
1
9
Appendix A
June 30, 2014
Florida Fish
and Wildlife
Conservation
Commission
Commissioners
Richard A. Corbett
Chairman
Tampa
Brian S. Yablonski
Vice Chairman
Tallahassee
Ronald M. Bergeron
Fort Lauderdale
Aliese P. "Liesa" Priddy
Immokalee
Bo Rivard
Panama City
Charles W. Roberts Ill
Tallahassee
Execut ive Sta ff
Nick Wiley
Executive Director
Eric Sutton
Assistant Executive Director
Karen Ventimiglia
Chief of Staff
Off ice of tile
Executive Director
Nick Wiley
Executive Director
(850) 487-3796
(850) 921-5786
Managing fish and wildlife
resources for their long-term
well-being and the benefit
of people.
620 South Meridian Street
Tallahassee, Florida
32399-1600
Voice: (850) 488-4676
Mr. Phillip 0 . Ellis
Division of Engineering
Public Service Commission
2540 Shumard Oak Boulevard
Tallahassee, FL 32399-0850
[email protected]
RE:
Ten-Year Power Plant Site Plans
Dear Mr. Ellis:
Florida Fish and Wildlife Conservation Commission (FWC) staff has reviewed the 2014 Ten-Year Power
Plant Site Plans submitted to the Public Service Co mmission (PSC).
We will be providing comments on the Duke Energy Florida (DEF) site plan in a subsequent letter.
However, we are submitting this letter to notify you that we have reviewed the following plans and have no
comments regarding fish and wildlife resources:
•
•
•
•
•
•
•
•
•
•
Gainesville Regional Utilities (GRU)
Jacksonville Energy Authority (JEA)
Florida Power and Light (FPL)
Gulf Power Company (GULF)
Florida Municipal Power Agency (FMP A)
City of Tallahassee Utilities (TAL)
Seminole Electric Cooperative (SEC)
Lakeland Electric (LAK)
Tampa Electric Company (TECO)
Orlando Utilities Commission (OUC)
The FWC appreciates the opportunity to review the Ten-Year Site Plans, as submitted by the PSC. If you
need further assistance, please do not hesitate to contact Jane Chabre either by phone at (850)41 0-5367 or
by email at [email protected] MyFWC.com.
Sincerely,
Jennifer Goff
Land Use Planning Program Administrator
Office of Conservation Planning Services
j g/jh
ENV I
Gainesville Regional Uti liti es 2014 Ten-year Sit e Plan_ l9085_06302014
JEA2014TenYearSitePlan- 19088- 06262014
FPL 2014 Ten Year Site Plan- 19084- 06262014
Gulf Power Company 2014 Ten Year Site Plan_ l9087_ 06262014
Florida Municipal Power Agency 2014 Ten-Year Site Plan_ 06262014
City ofTallahassee 2014 Ten-Year Site Plan_06262014
Seminole Electric Cooperative 2014 Ten Year Site Plan_ 19091 _ 06262014
Lakeland Electric 2014 Ten Year Site Plan- 19089- 06262014
Tampa Electric Co mpany 2014 Ten Year Site Plan_ l9092 _ 06262014
Orlando Utilities Commission 2014 Ten Year Site Plan - 19090- 06262014
Hearing/speech-impaired:
(800) 955-8771 (T)
(800) 955-8770 (V)
MyFWC.com
10
Appendix A
11
Appendix A
12
Appendix A
Regional Planning Councils
• Central Florida Regional Planning Council
• East Central Florida Regional Planning Council
• Treasure Coast Regional Planning Council
• West Florida Regional Planning Council
13
Appendix A
14
Appendix A
15
Appendix A
16
Appendix A
17
Appendix A
MEMORANDUM
To: Phillip Ellis, Florida Public Service Commission
From: Hugh W. Harling, Jr., Executive Director
Tara M. McCue, AICP, Director of Planning and Community Design
Date: July 30, 2014
Subject: 2014 Ten-Year Site Plans Review
- Florida Power and Light
- Orlando Utilities Commission
- Duke Energy Florida
The East Central Florida Regional Planning Council staff has no comments concerning the 10-Year Site Plans
for utility companies within the east central region at this time. The ECFRPC will conduct a detailed review
of any new facilities or upgraded facilities requiring an agency review when a proposal is submitted.
If you require any further information or comments, please contact Tara McCue, AICP at [email protected] or
by phone at (407) 262-7772, ext. 327.
18
Appendix A
19
Appendix A
20
Appendix A
21
Appendix A
22
Appendix A
23
Appendix A
24
Appendix A
25
Appendix A
26
Appendix A
27
Appendix A
28
Appendix A
29
Appendix A
Water Management Districts
• Northwest Florida Water Management District
• Southwest Florida Water Management District
• Suwannee River Water Management District
30
Appendix A
t
~
~
~
+
-t.,y)JGEM.'f-~<t
E
<?
<)-..;
Jonathan P. Steverson
Executive Director
Northwest Florida Water Management District
152 Water Management Drive, Havana, Florida 32333-4712
(U.S. Highway
90, 10
miles west of Tallahassee)
Phone: (850) 539-5999 • Fax: (850) 539-2693
June 24, 2014
State of Florida Public Service Commission
Attn: Mr. Phillip Ellis
Capital Circle Office Center
2540 Shumard Oak Boulevard
Tallahassee, Florida 32399-0850
RE: Review of the 2014 Ten-Year Site Plans for Florida's Electric Utilities
Dear Mr. Ellis,
The Northwest Florida Water Management District (District) has reviewed the Ten-Year Site Plans
for Gulf Power Company and the City of Tallahassee Utilities as requested in your correspondence
dated April 22, 2014. The District has no comments on the site plans at this time.
If you have any questions or if any additional information is needed, please feel free to contact us
at (850) 539-5999.
Sincerely,
Kevin R. Hayes, P.G., CPG, GISP
Chief, Bureau of Groundwater
Regulation
Y:\REG_GW\PSC 10-Year Plan Reviews 2014\PSC Ten-Year Plan Reviews- Electrical Utilities June 2014.docx
GEORGE ROBERTS
Chair
Panama City
GARY CLARK
Chipley
JERRY PATE
Vice Chair
Pensacola
JOHN ALTER
Malone
JON COSTELLO
Tallahassee
GUS ANDREWS
DeFuniak Springs
NICK PATRONIS
Panama City Beach
31
STEPHANIE BLOYD
Panama City Beach
BOSPRING
Port Saint Joe
Appendix A
2379 Broad Street, Brooksville, Florida 34604-6899
(352) 796-7211 or 1-800-423-1476 (FL only)
On the World Wide Web at WaterMatters.org
An Equal
Opportunity
Employer
Carlos Beruff
Chair, Manatee
Michael A. Babb
Vice Chair, Hillsborough
Randall S. Maggard
Secretary, Pasco
Jeffrey M. Adams
Treasurer, Pinellas
Todd Pressman
Former Chair, Pinellas
H. Paul Senft, Jr.
Former Chair, Polk
May 16, 2014
Mr. Phillip Ellis, Engineering Specialist III
Division of Engineering
Florida Public Service Commission
2540 Shumard Oak Boulevard
Tallahassee, FL 32399-0850
Bryan K. Beswick
DeSoto, Hardee, Highlands
Thomas E. Bronson
Hernando, Marion
Subject: Electric Utility 2014 Ten-Year Site Plans
Jennifer E. Closshey
Hillsborough
Wendy Griffin
Hillsborough
Dear Mr. Ellis:
George W. Mann
Polk
Vacant
Charlotte, Sarasota
Vacant
Citrus, Lake, Levy, Sumter
Blake C. Guillory
Executive Director
In response to your request, the Southwest Florida Water Management
District (District) has completed its review of the 2014 Ten-Year Site Plans
(Site Plans) for Duke Energy Florida (DEF) and Tampa Electric Company
(TECO). The District’s review is being conducted pursuant to Section
186.801(2)(e), Florida Statutes, which requires that the Public Service
Commission consider “the views of the appropriate water management
district as to the availability of water and its recommendation as to the use
by the proposed plant of salt water or fresh water for cooling purposes.”
Please note that, pursuant to Section II.A.1.f of the current Operating
Agreement between the Florida Department of Environmental Protection
(DEP) and the District concerning the division of responsibility for
management and storage of surface waters regulation and wetland resource
regulation under Chapter 373, Part IV, Florida Statutes, the DEP is
responsible for conducting the Environmental Resource Permit-related
review and for taking final agency action for power plants, electrical
distribution and transmission lines, and other facilities related to the
production, transmission, and distribution of electricity.
Both DEF and TECO indicate in their Site Plans that new generating
facilities are proposed within the ten-year planning horizon. The Site Plan
for DEF indicates that new combined cycle units are proposed in 2018 and
2021 adjacent to the Crystal River Site and at an undesignated site,
respectively. The Site Plan for TECO indicates that conversion of the Polk
Power Station’s simple cycle combustion turbines (Units 2-5) to a natural
32
Appendix A
Mr. Phillip Ellis, Engineering Specialist III
May 16, 2014
Page 2
gas combined cycle unit is proposed in 2017. In addition, a new combustion turbine is
proposed in 2020 at an undesignated site.
Based on the information provided in the Site Plans, the District offers the following
technical assistance comments for your consideration:
1) During the site certification or permitting process, consideration must be given to
the lowest quality water available which is acceptable for the proposed use. If a
lower quality water is available and is environmentally, technically and
economically feasible for all or a portion of the proposed use, this lower quality
water must be used.
2) For new generating facilities proposed in the southern and much of the central
portions of the District, there are additional water use constraints. These areas
have been designated as Water Use Caution Areas. This designation has
occurred in response to water resource impacts, such as salt water intrusion,
lowered water levels in lakes and wetlands, and reduced stream flows, which
have been caused by excessive ground water withdrawals. Regional recovery
strategies are being implemented to address these adverse water resource
impacts. Consequently, the District has heightened concerns regarding potential
impacts due to additional water withdrawals.
3) The most water conserving practices must be used in all processes and
components of the power plant’s water use that are environmentally, technically
and economically feasible for the activity, including reducing water losses,
recycling, and reuse.
We appreciate this opportunity to participate in the review process. If you have any
questions or require further assistance, please do not hesitate to contact me at (352)
796-7211, extension 4790, or [email protected]
Sincerely,
James J. Golden, AICP
Senior Planner
JG
33
Appendix A
34
Appendix A
Local Governments
• Leon County
• Suwannee County
35
Appendix A
36
Appendix A
37
Attachment 3
A R E P O R T TO T H E
Governor
President of the Senate
Speaker of the House of Representatives
FLORIDA
LIFELINE
ASSISTANCE
Number of Customers
Subscribing to Lifeline Service
And the Effectiveness of
Procedures to Promote Participation
DECEMBER2014
Table of Contents
I.
Executive Summary ...................................................................................................................1
II.
Background ................................................................................................................................2
III.
Lifeline Participation..................................................................................................................3
IV.
Lifeline Providers .......................................................................................................................5
V.
Lifeline Enrollment Process and Improvement Activities .........................................................9
A. Lifeline Electronic Coordinated Enrollment Process ................................................... 9
B. Transitional Lifeline...................................................................................................... 9
C. Florida Public Service Commission Activities ........................................................... 10
D. Federal Communications Commission Activities ...................................................... 13
VI.
Lifeline Promotion Activities...................................................................................................16
VII.
Conclusion ...............................................................................................................................19
Attachments
Attachment A. 2014 U.S. Poverty Guidelines ............................................................................. 20
Attachment B. Lifeline Net Enrollment and Year-to-Year Net Growth Rate ............................. 21
Attachment C. Recertification of Florida Lifeline Subscribers ................................................... 22
Attachment D. Agencies, Organizations, and Business Lifeline Partners ................................... 23
i
List of Figures
Figure 1.
Florida Lifeline Subscribership .................................................................................... 4
Figure 2.
Lifeline Participation Rate In Eligible Florida Households for 2011-2014 ................. 4
Figure 3.
ETCs Participating in Florida Lifeline Program .......................................................... 6
Figure 4.
Companies with Pending ETC Designation Petitions at FCC as of June 2014 ........... 6
Figure 5.
Six Florida ETCs with the Largest Number of Lifeline Customers in June 2014 ....... 7
Figure 6.
USAC Low Income ETC Disbursements to Florida Providers .................................... 7
Figure 7.
AT&T, Verizon, and CenturyLink Transitional Lifeline Participants 2010-2014 .... 10
Figure 8.
