User manual | IA-10-24

I.
Meeting Packet
State of Florida
Public Service Commission
INTERNAL AFFAIRS AGENDA
Thursday, October 24, 2013
Immediately following Commission Conference
Room 105 - Gerald L. Gunter Building
1. Draft Status Update to the Federal Communications Commission (FCC) Regarding
the Limited Waiver of 47 C.F.R. §54.407(d), 47 C.F.R. §54.410(b)(2)(ii), 47 C.F.R.
§54.410(c)(2)(ii), and 47 C.F.R. §54.410(e) for the State of Florida, and Petition to
FCC for Permanent Waiver of FCC Rules 47 C.F.R. §54.407(d), 47 C.F.R.
§54.410(b)(2)(ii), 47 C.F.R. §54.410(c)(2)(ii), and 47 C.F.R. §54.410(e). Approval is
sought. (Attachment 1)
2. Staff’s Review of the 2013 Ten-Year Site Plan. Approval is sought. (Attachment 2)
3. Legislative Update. (No Attachment)
4. Executive Director’s Report. (No Attachment)
5. Other Matters. (No Attachment)
BB/mj
Attachment 1
Florida Public Service Commission
October 15, 2013
As the June 1, 2013 waiver period was expiring and no FCC action had been taken on
approving the Florida electronic enrollment program, the FPSC again contacted FCC staff and
asked if there was anything else the FPSC could do to expedite the approval. FCC staff
recommended the FPSC file a description of the Florida process through an Ex Parte filing in
FCC Docket No. 11-42. The FPSC prepared the requested description with screen shots of the
coordinated enrollment process and filed the documents on May 31, 2013, after notifying each
Commissioner’s office.
On August 30, 2013, the FCC released Order DA 13-1853 which extended the Waiver
period for California, Colorado, Florida, Idaho, Nebraska, Oregon, Utah, and Vermont until the
earlier of February 1, 2014, or once the state has come into compliance with the FCC’s rules, or
no longer requires a waiver because the ETCs in that state collect certification forms directly
from consumers. The Waiver Order states that “...no later than November 1, 2013, each state
still subject to this waiver must file a status update with the Bureau explaining the steps it has
taken to bring its processes into compliance, and, if applicable, why it is unable to come into
compliance by the end of the waiver period.” In addition, the Waiver Order states that “...if an
ETC or state believes that it will be unable to come into compliance and seeks a permanent
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 of printing out a hard-copy
Lifeline application. This advanced process involves a computer interface between the FPSC
and the Florida Department of Children and Families (DCF) for Lifeline applicants who
currently participate in Medicaid, the Supplemental Nutrition Assistance Program (SNAP), or
the Temporary Cash Assistance (TCA)3 program. The Florida process eliminates the need to
require or maintain hard-copy Lifeline certification applications.
Only Lifeline applicants who have been verified as currently participating in Medicaid,
SNAP, or the TCA program are approved through the Florida Lifeline Electronic Coordinated
Enrollment process.4 The DCF uses LexisNexis Risk Solutions to authenticate the identity of
people applying online for public assistance. The LexisNexis technology helps the DCF confirm
the identification of applicants before processing their benefit applications. By verifying and
authenticating the identity of the applicant before processing their application, DCF knows
whether the person seeking benefits is truly the individual applying for them.
Consumers already participating in Medicaid, SNAP, or TCA can also apply for Lifeline
on the FPSC website. The FPSC mainframe computer automatically conducts a real-time query
in the DCF computer to verify the applicant is currently participating in the program(s) checked
3
Nationally known as Temporary Assistance to Needy Families (TANF).
Applicants wishing to qualify for Lifeline using Supplemental Security Income, Federal Public Housing
Assistance, Low-Income Home Energy Assistance Program, National School Lunch Free Lunch Program, or Bureau
of Indian Affairs Programs can complete a hard-copy Lifeline application available on the FPSC Web site, and
submit it to their telephone provider along with verification that they are currently participating in one of these
programs.
4
2
Florida Public Service Commission
October 15, 2013
by the applicant. If the DCF computer response message confirms participation in a qualifying
Lifeline program, the FPSC computer automatically generates an e-mail to the appropriate ETC
that it has a Lifeline applicant’s information available for retrieval on the FPSC confidential
website. In addition to the Florida Lifeline Electronic Coordinated Enrollment process, a
computer interface is available for Florida ETCs to conduct a real-time query into DCF’s
database to determine if a Lifeline applicant is currently participating in Medicaid, SNAP, or the
TCA program.
FPSC staff believes that the FCC requirement to provide hard-copy certifications is
unnecessary, not cost effective, and would penalize Florida for having a Lifeline Electronic
Coordinated Enrollment process that is efficient and streamlined. Staff is seeking Commission
approval to file the attached