Events and locations where Lifeline information was shared in Florida ................... 17
ii
List of Acronyms
CFR
Code of Federal Regulations
DCF
Department of Children and Families
ETC
Eligible Telecommunications Carrier
FCC
Federal Communications Commission
FPSC
Florida Public Service Commission
NCPW
National Consumer Protection Week
NLAD
National Lifeline Accountability Database
OPC
Office of Public Counsel
SNAP
Supplemental Nutrition Assistance Program (formerly Food Stamps)
TCA
Temporary Cash Assistance
USAC
Universal Service Administrative Company
iii
I.
Executive Summary
The Florida Lifeline program is part of the federal Universal Service Program designed to
enable low-income households to obtain and maintain basic local telephone service in
accordance with Section 364.10, Florida Statutes. The Lifeline program offers qualifying
households a minimum $9.25 discount on their monthly phone bills, or a free Lifeline cell phone
and monthly minutes from certain wireless providers. This report presents Lifeline participation
data for the July 2013 through June 2014 program year, and evaluates procedures put in place to
strengthen and streamline the Lifeline program.
As of June 30, 2014, 957,792 eligible households participated in the Florida Lifeline
program, which equates to approximately one of every eight Florida households. Lifeline
assistance participation includes the involvement of the Florida Public Service Commission
(FPSC), the Florida Department of Children and Families (DCF), the Florida Office of Public
Counsel (OPC), the Florida Department of Education (DOE) and other state agencies that
provide benefits to persons eligible for Lifeline service. 1
Approximately 50% of all Lifeline-eligible Florida households are receiving Lifeline
assistance. The Supplemental Nutrition Assistance Program (SNAP) continues to be the largest
qualifying program for Lifeline assistance in Florida. Based upon June 2014 SNAP participants,
the Lifeline eligible households 2 decreased by 1.2 percent compared to 2013 data, which may
reflect the improving Florida economy.
The Faces of Lifeline was the slogan for Florida’s 2014 Lifeline Awareness Week,
September 8-14. In addition to increasing awareness among eligible citizens, this year’s Lifeline
Awareness Week also aimed to educate residents about the Federal Communications
Commission (FCC) rule. This rule allows one Lifeline benefit per eligible household and
requires eligible citizens to annually recertify to continue the benefit.
The Commission continues to focus on enrollment process issues as a means of
increasing participation. Specific enrollment process initiatives include the following:
•
•
•
•
•
FPSC Lifeline Coordinated Online Application Process
FPSC/DCF Coordinated Lifeline Enrollment
Annual Recertification Procedures
DCF Certification/Verification Web Services Interface
Lifeline Work Group Meetings
1
Section 364.10(2)(g)1, Florida Statutes, requires each state agency that provides benefits to persons eligible for
Lifeline service to undertake, in cooperation with the DCF, the Department of Education, the FPSC, the OPC, and
ETCs providing Lifeline services, the development of procedures to promote Lifeline participation.
2
According to the U.S. Department of Agriculture Report, “Supplemental Nutrition Assistance Program: Number
Of Households Participating, ending June 30, 2014,” over 1,930,106 Florida households participated in the
Supplemental Nutrition Assistance Program. See Figure 2.
1
II.
Background
Each year, the FPSC is required to report to the Governor, the President of the Senate,
and the Speaker of the House of Representatives on the number of customers subscribing to
Lifeline service and the effectiveness of procedures to promote participation in the program.
This report is prepared pursuant to the requirements contained in Section 364.10, Florida
Statutes.
In Florida, if an applicant uses the electronic Lifeline Coordinated Enrollment Process 3 to
apply for Lifeline, the process will confirm if the applicant is currently participating in the
Medicaid, SNAP or Temporary Cash Assistance (TCA) 4 programs. If a program other than
Medicaid, SNAP, or TCA, is used for certification, the customer must provide documentation of
participation from the administering agency, which could be the Florida Department of
Education (free school lunch program), the Social Security Administration (Supplemental
Security Income), a county-level agency (Low-Income Home Energy Assistance Plan or Section
Eight Housing), or the Bureau of Indian Affairs for documentation. Current data shows that over
ninety-five percent of Florida applicants using the Lifeline Coordinated Enrollment Process use
Medicaid, SNAP, or TCA for eligibility.
If a Lifeline applicant chooses to apply for Lifeline directly with an eligible
telecommunications carrier (ETC), the ETC can access the DCF web services 5 to confirm
program participation for Medicaid, SNAP, and TCA. In Florida, certification and verification
can be accomplished using this process if the applicant or existing Lifeline customer participates
in the Medicaid, SNAP, or TCA programs which are administered by the DCF.
The National Lifeline Accountability Database (NLAD), which is maintained by the
Universal Service Administrative Company (USAC), 6 is designed to help carriers identify and
resolve duplicate claims for Lifeline Program supported service and prevent future duplicates.
This database provides a means for carriers to check, on a real-time and nationwide basis, if the
household is already receiving a Lifeline Program supported service. USAC activated the
National Lifeline Accountability Database for Florida Lifeline participants on March 6, 2014.
The FCC Lifeline Reform Order also called for the creation of a national eligibility
database for certification and program participation verification of Lifeline applicants. 7
3
The electronic Lifeline coordinated enrollment process was set up by the FPSC and DCF to allow an applicant for
Medicaid, SNAP, or TCA to request and receive Lifeline assistance after approved for the DCF program.
4
Nationally known as Temporary Assistance for Needy Families (TANF).
5
The Web services interface allows Florida ETCs a secure gateway into the DCF computer to verify that a Lifeline
customer is participating in the Medicaid, SNAP, or TCA programs administered by DCF. The ETC enters the
person's first and last name, date of birth, and last four digits of the person's social security number. The DCF
computer responds as to whether the person currently participates in one of the DCF programs without identifying
the program because of confidentiality. An ETC must pre-register with DCF to use the Web services interface to
ensure security is maintained.
6
The Universal Service Administrative Company (USAC) is an independent, not-for-profit corporation designated
by the Federal Communications Commission as the administrator of the Universal Service Fund. USAC collects
contributions from telecommunications carriers and administers support programs designed to help communities
across the country secure access to affordable telecommunications services.
7
A single nationwide database will be deployed and the physical infrastructure, connections, and all related
components will be located in a single location (or several locations to establish sufficient redundancy).
2
III. Lifeline Participation
Currently, FCC rules allow a $9.25 maximum reimbursement from the USAC to a
participating Lifeline carrier. The additional tier of support, available only to eligible subscribers
living on tribal lands, provides a credit up to $25.00 per month.
Florida Transitional Lifeline Assistance requires that ETCs offer former Lifeline
customers, who are no longer eligible, a 30 percent discount off the residential basic local service
rate. The customers are eligible to receive the discount for one year from the date the customer
ceases to be qualified for Lifeline. 8
Program-Based
Eligibility for Lifeline in Florida can be determined by customer enrollment in any one of
the following programs: 9
•
•
•
•
•
•
•
•
Food Assistance (SNAP)
Medicaid
Federal Public Housing Assistance (Section 8)
Supplement Security Income
Low-Income Home Energy Assistance Program
Temporary Cash Assistance (TCA)
National School Lunch Program - Free Lunch
Bureau of Indian Affairs Programs: Tribal Temporary Assistance to Needy Families,
Head Start Subsidy and National School Lunch Program
Income-Based
In addition to the program-based criteria, customers with annual incomes up to 150
percent of the Federal Poverty Guidelines may be eligible to participate in the Florida Lifeline
program.
Section 364.10(2)(a), Florida Statutes, provides that each local exchange
telecommunications company that has more than one million access lines and is an ETC shall
provide Lifeline service to citizens who meet an income eligibility test of up to 150 percent of
the Federal Poverty Guidelines. The U.S. Department of Health and Human Services updated
the 2014 Federal Poverty Guidelines, as shown in Attachment A. 10 The OPC certifies customer
eligibility under the income test for customers requesting to be enrolled in the Lifeline program
for the three major companies designated as ETCs. The OPC also performs income certification
for wireless ETCs who have filed a notice of election to do so with the FPSC. 11
The number of subscribers enrolled in Lifeline was 957,792 as of June 30, 2014, a 4.3
percent increase from the number of subscribers last year. Figure 1 shows the number of
8
9
10
11
Section 364.105, Florida Statutes.
Rule 25-4.0665(1) and (2), Florida Administrative Code.
Department of Health and Human Services, Annual Update of the Department of Health and Human Service
Poverty Guidelines. See Federal Register Notice, January 22, 2014.
See Section 364.10(2)(a), Florida Statutes.
3
Lifeline subscribers from June 2008 through 2014. In 2013, the decrease in subscribership was
largely attributable to the new FCC rules which require annual recertification of every subscriber
receiving Lifeline credits. Many customers failed to respond to the ETCs’ recertification
requests and were removed from the program.
Figure 1.
Florida Lifeline Subscribership
Source: Industry responses to FPSC data requests (2008-14)
In 2014, there was an increase in subscribership of 39,547 households, or 4.3 percent.
Lifeline eligible households decreased by 22,784 or 1.2 percent compared to 2013. The
participation rate grew to 49.6 percent, an increase of 2.6 percentage points, or 5.5 percent over
the 47.0 percent participation rate for the previous year. This may reflect an improving Florida
economy. Considering the number of households which are eligible to receive Lifeline in
Florida and the current participation rate, these numbers demonstrate the continued need for the
Lifeline program. Figure 2 shows participation rates in Florida households from June 2011
through June 2014.
Figure 2.
Lifeline Participation Rate In Eligible Florida Households for 2011-2014
Year
Lifeline
Enrollment
Eligible
Households
% Participation Rate
June 2011
943,854
1,690,512
55.8%
June 2012
1,035,858
1,864,183
55.6%
June 2013
918,245
1,952,890
47.0%
June 2014
957,792
1,930,106
49.6%
Sources: U.S. Department of Agriculture data figures are as of June 2014
4
IV. Lifeline Providers
Section 54.201(b) of the Code of Federal Regulations (CFR) allows state commissions to
designate a common carrier that meets certain requirements as an ETC 12 in a non-rural service
area. The CFR also allows state commissions to designate one or more common carriers as an
ETC in a rural service area. 13 The FPSC has determined that before designating a carrier as an
ETC, it should make an affirmative determination that such designation is in the public interest,
regardless of whether the applicant seeks designation in an area served by a rural or non-rural
carrier. 14
To qualify as an ETC, a common carrier must offer services that are supported by federal
universal service support mechanisms, either using its own facilities or a combination of its own
facilities and another carrier’s resold service, 15 and the carrier must advertise the availability of
such services and charges. Additionally, a company applying and qualifying for designation as
an ETC must demonstrate good management and legitimate business practices to successfully
administer the Lifeline program.
In 2011, the FCC took a technology neutral approach and determined that ETCs can use
any platform to provide voice service. Figure 3 shows the twenty-two companies which had
ETC status and participated in the Lifeline Program in Florida as of June 30, 2014. 16
12
13
14
15
16
Florida House Bill 1231, the Florida 2011 Legislature, removed the FPSC authority to designate ETC wireless
telecommunication providers. Effective July 1, 2012, wireless providers must directly apply for Florida ETC
designation with the FCC.
A state commission also has the authority to rescind the ETC status of any ETC designated by it that does not
follow the requirements of the Lifeline Assistance program.
See Docket No. 100124-TX, In RE: Petition for designation as eligible telecommunications carrier by Sun-Tel
USA, Inc., Order No. PSC-10-0634-PAA-TX, issued October 25, 2010.
Those services supported by Universal Service include the following: (1) voice grade access to the public
switched network or its functional equivalent, (2) minutes of use for local service provided at no additional
charge to end users, (3) toll limitation to qualifying low-income consumers, and (4) access to the emergency
services 911 and enhanced 911 services to the extent the local government in an eligible carrier's service area has
implemented 911 or enhanced 911 systems. However, the FCC started phasing down toll limitation service
reimbursement in 2012 and completely eliminated it effective January 1, 2014.
By Order No. PSC-13-0547-PAA-TX, issued October 29, 2013, the FPSC approved Unity Telecom, LLC’s
request for relinquishment of its ETC designation. By Order No. PSC-14-0144-PAA-TX, issued March 31,
2014, the FPSC approved Express Phone Service, Inc.’s request for relinquishment of its ETC designation.
5
Figure 3.
ETCs Participating in Florida Lifeline Program
Florida Companies Designated as ETCs
AT&T Florida (AT&T)
Budget Phone
Cox Florida Telecom, LP
CenturyLink
FLATEL, Inc.
Frontier Communications
Global Connection Inc.
FairPoint Communications
Access Wireless
ITS Telecommunications
Knology of Florida, Inc.
Nexus Communications, Inc.
NEFCOM
Quincy Telephone Company
Smart City Telecom
Sun-Tel USA, Inc.
T-Mobile Wireless
Tele Circuit Corporation
SafeLink Wireless
Assurance Wireless
Verizon Florida, LLC
Windstream Florida, Inc.
As of July 1, 2011, the FPSC no longer has authority to designate wireless ETCs in the
State of Florida. Wireless ETC applications for Florida are now filed directly with the FCC.
Figure 4 shows the 34 Florida ETC Wireless petitions pending at the FCC.
Figure 4.
Companies with Pending ETC Designation Petitions at FCC as of June 2014
ETC Petitions Pending at FCC
Airvoice Wireless
Amerimex
Blue Jay Wireless
Budget PrePay, Inc.
Consumer Cellular
FedLink Wireless
Free Mobile
Kajeet
LTS of Rocky Mount
Mobile Net POSA
Platinum Tel
Q Link Wireless
TNT Wireless
AmTel
Tempo Telecom
Total Call Mobile
Vast Communications’
American Broadband
Assist Wireless
Boomerang Wireless
Cintex Wireless
EZ Reach Mobile
ZING PCS
Global Connection
Linkup Telecom
Millennium 2000
Nexus Communications
Odin Wireless
TAG Mobile
Tele Circuit Network
Telrite
TerraCom
True Wireless
You Talk Mobile
6
Figure 5 shows the six Florida ETCs with the largest number of Lifeline customers in
June 2014, which represents 98.7 percent of the total Lifeline customer participation.
Figure 5.
Six Florida ETCs with the Largest Number of Lifeline Customers in June 2014
Source: Industry responses to 2014 FPSC data requests
Figure 6 reflects the USAC Lifeline disbursements to Florida for the 12-month period
ending June 2014, totaling $107,537,790, an average of $8,961,483 per month over the period.
These dollars enabled Florida citizens qualifying for Lifeline benefits to receive discounted
monthly bills with a current minimum credit of $9.25, or a free Lifeline wireless phone with up
to 250 free monthly minutes from certain wireless providers.
Figure 6.
USAC Low Income ETC Disbursements to Florida Providers
Source: USAC Disbursements Florida June 2013-2014 17
17
The Figure 6 fluctuations in the months of December 2013 and January 2014 were caused by Assurance Wireless’
filing dates for Lifeline credit reimbursement from the universal service fund.
7
As of June 30, 2014, the total Lifeline enrollment in Florida was 957,792 households.
Florida had a 4.31 net percentage increase in enrollment as of June 30, 2014, over the previous
year. Attachment B represents the historic enrollment figures for the Lifeline program listed by
each of the ETCs.
8
V. Lifeline Enrollment Process and Improvement Activities
A. Lifeline Electronic Coordinated Enrollment Process
Implementation of the electronic Lifeline Coordinated Enrollment Process has been a
major success. The FPSC began formally tracking the number of Lifeline applications filed via
the Lifeline Coordinated Enrollment Process in April 1, 2007. Cumulative Lifeline coordinated
enrollment applications as of June 30, 2014, totaled 650,825 over the seven year period.
The coordinated enrollment process requires a DCF client to indicate an interest in
receiving the Lifeline discount. The applicant then identifies a telephone service provider from a
drop-down box on the application and answers applicable questions. Once a client is determined
to be eligible for Medicaid, SNAP, or TCA, DCF will forward the necessary information for
Lifeline enrollment to the FPSC. The FPSC places this information on a secure Web site for
retrieval by the appropriate ETC.
All ETCs are required to enroll the subscriber in the Lifeline program as soon as possible,
but no later than 60 days from the receipt of the FPSC’s e-mail notification. In addition, the ETC
is required to credit the subscriber’s bill for Lifeline service as of the date the ETC received the
FPSC’s e-mail notification. 18
ETCs are required to provide the FPSC the names, addresses, telephone numbers, and the
date of the application for any misdirected applications; any applications for customers currently
receiving Lifeline service; or any rejected applicants, including the reason(s) the applicants were
rejected. FPSC staff then sends letters to the rejected applicants if the company they named on
the application as providing their telephone service does not have them listed as a current
customer, or if DCF could not confirm their current participation in one of their qualifying
programs. FPSC staff includes a new application with the letter along with staff contact
information if they need assistance with the application process.
B. Transitional Lifeline
In accordance with Section 364.105, Florida Statutes, current Lifeline customers who no
longer meet eligibility criteria and are removed from Lifeline service are eligible to receive a 30
percent discount on the residential basic local service rate for a period of one year after ending
Lifeline service. For example, a former Lifeline customer with a phone bill that includes a
$25.00 basic rate would receive a $7.50 monthly discount for one year. Transitioning from
Lifeline service means that the consumer’s socio-economic status may have improved, and the
customer may have advanced beyond the qualifying eligibility criteria.
Figure 7 presents the number of Transitional Lifeline customers for AT&T, Verizon, and
CenturyLink for June 2010 through June 2014. The large increase in the number of Transitional
Lifeline participants in 2013 19 is attributable to customers being de-enrolled from the Florida
Lifeline program due to the new FCC requirement to annually recertify Lifeline customers.
18
19
See Rule 25-4.0665(10)(b), Florida Administrative Code.
In 2013, AT&T reported 32,783; CenturyLink reported 488; and Verizon reported 23. In 2014, AT&T reported
4,921; CenturyLink reported 566; and Verizon reported 2,550.
9
These former Lifeline participants may elect to receive Transitional Lifeline benefits for up to
one year.
Figure 7.
AT&T, Verizon, and CenturyLink Transitional Lifeline Participants 2010-2014
Source: Industry responses to FPSC data requests (2010-2014)
Several actions by the FPSC and FCC occurred during the July 1, 2013 through June 30,
2014 period. A discussion of these initiatives is presented below.
C. Florida Public Service Commission Activities
1. Lifeline Work Group Met December 2013
The Lifeline Work Group was created by Section 364.10(2)(g)3, Florida Statutes, and
includes the FPSC, DCF, OPC, and each Florida ETC offering Lifeline service. Its purpose is to
determine how the eligible Lifeline subscriber information will be shared, the obligations of each
party with respect to the use of that information, and the procedures to be implemented to
increase enrollment and verify eligibility in these programs.
FPSC staff conducted a meeting of the Lifeline Work Group on December 5, 2013. The
purpose of this meeting was for the Lifeline Work Group to discuss:
a. The DCF Web Services Interface which verifies participation in the Medicaid,
SNAP, and TCA for Lifeline verification, and new federal rules regarding state
databases.
b. The status of the FCC Temporary Waiver for Florida of the FCC rules which
require state agencies that make the initial determination of a subscriber's
eligibility for Lifeline to provide each ETC with a hard-copy of each of the
Lifeline certification forms.
10
c. Determine how each Florida ETC will perform the required 2013 Lifeline
customer recertification required by the FCC.
d. Solicit ideas to further streamline the Lifeline enrollment process for both the
applicant and ETC.
2. FPSC Continued Actions to Prevent Waste, Fraud and Abuse of the Federal
Universal Service Fund
In 2013-2014, Florida continued enforcing safeguards to prevent waste, fraud, and abuse
of the Universal Service Fund. Florida’s leadership in implementing and administering the
National ETC State Coordinating Group to monitor prospective and existing ETCs across the
country, has enabled information sharing with all states 20 on a national basis. Protecting against
waste, fraud, and abuse in the Lifeline program is contingent upon developing adequate
safeguards to ensure that funds are being disbursed and expended according to state and federal
regulations and guidelines. The FPSC monitors monthly federal universal service funds
disbursed to ETCs operating in Florida to determine the number of Lifeline participants in
Florida by month.
The FPSC strives to protect the integrity of the Lifeline program in the State of Florida
and takes appropriate enforcement action when necessary. The FPSC has statutory authority to
grant landline ETC designations, and can also revoke ETC status when warranted. Unlawful and
inappropriate federal Universal Service Fund disbursements are inconsistent with public trust
and negatively impacts states like Florida, which contribute more into the Universal Service
Fund than it receives. Florida continues to be commended by the FCC for its continued and
formidable efforts to identify and eliminate fraud in the Lifeline Assistance program and
Universal Service Fund.
3. FCC Requirement to Provide Hard-Copy Certifications of Lifeline Applicants to
ETCs
FCC Order 12-11 stated that ETCs must not seek reimbursement from the federal
Universal Service Fund unless the ETC has received from the state Lifeline administrator or
other state agency, a copy of the Lifeline subscriber’s certification form. 21 The Order also
required state Lifeline administrators or other state agencies that are responsible for the initial
determination of a subscriber’s eligibility for Lifeline to provide each ETC with a hard-copy of
each of the Lifeline certification forms. 22
The United States Telecom Association (US Telecom) filed for and received three
consecutive waivers of this requirement on behalf of states, which included Florida, through
February 1, 2014. The US Telecom Waiver Request granted August 30, 2013, 23 states that “...if
an ETC or state believes that it will be unable to come into compliance and seeks a permanent
20
21
22
23
The ETC State Coordinating group includes state commission members from all fifty states and the District of
Columbia.
47 C.F.R. §54.410(b)(2)(ii), 47 C.F.R. §54.410(c)(2)(ii), and 47 C.F.R. §54.407(d)
47 C.F.R. §54.410(e)
In the Matter of Lifeline and Link Up Reform and Modernization, WC Docket No. 11-42, DA 13-1853, released
August 30, 2013.
11
waiver from the rules, it must provide in its request for permanent relief an explanation for why
such relief is appropriate.”
Florida has put in place a streamlined, efficient, and verifiable Lifeline Electronic
Coordinated Enrollment process that does not have the capability or necessity of printing out a
hard-copy Lifeline application. This advanced process involves a computer interface between
the FPSC and the DCF for Lifeline applicants who currently participate in the Medicaid, the
SNAP, or the TCA program. The Florida process eliminates the need to require or maintain
hard-copy Lifeline certification applications.
On October 25, 2013, the FPSC filed a petition with the FCC providing a status update
and request for a permanent waiver of the requirement to provide hard-copy certifications to
ETCs. On June 6, 2014, the FCC released Order DA 14-785, granting Florida a permanent
waiver of the FCC requirements to provide hard-copy Lifeline applications to eligible
telecommunications carriers. In the Order, the FCC stated a permanent waiver is appropriate
because Florida’s screening system fulfills the underlying purpose of the rules to limit Lifeline
benefits to eligible consumers.
4. Comments FPSC Filed with the FCC Addressing the Waiver of Certain Lifeline
Rules for the Benefit of Those Individuals Participating in State-Administered
Address Confidentiality Programs
On November 21, 2013, the FCC released a Public Notice (DA 13-2240) seeking
comment on waiving certain Lifeline rules for the benefit of those individuals participating in
state-administered Address Confidentiality Programs. Address Confidentiality Programs protect
victims of domestic violence by allowing them to use a substitute mailing address rather than
their physical home address. On December 17, 2013, the FPSC submitted comments in response
to the FCC’s Public Notice and encouraged the FCC to consider the following:
a. The FCC should waive the rule limiting the use of P.O. Boxes as
residential addresses, to allow qualifying, low-income consumers who
participate in state-administered Address Confidentiality Programs to
receive Lifeline service.
b. In Florida, Eligible Telecommunications Carriers should accept a Florida
Address Confidentiality Program authorization card as proof of Address
Confidentiality Program enrollment.
c. The FCC should waive the requirement for Address Confidentiality
Program participants to fill out a one per household worksheet.
During 2013, there were 108,030 cases of domestic violence reported to the Florida
Department of Law Enforcement. Developing a process for Address Confidentiality Program
participants to enroll in Lifeline while protecting their physical address is vital.
12
D. Federal Communications Commission Activities
1. 2013 Recertification of Florida Lifeline Subscribers
The FCC adopted a set of uniform recertification procedures that all ETCs must perform
annually to verify the ongoing eligibility of their Lifeline subscribers. 24 To comply with the
annual requirement for 2013, all ETCs and state Lifeline administrators were required to
recertify the eligibility of their Lifeline subscriber base by the end of 2013, and report the results
to USAC by January 31, 2014. Subscribers failing to respond to recertification efforts had to be
de-enrolled from Lifeline. As a result of the 2013 recertification process, 350,817 customers or
34.05 percent were de-enrolled from the Florida Lifeline program.
ETCs have the option of recertifying subscribers in one of two ways. The first is to
verify program or income-based eligibility where an ETC can query the available database to
confirm the subscriber’s continued eligibility. In the absence of a database, the ETC must
recertify the continued eligibility of a subscriber by writing, phone, text message, e-mail,
Interactive Voice Response, or otherwise through the Internet using an electronic signature. If an
ETC is unable to recertify a subscriber, the subscriber is offered transitional Lifeline benefits at a
30 percent discount of the local telecommunications service rate for one year. 25
2. 2014 Recertification of Florida Lifeline Subscribers
As explained in the requirements for Lifeline recertification, subscribers failing to
respond to recertification efforts must be de-enrolled from Lifeline. The number of subscribers
claimed by Florida ETCs in February 2014 was 825,046, and the number of subscribers not
responding for recertification was 154,348. The number of subscribers who responded that they
are no longer eligible for Lifeline benefits was 217. As a result of the 2014 recertification
process, 154,565 customers or 18.73 percent were de-enrolled from the Florida Lifeline
program. 26 Results of the recertification by company are presented in Attachment C.
3. Duplicate Lifeline Support
Eligible consumers can only receive one Lifeline-supported service per household. 27 If
there are two households residing at one address and each desire to participate in Lifeline, each
applicant would have to complete a one-per-household worksheet to demonstrate that each
applicant is living in a separate economic unit and not sharing living expenses (bills, food, etc.)
or income with another resident. 28
24
See Order FCC 12-11, 27 FCC Rcd at 6714-22, paras. 129-148; 47 C.F.R. § 54.410(f).
Section 364.105, Florida Statutes, Discounted rate for basic service for former Lifeline subscribers.
26
Numbers recorded by ETCs on FCC Form 555, Annual Lifeline Eligible Telecommunications Carrier
Certification Form.
27
See id., 27 FCC Rcd at 6689, para. 74. The one-per-household rule is codified at 47 C.F.R. § 54.409(c). See 47
C.F.R. § 54.409(c). This rule became effective June 1, 2012. See Lifeline Reform Order, 27 FCC Rcd at 685960, para. 515; 77 FR 12952 (March 2, 2012), corrected by 77 FR 19125 (Mar. 30, 2012).
28
A household Lifeline eligibility pre-screening tool is available at www.lifelinesupport.org.
25
13
By Order FCC 12-11, the FCC directed USAC to establish a database to both eliminate
existing duplicative support and prevent duplicative support in the future. To prevent waste in
the Universal Service Fund, the FCC created and mandated the use by ETCs of a National
Lifeline Accountability Database (NLAD) to ensure that multiple ETCs do not seek and receive
reimbursement for the same Lifeline subscriber.
The NLAD conducts a nationwide real-time check to determine if the consumer or
another person at the address of the consumer, is already receiving a Lifeline Program-supported
service. The NLAD can only be effective if ETCs provide to the NLAD the following
information for each new and existing Lifeline subscriber.
•
•
•
•
•
•
•
•
•
The subscriber’s full name
Full residential address
Date of birth
Last four digits of the subscriber’s Social Security number or Tribal Identification
number, if the subscriber is a member of a Tribal nation and does not have a Social
Security number
The telephone number associated with the Lifeline service
The date on which the Lifeline service was initiated
The date on which the Lifeline service was terminated, if it has been terminated
The amount of support being sought for that subscriber, and
The means through which the subscriber qualified for Lifeline
After December 2013, ETCs must provide information for existing Lifeline subscribers to
the NLAD by state, and for new subscribers upon initiation of service. The NLAD transitioned
states to its database on a state-by-state basis. Florida ETCs were operational on the NLAD
starting March 6, 2014.
4. AT&T TDM-to-IP Transition
On November 7, 2012, AT&T filed a petition asking the FCC to allow incumbent local
exchange carriers to retire their existing Time-Division Multiplexing (TDM) services in select
exchanges and introduce all-IP services in their place. On January 31, 2014, the FCC invited
interested providers to submit detailed proposals to test real-world applications of planned
changes in technology likely to have tangible effects on consumers. AT&T submitted its
proposal to the FCC on February 27, 2014, to conduct the trials in a rural wire center in Carbon
Hill, AL, and in a suburban wire center in Palm Beach County, FL (Kings Point).
AT&T proposes to conduct the trials in three phases: phase one will have customers opt
for new services voluntarily, phase two will grandfather TDM-based services, and phase three
will sunset all TDM-based services in these exchanges and require customers to migrate to IPbased products. Within AT&T’s wireline and wireless footprints, it will offer consumers and
businesses wireline and wireless products as substitutions for traditional TDM services. In areas
within AT&T’s wireless footprint but outside its wireline footprint, only wireless services plan
will be offered. In its February 27, 2014 filing, AT&T stated that there is no reason to require
AT&T to remain an eligible telecommunications carrier in the trial rate center solely to provide
14
Lifeline, so it will be requesting that its ETC status be relinquished in the trial rate center and, if
approved, it will no longer provide Lifeline there.
5. Petitions to FCC to Allow Incumbent Wireline Lifeline Providers to Opt Out of
the Lifeline Program
On January 23, 2012, AT&T met with the FCC and suggested that it should allow
incumbent wireline Lifeline providers to choose whether to participate in the Lifeline program.
AT&T emphasized that wireline telephone companies are no longer dominant providers of voice
service and thus should be able to choose whether to participate in the Lifeline program, just as
wireless providers do today.
In Order FCC 12-11, the FCC sought comment on this suggestion in this docket, and how
it might be implemented given the statutory framework for revocation of ETC designations set
forth in section 214. The FCC wanted to know how the FCC, or the states, would ensure that
low-income consumers in all regions of the country have “access to telecommunications and
information services.”
On September 15, 2014, AT&T submitted comments to the FCC stating that there is no
reason in law or policy for the FCC to continue its current overly-broad ETC regime or its
mandatory Lifeline requirements for incumbent local exchange companies. It believes Lifeline
participation should be made voluntary for ILECs. AT&T urged the FCC to update its ETC and
Lifeline rules and requirements to better reflect the existing competitive landscape.” 29
On October 6, 2014, the United States Telecom Association (USTA) filed a petition with
the FCC for forbearance from various outdated regulatory requirements applicable to incumbent
local exchange carriers, including mandatory provision of Lifeline. The USTA stated that almost
all Lifeline customers prefer wireless services, and given the substantial non-reimbursable costs
to carriers involved in Lifeline participation and the multiple Lifeline providers in price cap
carriers’ service areas, there is no reason to continue compelling price cap carriers to offer
Lifeline service to consumers that do not want it. 30 An FCC decision is pending.
29
30
WC Docket No. 10-90, Connect America Fund; WC Docket No. 11-42, Lifeline and Link Up Reform and
Modernization.
Petition of USTelecom for Forbearance Pursuant to 47 U.S.C. §160(c) from Obsolete ILEC Regulatory
Obligations that Inhibit Deployment of Next-Generation Networks.
15
VI.
Lifeline Promotion Activities
Promotional activities in 2014 featured National Lifeline Awareness Week, National
Consumer Protection Week, Older American’s Month, and ongoing “grass roots” efforts to
increase awareness and enrollment in the Lifeline program.
Lifeline Across America. In 2014, the Lifeline Across America Working Group [FCC,
National Association of Regulatory Utility Commissioners, and National Association of State
Utility Consumer Advocates representatives] concentrated on the sixth annual National Lifeline
Awareness Week (Lifeline Awareness Week). The Group’s national effort is to ensure that low
income families and individuals are aware of the Lifeline program and understand the
participation requirements, including the requirement that eligible consumers may receive no
more than one Lifeline discount. The FCC continues to review reforms to further reduce
program fraud and abuse, working with its Lifeline Across America Working Group partners
and others to increase awareness among low-income consumers about the recent program
reforms and participation requirements.
According to National Association of Regulatory Utility Commissioners, more than
fifteen state public utility commissions issued press releases, received gubernatorial
proclamations, released radio and television public service announcements, and published lettersto-the-editor to help promote Lifeline.
National Lifeline Awareness Week (September 8-14, 2014). The Faces of Lifeline was the
theme for Florida’s 2014 Lifeline Awareness Week, September 8-14. In addition to increasing
awareness among eligible citizens, this year’s Lifeline Awareness Week also aimed to continue
educating residents on the FCC rule changes to limit benefits to one per eligible household and
require annual recertification to continue the benefit. FPSC Chairman Art Graham kicked off the
week by showcasing Florida’s “Faces of Lifeline.” He stressed how people need phone service
to help them find jobs, contact community services, call doctors and schools or connect to family
and friends. Chairman Graham urged consumers to meet the “Faces of Lifeline” on the FPSC’s
website, then identify faces within their community, maybe even some neighbors, who could
benefit from the program. The FPSC partners with many agencies year-round to make sure
eligible consumers know about Lifeline and know how to sign up.
Now in its sixth year, Lifeline Awareness Week events were also held around Florida to
help seniors and low-income Floridians learn about, and apply for, the Lifeline program. The
FPSC visited senior centers in Lakeland, Orlando, Starke, and Tallahassee and partnered with the
Career Source Tampa Bay to help Florida’s residents save money on their telephone and utility
bills and to share recent Lifeline information. Each Lifeline Awareness Week event offered
individual assistance to consumers applying for the program.
Lifeline Outreach to Florida’s Superintendents. In July, Florida’s Superintendents were sent
a Lifeline outreach letter with brochure samples (in three languages) and applications to include
in students’ Back-to-School information. As a result, the FPSC provided more than 26,000
Lifeline brochures and applications to eligible families in six Florida counties.
16
National Consumer Protection Week and Other Community Events.
The FPSC
continuously seeks existing community events as well as new venues and opportunities where
Lifeline educational materials can be distributed and discussed with citizens. National Consumer
Protection Week (NCPW), March 2-8, 2014, was a good backdrop for Lifeline outreach
activities. NCPW, an annual consumer education campaign, encourages individuals to take
advantage of their consumer rights. For this year’s event, FPSC Chairman Art Graham was
featured in a Public Service Announcement about scams targeting utility customers and customer
protection tips for the FPSC website; it was also made accessible to media outlets for their
broadcasts. Also during NCPW, the FPSC made presentations in Madison, Jasper, Lake
Panasoffkee, and at Pow Wow’s in Deland and Mount Dora showing consumers how to save
money through energy and water conservation and how to sign up for the Lifeline program.
For the third year, the FPSC participated in a national project called Older Americans
Month--celebrated each May to honor and recognize older Americans for the contributions they
make to their families, communities, and society. Safe Today. Healthy Tomorrow. was this
year’s theme, and the FPSC held educational sessions with Florida senior centers in Sarasota,
Venice, Jacksonville, and Bristol to show seniors ways to conserve energy and water and learn
about the Lifeline program. For the second year, the FPSC distributed brochures and
publications at the Jacksonville Expo, where over 5,000 seniors attended. An FPSC article
highlighting the FPSC’s website video, “Life Before Air Conditioning,” and the Commission’s
outreach activities were featured in the July/August 2014 issue of the Florida Department of
Elder Affairs’ Elder Update.
Each year the FPSC provides educational packets, including publications, Lifeline
brochures and applications in English, Spanish, and Creole, to Florida public libraries across the
state for consumer distribution. For the second year, the FPSC’s Library Outreach Campaign
increased in number from 333 sites to 583 sites, including all state public libraries and branches.
Following the Campaign, many libraries’ requests for additional publications have been filled.
Figure 8.
Events and locations where Lifeline information was shared in Florida
Lifeline Events and Locations
Ambassadors for Aging Day
Tallahassee Housing Authority
Clearwater Housing Authority
Alachua County Senior Center
Jefferson County Senior Center
Barbara Washington Senior Center
Moncrief Senior Center
Dixie Suwanee County Senior Center
Oceanway Senior Center
Lincoln Villa Senior Center
Senior Day at Jake Gaither Center
Florida DOH American Indian Heritage Month
Springfield Community Center
Community Rehabilitation Center
Florida DOEA Fraud Prevention Seminar
Active Living Expo
Pinellas Housing Authority
Baker Manor Housing Authority
Taylor County Senior Center
8th Avenue Senior Center
Mary L. Singleton Senior Center
Woodville Senior Center
Lafayette Suwanee County Senior Center
Louis Dinah Senior Center
Ft. Braden Senior Center
Baker Council on Aging
Northeast Community Action Agency
Shine Women’s Conference
Maranatha Seventh-Day Adventist Church
Florida DOH Community Fair and Refugee Day
17
Community Services Block Grant Program. The Florida Department of Economic
Opportunity includes Lifeline services as an indicator in its work plan, allowing
the Community Action Agencies to report on the number of clients they help to secure Lifeline
services. During the October 1, 2012–September 30, 2013 reporting period, an estimated 1,390
households signed up for Lifeline benefits through local Community Action Agencies, with
$181,000 in estimated benefits to clients. For the reporting period, 16 of the 27 community
action agencies provided Lifeline enrollment services to clients.
Income-Based Lifeline Applicants. The OPC provides assistance to consumers applying for
Lifeline Assistance based upon income level. During July 2013–June 2014 reporting period,
OPC received over 20,000 calls from potential applicants seeking assistance, and processed
36,136 applications. The OPC verifies consumer income eligibility for the following
telecommunication carriers: Assurance Wireless, AT&T Landline, CenturyLink Landline,
SafeLink Wireless, T-Mobile Wireless, and Verizon Landline.
Ongoing Lifeline Outreach. Ensuring easily accessible Lifeline information through the
agencies and organizations having regular interaction with eligible consumers is crucial to the
Lifeline awareness effort. The Lifeline Partners listed in the next section participate in local
community events, offer training sessions, provide updates about program changes, and supply
brochures and applications.
Lifeline Partners. Attachment D shows local, state, and federal agencies, organizations,
businesses, and telecommunications companies that are involved in the collaborative effort to
increase awareness and participation in the Lifeline program. Each month, the FPSC sends a
cover letter and informational packet to two organizations to encourage continued Lifeline
outreach to their eligible clientele. Additionally, the FPSC attends two community events
monthly to promote Lifeline.
18
VII. Conclusion
As of June 30, 2014, 957,792 eligible customers participated in the Florida Lifeline
program. The success of the Florida Lifeline program can be attributed to the continued
partnership between the FPSC, DCF, OPC, and other agencies around the state that assist Florida
low-income families.
As a result of Florida Lifeline participation, USAC Low Income disbursements for
Florida ETCs for the 12-month period ending June 2014, totaled over $107 million. These
dollars enabled Florida citizens qualifying for Lifeline benefits to receive discounted monthly
bills with a current credit of at least $9.25, or a free Lifeline wireless phone with 250 free
monthly minutes. The ETC designation of successful prepaid wireless providers, such as
SafeLink Wireless Assurance Wireless, and i-wireless, which provide a free phone and free
monthly minutes to the customer, has been a major growth factor in the Florida Lifeline program
the last several years.
Efforts to increase Lifeline participation can be separated into two categories, consumer
outreach and enrollment process. The FPSC, in cooperation with other state and federal
agencies, the OPC, ETCs, and other organizations, remains engaged in extensive outreach
efforts. Because most of these efforts run concurrently, measuring the impact of any single
activity on Lifeline participation is difficult. Nevertheless, outreach efforts overall are having a
positive outcome and should be continued. Outreach efforts are also being expanded to include
more competitive local exchange carrier and wireless ETCs.
The Commission continues to focus on enrollment process issues as a means of
increasing participation. As previously discussed in this report, specific enrollment process
initiatives include the following:
•
•
•
•
•
FPSC Lifeline Coordinated Online Application Process
FPSC/DCF Coordinated Lifeline Enrollment
Annual Recertification Procedures
DCF Certification/Verification Web Services Interface
Lifeline Work Group Meetings
The FPSC remains committed to enabling low-income households in Florida obtain and
maintain basic local telephone service to help them find jobs, contact community services, call
doctors and schools, and connect to family and friends. The FPSC will continue to identify and
find solutions to barriers that may prevent Lifeline from achieving greater success for the benefit
of Florida’s low-income consumers. The FPSC will also continue its work on streamlining the
Lifeline enrollment process and refining the FPSC/DCF Lifeline coordinated application
procedure in Florida so that applying for the Lifeline program is easier and faster than in
previous years.
19
Attachment A
Attachment A. 2014 U.S. Poverty Guidelines
Household size
(number persons)
2014 U.S. Poverty
Guidelines
Total Household
Annual Income
150% of U.S. Poverty
Guidelines
Total Household
Monthly Income
150% of U.S. Poverty
Guidelines
Total Household
Annual Income*
1
$11,670
$1,459
$17,505
2
$15,730
$1,966
$23,595
3
$19,790
$2,474
$29,685
4
$23,850
$2,981
$35,775
5
$27,910
$3,489
$41,865
6
$31,970
$3,996
$47,955
7
$36,030
$4,504
$54,045
8
$40,090
$5,011
$60,135
*For families with more than 8 persons, add $6,090 for each additional person to the yearly amount.
20
Attachment B
Attachment B. Lifeline Net Enrollment and Year-to-Year Net Growth Rate
ETCs
TracFone
Net
Growth
Rate
2010
to
2011
Net
Growth
Rate
2011
to
2012
June
2011
396,114
447,379
12.9%
430,048
-3.9%
490,828
14.1%
543,174
10.7%
286,866
100.0%
428,830
49.5%
323,014
-24.7 %
249,664
-22.7%
12,450
100.0%
97,044
679.5%
i-wireless
AT&T
June
2013
Net
Growth
Rate
2013
to
2014
June
2010
Virgin Mobile
June
2012
Net
Growth
Rate
2012
to
2013
June
2014
126,114
122,849
-2.6%
102,363
-16.7%
44,796
-56.2%
28,156
-37.2%
CenturyLink
41,593
39,524
-5.0%
35,154
-11.1%
22,179
-36.9%
18,756
-15.4%
Verizon
23,681
22,307
-5.8%
18,496
-17.1%
11,327
-38.8%
8,245
-27.2%
5,517
6,249
13.3%
6,775
8.4%
5,176
-23.6%
4,348
-16.0%
70
100.0%
232
231.4%
1,373
491.8%
3,091
125.1%
2,446
-20.9%
2,146
-12.3%
1,437
-33.0%
1,307
-9.1%
1,497
100.0%
637
-57.5%
666
4.6%
Windstream
T-Mobile
FairPoint
3,093
Tele Circuit
Non-ETC
Reseller
13,664
4,941
-63.8%
2,828
-42.8%
979
-65.4%
658
-32.8%
NEFCOM
769
795
3.4%
804
1.1%
712
-11.4%
545
-23.5%
41
100.0%
522
1173.2%
Cox Telecom
Budget Phone
3,099
2,912
-6.0%
1,399
-52.0%
776
-44.5%
407
-47.6%
TDS Telecom
920
811
-11.9%
728
-10.2%
582
-20.1%
406
-30.2%
Knology
959
761
-20.7%
751
-1.3%
516
-31.3%
294
-43.0%
594
100.0%
789
32.8%
275
-65.2%
Global
Connection
Frontier
159
157
-1.3%
174
10.8%
114
-34.5%
84
-26.3%
ITS Telecom
147
178
21.1%
190
6.7%
112
-41.1%
77
-31.3%
Nexus
333
201
-39.6%
132
-34.3%
69
-47.7%
51
-26.1%
18
23
27.8%
33
43.5%
21
-36.4%
12
-42.9%
1,888
2,845
50.7%
1,469
-48.4%
304
-79.3%
10
-96.8%
434
100.0%
1,065
145.4%
13
-98.8%
0
-100.0%
23,870
2106
-91.2%
150
-92.9%
0
100.0%
0
0.0%
641,938
943,854
47.0%
1,035,858
9.8%
918,245
-11.4%
957,792
4.3%
Smart City
FLATEL
Sun-Tel
ETCs which
Relinquished
Designation
Total
Sources: FPSC data requests (2010-2014).
21
Attachment C
Attachment C. Recertification of Florida Lifeline Subscribers
Company
Number of
Number of
Number of Lifeline
Number of
Subscribers
Lifeline Not
Subscribers
Subscribers
Claimed in
Responding To
Responding That
De-Enrolled
February 2014 Recertification They Are No Longer
Eligible
ILECs
NEFCOM
Smart City Telecommunications
TDS/Quincy
AT&T
CenturyLink
ITS Telecommunications
Frontier
Verizon
Windstream
GTC - Florala, St. Joe, Gulf
CLECs
Knology
Unity Telecom f/k/a dPi
Absolute Home Phones
Global Connection Inc.
Tele Circuit
Easy Telephone Services
Budget Prepay
FLATEL
Sun-Tel USA
Nexus Communications
Express Phone Service
Cox Florida Telecom, L.P.
Wireless
T-Mobile
Assurance Wireless
SafeLink Wireless
i-wireless
Total
Percent of
Lifeline
Subscribers
De-Enrolled
653
24
533
37,313
17,314
110
103
10,525
4,766
952
192
10
163
12,696
6,389
58
41
2,388
1,785
367
0
0
0
0
0
0
0
0
0
0
192
10
163
12,696
6,389
58
41
2,388
1,785
367
29.40%
41.67%
30.58%
34.03%
36.90%
52.73%
39.81%
22.69%
37.45%
38.55%
498
0
0
330
103
0
946
323
0
0
0
0
0
0
24
0
0
400
0
0
0
0
217
0
0
0
0
0
0
0
0
0
0
217
0
0
24
0
0
400
0
0
0
0
43.57%
N/A
N/A
7.27%
0.00%
N/A
42.28%
0.00%
N/A
N/A
N/A
N/A
476
285,289
461,344
3,444
57
107,178
22,439
161
0
0
0
0
57
107,178
22,439
161
11.97%
37.57%
4.86%
4.67%
825,046
154,348
217
154,565
18.73%
Source: Form 555 forms submitted to FCC and Universal Service Administrative Company by ETCs.
22
Attachment D
Attachment D. Agencies, Organizations, and Business Lifeline Partners
Florida Lifeline Partners
AARP - Florida Chapter
Ability Housing of Northeast Florida
ACCESS Florida Community Network
Agency for Health Care Administration
Agency for Persons with Disabilities
Aging Matters in Brevard County
Alliance for Aging, Inc.
Area Agencies on Aging
Big Bend 2-1-1 and other 2-1-1 Agencies
Boley Centers, Inc.
Braille and Talking Book Library
Brain Injury Association of Florida, Inc.
Bureau of Indian Affairs Programs
Capital Area Community Action Agency
Catholic Charities of Central Florida
Centers for Drug Free Living
Centers for Independent Living
City and County Consumer Assistance
City and County Housing Authorities
Foster Grandparent Program
Community Partnership Group
Disability Rights Florida
Faith Radio and other Florida radio stations
Federal Social Security Administration
First Quality Home Care
Florida Alliance for Information and Referral
Florida Assisted Living Association
Florida Association for Community Action
Florida Assoc. of Community Health Centers
Florida Association of Counties
Florida Assoc. of Human Service Admin.
Florida Association of Food Banks (FAFB)
Florida Housing and Redevelopment
Florida Coalition for Children
Florida Coalition for the Homeless
Florida Council on Aging
Florida Deaf Services Centers Association
Florida Department of Children and Families
Florida Department of Community Affairs
Florida Dept. of Economic Opportunity
Florida Department of Education
Florida Department of Elder Affairs (DEA)
Florida Department of Revenue (DOR)
Florida Department of Veterans’ Affairs
Florida Developmental Disabilities Council
Florida Elder Care Services
Florida Home Partnership
Florida Hospital Association
Florida Housing Coalition
Florida Housing Finance Corporation
Florida League of Cities, Inc.
Florida Low Income Housing Associates
Florida Nurses Association
Florida Office of Public Counsel (OPC)
Florida Public Libraries
Florida Public School Districts
Florida Rural Legal Services, Inc.
Florida Senior Medicare Patrol
Florida Senior Program
Florida Telecommunications Relay, Inc.
Florida Voters League
1000 Friends of Florida, Inc.
Habitat for Humanity – Florida
HANDS of Central Florida
Hemophilia Foundation of Greater Florida
Hispanic Office for Local Assistance
Leon County School Board
Living Stones Native Circle
Marion Senior Services
Mid-Florida Housing Partnership, Inc.
Miccosukee Tribe of Indians of Florida
NAACP (Florida Associations)
Nursing Homes Administrators
Florida Dept. of Economic Opportunity
Seminole County Community Development
Seniors First
Senior Resource Alliance
South East American Council, Inc.
Refuge House of the Big Bend
Tallahassee Memorial and other hospitals
Tallahassee Urban League
Tampa Vet Center
Three Rivers Legal Services, Inc.
United Home Care Services
United Way of Florida
Urban Leagues of Florida
U.S. Housing and Urban Development
Washington County Council on Aging
23
II. Outside Persons Who
Wish to Address the
Commission at
Internal Affairs
OUTSIDE PERSONS WHO WISH
TO ADDRESS THE COMMISSION AT
INTERNAL AFFAIRS
November 25, 2014
Speaker
Representing
Item #
Stephanie Kunkel
Sierra Club
1&2
T.J. Szelistowski
TECO
2
III. Supplemental
Materials for Internal
Affairs
Note: The following material pertains to Item 1
of this agenda.
Handout
@aLOggSyAgenda
on lt / 2s/ r.l
ttem-E.f__
Changes to draft comments
Page 17 (Building Block 3)
The EPA's adoption of North Carolina's renewable energy and energy efficiency
portfolio standard (REPS) for Florida does not realistically reflect the available renewable
i.rour.., or policy framework in Florida. ' Fot example, Florida lacks viable wind resourcest
and has limited biomass opportunities, given competing industrial use of biomass resou.c"s.
is
ineluding muni€ipat
selid
Additionally.
+eei+ienaUy; Instead, EPA elected to group Florida with Alabama, Georgia, Kentucky,
Mississippi, North Carolina, South Carolina, and Tennessee to form its modeled Southeast
region for the purpose of assigning its assumed achievable renewable energy generation
requirement. Of that group, North Carolina is the only state that has a REPS requirement.
The FpSC appreciates the additional information regarding "Framework for Assessing Biogenic CO2 Emissions
from Stationary Sources," issued November 2014, as to how EPA intends to treat biomass generation, including
municipal solid waste options. 5ee hftp://www.epa.gov/climatechange/downloads/Framework-for-AssessingBiogenic-C02 -Emissions. pdf.
2
nlorida Department of Agriculture and Consumer Services, Division of Forestry, Iltoody Biomqss Economic Study,
'
March 10.2010.
IV. Transcript
Florida Public Service Commission
Internal Affairs
11/25/2014
1
BEFORE THE
FLORIDA PUBLIC SERVICE COMMISSION
1
2
3
4
5
6
PROCEEDINGS:
7
COMMISSIONERS
PARTICIPATING:
8
9
10
11
GRAHAM
RONALD A. BRISÉ
LISA POLAK EDGAR
EDUARDO E. BALBIS
JULIE I. BROWN
Tuesday, November 25, 2014
Commenced at 2:00 p.m.
Concluded at 2:37 p.m.
PLACE:
Gerald L. Gunter Building
Room 105
2540 Shumard Oak Boulevard
Tallahassee, Florida
REPORTED BY:
ANDREA KOMARIDIS, Court Reporter
14
15
CHAIRMAN ART
COMMISSIONER
COMMISSIONER
COMMISSIONER
COMMISSIONER
DATE:
TIME:
12
13
INTERNAL AFFAIRS
16
17
18
19
20
PREMIER REPORTING
114 W. 5TH AVENUE
TALLAHASSEE, FLORIDA
(850) 894-0828
21
22
23
24
25
Premier Reporting
Reported by: Andrea Komaridis
Florida Public Service Commission
Internal Affairs
P R O C E E D I N G S
1
2
11/25/2014
2
CHAIRMAN GRAHAM:
Guys, we're going to take up
3
Item No. 3 first, Lifeline, and then Item No. 2.
4
All right.
5
Let's get started with the Lifeline.
MS. BEARD:
Good afternoon, Commissioners.
6
Catherine Beard on behalf of staff.
7
addresses the draft 2014 Lifeline report prepared
8
pursuant to Section 364.10 Florida Statutes.
9
Item No. 3
The Commission is required by December 31st to
10
report to the Governor and Legislature on the
11
number of customers prescribing to Lifeline service
12
and the effectiveness of procedures to promote
13
participation in the program.
14
As of June 30th, 2014, the total Lifeline
15
enrollment in Florida was approximately 960,000
16
households, a 4.31 percent increase in enrollment
17
over the previous year.
18
19
Staff is requesting Commission approval to
submit this report.
20
CHAIRMAN GRAHAM:
21
or comments to staff?
Commissioners, any questions
22
Commissioner Brisé.
23
COMMISSIONER BRISÉ:
24
25
Premier Reporting
First, I wanted to move
approval of the report.
COMMISSIONER BROWN:
Second.
Reported by: Andrea Komaridis
Florida Public Service Commission
Internal Affairs
1
(Brief interruption.)
2
COMMISSIONER EDGAR:
11/25/2014
3
I couldn't carry
3
everything.
Nobody came to help me.
4
Bobby came.
I couldn't even open the doors.
5
(Laughter.)
6
CHAIRMAN GRAHAM:
7
reverse order.
8
items on the agenda.
9
10
11
12
And then
We decided to take it in
We're on No. 3, then two, then one,
COMMISSIONER EDGAR:
So, how many have you
already done?
COMMISSIONER BALBIS:
There is a motion on the
table.
13
(Laughter.)
14
COMMISSIONER BROWN:
15
CHAIRMAN GRAHAM:
There is, actually.
So, Commissioner Brisé moved
16
to approve the report for the Lifeline.
17
been seconded.
And it's
18
Further discussion, Commissioner Brisé.
19
COMMISSIONER BRISÉ:
Yeah.
I think it's an
20
accurate depiction of where our Lifeline program is
21
within the state.
22
many people who could qualify for the program
23
continue to seek to enroll.
24
25
Premier Reporting
And we certainly wish that as
CHAIRMAN GRAHAM:
Any other further discussion
on Lifeline?
Reported by: Andrea Komaridis
Florida Public Service Commission
Internal Affairs
1
Commissioner Balbis.
2
COMMISSIONER BALBIS:
11/25/2014
4
Thank you, Mr. Chairman.
3
I just want to confirm with the staff -- I know the
4
state has been recognized on our measures we've
5
used to prevent waste, fraud, and abuse in this
6
program.
7
is going and if we're still doing as good a job as
8
we have done, and can we do better?
9
Could you just briefly explain how that
MR. CASEY:
We're constantly monitoring the
10
amount of disbursements that are given to ETCs in
11
Florida.
12
anything that may be fraud, waste, and abuse.
13
We're constantly on the watch for
To get back to your point about Florida being
14
recognized, actually the FCC started U.S.F Strike
15
Force to prevent fraud, waste, and abuse.
16
first state they called was Florida and asked us to
17
set up a telephone call with the ETC group to
18
introduce themselves.
19
And the
And they are looking to work with us, the ETC
20
group, in all 50 states to prevent fraud, waste,
21
and abuse, and watch out for it and give them tips
22
if they need to do anything.
23
Of course, we have -- in the past years, we've
24
done a lot of things, put a few ETCs out of
25
business that were creating fraud, waste, and
Premier Reporting
Reported by: Andrea Komaridis
Florida Public Service Commission
Internal Affairs
1
abuse.
2
COMMISSIONER BALBIS:
3
CHAIRMAN GRAHAM:
4
11/25/2014
5
Okay.
Thank you.
Any further discussion?
Seeing none, all in favor, say aye.
5
(Chorus of ayes.)
6
CHAIRMAN GRAHAM:
Any opposed?
By your
7
action, you've approved the motion to approve
8
staff's recommendation on Lifeline.
Thank you very much.
9
10
MS. BEARD:
11
CHAIRMAN GRAHAM:
12
13
Thank you.
Item No. 2, ten-year site
plan.
And the reason why I did this is because we're
14
standing-room only.
15
spaces quicker, so people can start sitting down
16
for the longer piece of the agenda.
17
Please.
18
MR. ELLIS:
This way, we free up the
Good afternoon, Commissioners.
19
Item 2 is the draft review of the 2014 ten-year
20
site plan for Florida's electric utilities.
21
review is similar in format and content to last
22
year's review.
23
The
Regarding the statewide perspective, the three
24
notable items are retail and resales are below
25
their 2007 peak; natural gas is currently at
Premier Reporting
Reported by: Andrea Komaridis
Florida Public Service Commission
Internal Affairs
11/25/2014
6
1
60 percent of that energy for load; and the third
2
item is that 60 percent is before the clean power
3
plant.
4
that as of yet.
5
in in next year's review.
6
So, it does not include any impacts from
Those we expect to start trickling
On the utility side, only one utility was
7
especially notable.
8
includes a proposed generation-only reserve margins
9
of 10 percent.
10
FPL's 2014 ten-year site plan
That excludes incremental energy
efficiency.
11
At this time, FPL has not sought approval of
12
this metric, nor does it impact the timing of any
13
generation units.
14
opportunity to review this metric if it becomes a
15
controlling factor in a determination for need.
16
The Commission will have an
And lastly, it includes Appendix A, which is
17
comments from other state, regional, and local
18
government agencies, which include subjects such as
19
zoning, wildlife, water resources, dependence upon
20
natural gas, and renewables.
21
Staff at this time is aware of a series of
22
scrivener's errors associated with the list of
23
figures and tables in the individual header
24
numbers.
25
to make these corrections before the final version
Premier Reporting
Staff would seek administrative approval
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Florida Public Service Commission
Internal Affairs
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7
would be published.
If the Commission approves the draft with
2
3
these modifications, the review and the attached
4
comments would be submitted to DEP for
5
consideration in future proceedings, and at this
6
time, seeks the Commission's approval -- staff
7
seeks the Commission's approval for the draft
8
review and to find each utility site plan suitable.
Staff is available for any questions you may
9
10
have.
CHAIRMAN GRAHAM:
11
12
requested to speak, Stephanie from Sierra Club.
13
MS. KUNKEL:
14
CHAIRMAN GRAHAM:
15
16
We have one person that
Should I approach the table or -Right there -- no, you're
fine.
MS. KUNKEL:
Thank you.
Stephanie Kunkel on
17
behalf of Sierra Club of Florida.
18
opportunity to speak.
19
brief.
20
I appreciate the
I'll keep my comments very
We urge the Commission to require the
21
utilities to test the market and reconcile the
22
available and low-cost, low-risk clean power
23
sources with any decisions to add more conventional
24
power plants.
25
Premier Reporting
Although Florida certainly has the know-how to
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1
do this right, we offer the example of our
2
neighboring Georgia.
3
owned utility just completed a record procurement
4
that returned more than five gigawatts worth of
5
solar projects.
6
Georgia Power is seeking approval for more than the
7
required amount under the state's advanced solar
8
initiative.
9
That state's major investor-
The prices were so low that
Because the U.S. DOE's latest market research
10
shows that Florida is the least expensive market to
11
invest in solar rooftop systems, the question is
12
why aren't Florida utilities completing similar
13
solar procurements.
14
We're very excited to hear the push for
15
rooftop for solar in the last FECA hearing and
16
appreciate that, and look forward to working with
17
the Commission on that moving forward.
18
The Georgia Public Service Commission also
19
requires Georgia Power to issue a request for
20
information to test the wind market after the
21
successful 250-megawatt wind contract discussed
22
earlier.
23
All of the market trends suggest that Florida,
24
like Georgia, can access cost-effective wind power.
25
The utilities should be required to test the market
Premier Reporting
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Florida Public Service Commission
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9
and publicly report on the results.
We look forward to continuing to work with the
2
3
Commission on the ten-year site plans moving
4
forward and appreciate the opportunity to present
5
comments.
6
Thank you so much.
7
CHAIRMAN GRAHAM:
8
Commissioners.
9
Commissioner Brown.
10
COMMISSIONER BROWN:
Thank you.
Hi.
Thank you for
11
compiling this information.
12
management section -- are you going to make edits
13
to it pursuant to our vote?
MR. ELLIS:
14
15
16
17
18
19
20
The demand-side
We can do so, if that is your
wish.
COMMISSIONER BROWN:
Since it's not due until
December 31st.
MR. ELLIS:
We can definitely make those
edits.
COMMISSIONER BROWN:
Question on Page 16
21
regarding the table, Table 2 is the estimated
22
number of electric vehicles by service territory.
23
I'm actually very curious about this and know that
24
it's a growing industry.
25
Premier Reporting
I was just curious why TECO did not have
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1
available information for 2014 through 2023.
2
TECO wants to speak on it or if you have that
3
information --
4
MR. ELLIS:
If
I have that, but if they would
5
like to speak as well -- from my understanding,
6
they did not project any future -- they didn't have
7
a projection of what those values would be.
8
they did not provide it.
9
current-year value in the data request.
10
MS. BROWN:
11
any future use?
12
MR. ELLIS:
So,
But they did have a
So, do they anticipate not having
From my understanding, they just
13
did not have a projection of the specific number of
14
vehicles, whereas some of the other companies had
15
creative projections from that.
16
17
18
COMMISSIONER BROWN:
It doesn't look like
anybody wants to talk on it.
MR. SZELISTOWSKI:
Sure.
T.J. Szelistowski
19
with Tampa Electric.
20
could rely on.
21
something -- I don't know what the other utilities
22
relied on.
23
that we felt comfortable relying on to provide to
24
the Commission.
25
Premier Reporting
We didn't have anything we
We'll continue to look.
If we have
As we looked, we didn't have anything
We'll continue to look at that.
And as we
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1
have things that come up or we believe we can rely
2
those numbers, we'll provide that.
COMMISSIONER BROWN:
3
4
Great answer.
Thank you.
I appreciate it.
I also have a few modifications, stylistic,
5
6
grammatical, non-substantive changes, errors that I
7
would be glad to provide to you before --
8
MR. ELLIS:
9
those edits as well.
COMMISSIONER BROWN:
10
11
12
13
We can -- we can definitely make
here.
I won't go over them
Thanks.
CHAIRMAN GRAHAM:
Any other questions or
concerns for staff?
14
Can we get a motion to approve?
15
COMMISSIONER BROWN:
So moved.
16
COMMISSIONER BALBIS:
Second.
17
CHAIRMAN GRAHAM:
It's been moved and
18
seconded.
The motion also takes for you to make
19
those errors and bring that back before my office.
20
We won't be able to come back here.
21
will get one last look at it and make sure
22
everything is correct.
23
Everybody in favor say aye.
24
(Chorus of ayes.)
25
CHAIRMAN GRAHAM:
Premier Reporting
Any opposed?
But my office
By your
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actions, you approve the motion.
2
Okay.
3
musical chairs.
4
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Item No. 1.
MS. ORTEGA:
Thank you.
I apologize for the
I'm always a fan of saving the
5
best for last.
Good afternoon, Commissioners.
6
Ortega from staff with Ms. Cowdery and Mr. Breman
7
also from staff.
8
Item No. 1, staff is seeking approval --
9
CHAIRMAN GRAHAM:
10
11
12
13
Ana
Can you slide that mic over
a little bit?
MS. ORTEGA:
Sure.
Sure.
How is this?
Is
this better?
CHAIRMAN GRAHAM:
Yeah, that's fine.
I just
14
want to make sure everybody back in the back can
15
hear you.
16
17
18
MS. ORTEGA:
Yes, thank you.
I'll try to
speak a little louder.
Item No. 1, staff is seeking approval of the
19
draft comments to the EPA regarding the proposed
20
clean power plant.
21
with the EPA on Monday, December 1st.
22
Comments are due to be filed
At the internal affairs in September, the
23
Commission directed staff to draft comments that
24
focus on three particular concerns; the PSC's
25
jurisdiction, cost, and reliability.
Premier Reporting
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The attached comments incorporate those areas
1
2
as well as discuss areas of the best system of
3
emission reduction used by EPA to set those
4
standards for Florida, our request for recognition
5
of early actions, and the removal of an interim
6
performance requirement and technical corrections
7
to each of the building blocks.
Staff is available to answer any questions
8
9
that you have regarding the draft comments.
We
10
also note that we have draft language to change on
11
Page 17 that recognizes new information released by
12
EPA last week.
13
can talk about it, then.
And when it becomes appropriate, we
14
CHAIRMAN GRAHAM:
Commissioners.
15
Commissioner Balbis.
16
COMMISSIONER BALBIS:
Thank you.
And I want
17
to thank staff for putting this together.
18
it's a fairly accurate reflection of the comments
19
that we made in September.
20
also focuses on issues that we do have jurisdiction
21
over.
22
I think
And I think that it
And that's important because the Attorney
23
General's Office has issued their comments in
24
handling the strictly legal aspects and challenges
25
to the rule.
Premier Reporting
And I think it's important that each
Reported by: Andrea Komaridis
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1
agency in the state has their own specific area to
2
provide the information to EPA so that they can
3
revise this rule to something that's more that
4
achievable without as many impacts.
5
Of course, there are some -- not truly
6
grammatical issues.
Just things that, if I would
7
have written it, it would have come across a little
8
differently.
9
made and provided to staff they've incorporated it
But I think all the points that I
10
into it with the other Commissioners.
11
happy with the draft comments as they are, but will
12
be willing to hear from my colleagues on it, if
13
they have any other issues.
14
CHAIRMAN GRAHAM:
15
Commissioner Edgar.
16
COMMISSIONER EDGAR:
So, I'm
Commissioners?
Thank you, Mr. Chairman
17
and Commissioners.
18
but generally, I agree with Commissioner Balbis.
19
And I shared this with staff in our briefing
20
yesterday.
21
of bringing together so many issues.
22
touching on the points that we, in open meetings,
23
had discussed that we had concerns about and
24
thought should be addressed.
25
done an excellent job.
Premier Reporting
I might have one other issue,
I think they've done a really fine job
And I'm
I really think you've
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1
I did, in my briefing yesterday, point out a
2
couple of sentences that I thought were -- could,
3
perhaps, be clarified or reworded just to be a
4
little more straightforward.
5
mark all of them, but staff has that.
6
make our comments, I know that they'll take a look
7
at that as well.
8
9
And I didn't even
And as we
I've said this before, but I think it's
important to say, probably every time that we
10
discuss this issue, this is, I recognize, one step
11
in a much longer process.
12
EPA is -- if they have proposed a rule, they
13
have solicited comment.
14
have chosen as an agency to provide comments on
15
behalf of this Commission from our statutory
16
authority and those areas that we are charged with,
17
which fall under, again, the larger umbrella of
18
reliability and potential cost impact.
19
I am very glad that we
I recognize that some states have chosen to do
20
one state comment, but of course, every state is
21
organized somewhat differently.
22
instance, I think it's important that we speak from
23
our perspective on behalf of the ratepayers for,
24
again, potential cost impacts and reliability.
25
Premier Reporting
And in this
I also think that it's important to point out
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Florida Public Service Commission
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1
the obvious, which is, to participate by providing
2
comments during this part of the process, I do not
3
believe, forecloses or limits in any way other
4
routes, should we as an agency choose to go there
5
or, of course, other arms of the state as far as
6
legal challenges, clarifications, et cetera.
7
believe that they -- we can go on parallel
8
processes.
9
I do
And the Federal agency has asked for comments
10
as to potential disagreements, corrections, ways to
11
make it more implementable.
12
agency, I think it is our responsibility to
13
participate in that process.
14
that we are.
15
And as a government
So, I'm very pleased
The only issue -- and I mentioned this to
16
staff this morning, and we have not had the chance
17
to get back together -- is I don't believe we touch
18
at all on nuclear in these comments.
19
course, is part of the portfolio for Florida, not
20
for every state, but it is for us.
21
Nuclear, of
Implicit, if not explicit, in the proposed
22
language as it exists right now seems to be a
23
recognized reliance by EPA on nuclear as a way of
24
getting to lower emissions.
25
Premier Reporting
So, I had asked the staff to look at that this
Reported by: Andrea Komaridis
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1
morning and just see if there was a place to maybe
2
add a little language.
3
COMMISSIONER BROWN:
See (indicating).
4
COMMISSIONER EDGAR:
Oh, okay.
So, that's the
5
only issue I saw when we went through it that I
6
felt we had touched on that really wasn't really
7
included.
8
want to respond, that would be fine.
9
So, I'll toss that out.
MS. ORTEGA:
Sure.
10
COMMISSIONER EDGAR:
11
MS. ORTEGA:
And then if you
I did -- if I could -Sure.
-- briefly look a couple of
12
places in the document where we didn't explicitly
13
talk about nuclear because the impact of including
14
it in the goal was less than the impact of all the
15
other areas.
16
But there are a couple of places where we
17
noted the assumptions, a national or regional
18
assumptions being applied to Florida as being
19
inappropriate.
20
national assumption of nuclear at risk is another
21
area where it is not appropriate for Florida.
22
And the inclusion of the 6 percent
We could certainly, if it's a little
23
deficient, include some language in that section.
24
And also we do touch on the early actions --
25
Premier Reporting
COMMISSIONER BROWN:
That's what I was going
Reported by: Andrea Komaridis
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2
to suggest.
THE WITNESS:
-- that our utilities have taken
3
for nuclear upgrades.
4
areas that we could expand upon.
5
11/25/2014
18
So, there are certainly
COMMISSIONER EDGAR:
I would put that out for
6
our consideration and discussion as we come to
7
finalize the document.
8
9
CHAIRMAN GRAHAM:
should be pretty easy.
I have two things.
One
The other one, I guess, all
10
depends on where the Board sits.
11
didn't see in here -- maybe it is in here and I
12
just didn't read it.
13
participation in comments on this proposed rule
14
does not indicate agreement that EPA has the
15
authority to regulate greenhouse gas emissions from
16
existing power plants under Section 1.11(d).
17
MS. ORTEGA:
The first one I
I think one comment should be
We -- we briefly touched on that
18
at bottom of Page 4 leading into Page 5.
19
the last sentence.
20
contained herein are meant to request Florida-
21
specific considerations for application of the rule
22
and should not be constructed as support or
23
opposition to EPA's adopting carbon emission rules.
24
25
Premier Reporting
And it's
"The Commission's comments
If you would like us to tweak the language to
incorporate the jurisdiction, I think I heard in
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Florida Public Service Commission
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your comments, we can certainly do that.
COMMISSIONER BALBIS:
If I could make a
suggestion --
4
CHAIRMAN GRAHAM:
Sure.
5
COMMISSIONER BALBIS:
In reading the attorney
6
general's comments, they specifically had, I
7
believe, five or six legal-authority challenges, if
8
you will.
9
in our comments, it's our understanding they may
10
So, you may want to refer to those.
And
not have jurisdiction, et cetera.
11
I mean, what are your thoughts?
12
COMMISSIONER BROWN:
I say we do your work.
13
COMMISSIONER EDGAR:
Yeah, I don't --
14
personally, I support the attorney general doing
15
what the attorney general does, but for us to
16
reference specific petitions or pending other
17
litigation, I just --
18
COMMISSIONER BALBIS:
19
COMMISSIONER EDGAR:
20
21
Yeah, I guess --- don't know that that
needs to be here.
COMMISSIONER BALBIS:
My point isn't to refer
22
to the attorney general's comments, but if there
23
are questions to the EPA's authority that Chairman
24
Graham brought up, it may be helpful for staff to
25
look at what the attorney general is challenging as
Premier Reporting
Reported by: Andrea Komaridis
Florida Public Service Commission
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11/25/2014
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1
a reference -- not referencing their challenges
2
specifically.
COMMISSIONER EDGAR:
3
4
I'm sure staff will do
that.
5
MR. KISER:
Mr. Chairman?
6
CHAIRMAN GRAHAM:
Yes, sir.
I think it was
7
about two weeks ago we had the briefing.
8
Commissioner Brown, I know you were going to try to
9
be there.
10
11
And
And unfortunately, you had to be out of
town.
But one of the lead lawyers who will probably
12
be involved in litigating this on behalf of the
13
states -- the attorney general put together a
14
meeting of -- I guess, we had five or six people
15
from PSC.
16
lot of people from both Ag and from DEP.
17
We had the Attorney General's Office, a
And as he went through the vulnerability of
18
this carbon rule, I came away pretty impressed that
19
they are -- they really have some really solid
20
issues to challenge their authority on.
21
And if you look at the attorney general's
22
statement, really right in the very first two or
23
three pages, it outlines showing one, two, three,
24
four, five -- I think it's maybe six -- but the
25
very first one, for example, in my opinion is going
Premier Reporting
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Florida Public Service Commission
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11/25/2014
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to be a tough barrier to get over.
And we -- a lot of the discussion at that --
3
and it went for, like, an hour and a half.
The
4
briefing we had talked a lot about timing.
And one
5
of the comments the guy made was, you know, the
6
time period for comments.
7
really don't expect that to have any effect on what
8
their approach on the rule was.
9
very, very informative.
10
And he said, but we
And it was just
And you know, just like a blatant power grab
11
at Federal level to take over the whole energy
12
sector.
13
are trying to do and trampling on states' rights.
14
And it's very offensive to me what they
And it's -- but I do believe there will be
15
substantial amount of litigation.
16
probably looking at a couple of years before some
17
of this has any real effect, I would think.
18
MR. BAEZ:
So, we're
Mr. Chairman, I would only add that
19
as far as -- as far as I've been part of -- witness
20
to your conversations, the question of whether
21
we're going to engage in litigation on this or not
22
really hasn't come before you.
23
It's not that I'm recommending that we do or
24
that we don't, but it's something that you ought to
25
discuss, perhaps, not through what have become more
Premier Reporting
Reported by: Andrea Komaridis
Florida Public Service Commission
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11/25/2014
22
technical comments on the rule.
I think the Chairman's suggested language is
3
sort of a reservation of our rights.
4
that's a nice limit to have at this point for
5
purposes of these comments.
6
about how far you're going to take this and you
7
think right now is a proper time, then you should
8
have that conversation before you, you know, start
9
telling the EPA they don't have authority in these
10
11
comments.
And that's --
If you want to talk
They may --
CHAIRMAN GRAHAM:
Well, I think -- I think
12
what I said was not that we're -- just because
13
we're giving the comments, we're not saying that
14
you -- we're not blessing you --
15
MR. DIAS:
Understood.
You're reserving --
16
you know, as an agency, we're reserving our rights
17
to challenge and, otherwise, you know -- whatever
18
our legal rights are.
19
person's opinion.
20
reservation of our rights, but to -- to have this
21
turn into a legal paper is probably a step -- a
22
step further than -- at least that these comments
23
were intended to be.
I think it's just one
That's an appropriate
24
I mean, if that's the prism through which
25
we're looking at them, they are woefully short, you
Premier Reporting
Reported by: Andrea Komaridis
Florida Public Service Commission
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know.
2
COMMISSIONER EDGAR:
3
CHAIRMAN GRAHAM:
4
COMMISSIONER EDGAR:
Mr. Chairman, if I may.
Yes.
As I said, I think there
5
can be parallel tracks and different timelines.
6
And I think that's part of the process and will be
7
part of the process.
8
9
I do think that the statement that Ana pointed
out does cover the point that you have raised.
10
However, your language is a little stronger.
11
if you or others are more comfortable bolstering
12
that, I think it says the same thing, but I'm fine
13
with that language or, again, I think it is
14
covered.
15
There will be much litigation and for those of
16
us who -- for lawyers and for environmental
17
consultants and --
18
19
And
MR. KISER:
I need a job, now.
So, maybe we
can work something out.
20
(Laughter.)
21
COMMISSIONER EDGAR:
About environmental
22
policy and the creative tension between states and
23
the Federal Government -- it's going to be
24
Christmas.
25
really great issues.
Premier Reporting
And it's going to be a lot of really,
Reported by: Andrea Komaridis
Florida Public Service Commission
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24
I do think that any further discussion,
2
though, of particular legal positions is premature.
3
And it's not what this document is designed for.
4
And we'll see where those issues take us as --
5
MR. KISER:
Mr. Chairman --
6
CHAIRMAN GRAHAM:
7
I have one other comment that won't be as easy
I agree with you with that.
8
as the first one.
I don't know.
In this document,
9
in this draft, it has a lot of things that staff
10
does need to be Florida-specific.
11
plant-specific and Florida-specific.
12
They need to be
I guess the other comment I was looking for
13
because we basically don't take a position; we're
14
just making comments on what the EPA is trying to
15
do -- should we put something in there that if they
16
are not going to be Florida-specific, that we do
17
not support the proposed rule?
18
COMMISSIONER BALBIS:
I think that implies we
19
support the proposed rule if it is Florida-
20
specific.
21
MR. KISER:
22
CHAIRMAN GRAHAM:
23
MR. KISER:
24
CHAIRMAN GRAHAM:
25
MR. KISER:
Premier Reporting
Don't put yourself in a corner.
Okay.
Mr. Chairman?
Yes, sir.
May be of little help, too.
One
Reported by: Andrea Komaridis
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11/25/2014
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1
of the comments that was made at the meeting by the
2
lawyer that conducted the briefing is that really
3
nobody should do too much until the comment period
4
is over because technically, they still have the
5
opportunity to change it.
6
Now, he commented he didn't expect much -- any
7
change to any degree.
But in terms of doing too
8
much, we really kind of need to wait for the
9
comment period to run and then see what that
10
response is after that.
11
position to decide where you want to go and how.
12
CHAIRMAN GRAHAM:
And then we would be in a
Before we continue, do we
13
have Stephanie from Sierra Club wanting to speak to
14
this again?
15
MS. KUNKEL:
Yeah, I can just be very brief.
16
We know that this is going to be a very long
17
process and look forward to working with all of the
18
stakeholders on the state implementation plan as it
19
goes forward.
20
We just have some real technical concerns
21
dealing specifically with what we believe are key
22
inaccurate statements about clean power that deals
23
specifically with efficiency, solar, and wind.
24
25
Premier Reporting
On the efficiency section -- and I apologize,
I don't have the page number -- but the comments
Reported by: Andrea Komaridis
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Internal Affairs
11/25/2014
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1
say that the Florida Public Service Commission has
2
found that energy-efficiency programs capable of
3
achieving savings of 10 percent are not cost-
4
effective.
5
opinion, supporting market data.
6
But the comments do not cite, in our
It appears that staff is adopting the
7
utilities' assertions about what is and is not
8
cost-effective.
9
overwhelming market data and utility admissions
And staff does so despite
10
that you all have heard in the hearings.
11
Specifically FPL mentioned it in the FECA hearings
12
that Florida could save a lot more money by ramping
13
up utility energy-saving programs, instead of
14
cutting them back to make way for expensive risky
15
power plants.
16
On the issue of solar, staff proposes to lower
17
the renewables base portion of Florida's proposed
18
targets, but never substantiates that Florida's
19
solar market cannot meet or exceed the levels
20
proposed by EPA.
21
We just feel that the Public Service
22
Commission is simply not looking at the utilities
23
to rigorously and transparently explore our solar
24
market and add all of the cost-effective solar.
25
But again, we are excited to hear that that will be
Premier Reporting
Reported by: Andrea Komaridis
Florida Public Service Commission
Internal Affairs
1
2
11/25/2014
27
a workshop issue coming forward.
And then just lastly, on wind -- I know,
3
Commissioner Edgar, you had mentioned it
4
specifically.
5
Florida lacks viable wind resources without citing
6
any market data.
7
opposite is true.
8
9
In the comments, it says that
We feel that, actually, the
Florida has as much as 1500 megawatts of
onshore wind potential according to the National
10
Renewable Energy Laboratory.
11
access proven sheath out-of-state wind thanks to
12
transmission upgrades and wind procurement by
13
neighboring states such as Georgia.
14
Florida can also
Gulf Power, which is Gulf -- Georgia Power,
15
which is Gulf Power's sister subsidiary just
16
produced 250 megawatts of wind.
17
characterized that wind as an extraordinary
18
advantage for ratepayers and disclosed that the
19
price fell below the company's energy-cost
20
productions.
21
And Georgia Power
So, I'll just wrap by saying that we would
22
respectfully request that the Commission amend
23
staff comments prior to submission to EPA to
24
clarify some of the clean power issues that we've
25
raised.
Premier Reporting
Thank you so much.
Reported by: Andrea Komaridis
Florida Public Service Commission
Internal Affairs
1
CHAIRMAN GRAHAM:
2
Commissioner Edgar.
3
COMMISSIONER EDGAR:
11/25/2014
28
Thank you.
I'll just say very
4
briefly -- and I know Ana will jump in here -- and
5
I don't know page marked either.
6
sentence that she referenced was one of the ones
7
that I discussed with staff.
8
know what you're trying to say, but I felt like it
9
was a little unclear and asked them to consider
10
clarifying.
11
look at that section.
12
MS. ORTEGA:
But the specific
And I said I think I
So, I know they are taking another
Yes, it's on Page 19.
If I can,
13
the middle paragraph when we're speaking about
14
Building Block 4.
15
not saying exactly what really we intended it to
16
say.
17
aware, of looking at cost-effective
18
energy-efficiency programs.
And I apologize for the sentence
We have a framework in Florida, as we are all
19
And if we found the level of energy-efficiency
20
programs that EPA is assuming to be cost-effective,
21
we would have already been doing that level.
22
that was kind of what staff was trying to achieve
23
with this sentence.
24
25
Premier Reporting
And
But we're very open to changing it to reflect
the fact that our point being is that we have 20 -Reported by: Andrea Komaridis
Florida Public Service Commission
Internal Affairs
11/25/2014
29
1
32 years -- I think we started in '82 -- 32 years
2
of energy-efficiency data.
3
level to be cost-effective, we would.
If we had found that
4
The solar and the wind cites -- we can
5
certainly add additional information if it's the
6
will of the Commission to cite specific NREL -- the
7
National Energy Laboratory report that the Sierra
8
Club was referencing.
9
But again, we have a process in place that,
10
with our need determination, that if those options
11
are available to the utilities at the least cost,
12
then we would already be doing more of them.
13
14
COMMISSIONER EDGAR:
My own preference -- I'm
sorry --
15
COMMISSIONER BROWN:
It's okay.
16
COMMISSIONER EDGAR:
-- would be, as we had
17
discussed and as you have them describe in more
18
detail, to look at rewording.
19
as a non-substantive change, but a clarification
20
along the lines of energy efficiency.
21
think we need to reference any more studies.
22
MS. ORTEGA:
23
COMMISSIONER EDGAR:
24
25
Premier Reporting
And again, I see it
And I don't
Okay.
I think there will be
plenty of time for that down the road.
CHAIRMAN GRAHAM:
Any other comments or
Reported by: Andrea Komaridis
Florida Public Service Commission
Internal Affairs
1
11/25/2014
30
questions of staff?
2
Can I entertain a motion?
3
COMMISSIONER EDGAR:
Mr. Chairman, I would
4
move that we approve these comments with the
5
understanding that the staff make a few
6
adjustments, run a final through your office, as is
7
our general procedure.
8
to talk about --
9
MS. ORTEGA:
10
11
12
And also -- oh, do you want
Let me interrupt.
Yeah, I'm so
sorry.
COMMISSIONER EDGAR:
May I hold off on that?
I got ahead of myself.
13
MS. ORTEGA:
I apologize.
14
COMMISSIONER EDGAR:
There is additional
15
language that we discussed yesterday in response to
16
the most recent EPA --
17
CHAIRMAN GRAHAM:
18
MS. ORTEGA:
The biomass.
Yes, the biomass.
If I could
19
direct everybody's attention -- sorry -- to
20
Page 17.
21
you can look at.
22
If you want, I have some drafts typed up
So, currently, in our -- on Page 17, in the
23
Building Block 3 discussion, we refer to the lack
24
of information that EPA has given with the proposal
25
in June in regards to biomass.
Premier Reporting
Reported by: Andrea Komaridis
Florida Public Service Commission
Internal Affairs
1
11/25/2014
31
Last week, they released a framework about how
2
they will assess biomass.
3
definitive answer as to whether or not it's
4
emission -- CO2-emission neutral, it was a step in
5
the right direction.
6
Although, it wasn't a
So, staff has proposed, if accepted, a change
7
in the language that would essentially strike the
8
discussion of the lack of clarity on biomass and
9
insert a footnote recognizing that EPA has released
10
additional information in regards to that area.
11
CHAIRMAN GRAHAM:
Now what is your motion?
12
COMMISSIONER EDGAR:
Thank you.
Thank you,
13
Mr. Chairman.
14
comments directing staff to make the slight wording
15
changes per the discussion on the different issues
16
that we've had, compare them, run them through the
17
Chairman's office and then, at your sign-off,
18
submit them to EPA prior to the deadline.
19
20
Again, I move that we approve
CHAIRMAN GRAHAM:
moved and seconded.
The Edgar motion has been
Any further discussion?
21
Seeing none, all in favor, say aye.
22
(Chorus of ayes.)
23
Any opposed?
24
Thank you very much.
25
MS. ORTEGA:
Premier Reporting
By your actions, it is passed.
Thank you.
Reported by: Andrea Komaridis
Florida Public Service Commission
Internal Affairs
CHAIRMAN GRAHAM:
1
2
I think you guys did a lot
of good work this.
3
MS. ORTEGA:
4
CHAIRMAN GRAHAM:
5
11/25/2014
32
Thank you.
And it's really pretty
clear.
6
Okay.
Executive director's report.
7
MR. BAEZ:
8
CHAIRMAN GRAHAM:
9
MR. BAEZ:
No report today, Commissioner.
No report?
No, Mr. Chairman.
10
CHAIRMAN GRAHAM:
Other matters?
11
COMMISSIONER BALBIS:
Yes.
Mr. Chairman, I just
12
realized, that this, I believe -- do we have an IA
13
next month?
14
CHAIRMAN GRAHAM:
15
COMMISSIONER BALBIS:
16
comments.
17
last IA.
yet.
Well, then I'll save my
I was about to be excited to have my
COMMISSIONER EDGAR:
18
19
I think so.
Nope.
Nope.
Nope.
We're going to work you until the very end.
20
(Laughter.)
21
CHAIRMAN GRAHAM:
All right.
Well, if there
22
is no other matters coming up, we are now
23
adjourned.
24
25
Premier Reporting
Not
Everybody please travel safely.
(Whereupon, the proceedings were recessed at
2:37 p.m.)
Reported by: Andrea Komaridis
Florida Public Service Commission
Internal Affairs
CERTIFICATE OF REPORTER
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2
3
11/25/2014
33
STATE OF FLORIDA )
COUNTY OF LEON )
I, ANDREA KOMARIDIS, Professional Court
4
5
Reporter, do hereby certify that the foregoing
6
proceeding was heard at the time and place herein
7
stated.
IT IS FURTHER CERTIFIED that I
8
9
stenographically reported the said proceedings; that the
10
same has been transcribed under my direct supervision;
11
and that this transcript constitutes a true
12
transcription of my notes of said proceedings.
I FURTHER CERTIFY that I am not a relative,
13
14
employee, attorney or counsel of any of the parties, nor
15
am I a relative or employee of any of the parties'
16
attorney or counsel connected with the action, nor am I
17
financially interested in the action.
18
DATED THIS 4th day of December, 2014.
19
20
21
22
23
24
____________________________
ANDREA KOMARIDIS
NOTARY PUBLIC
COMMISSION #EE866180
EXPIRES FEBRUARY 09, 2017
25
Premier Reporting
Reported by: Andrea Komaridis
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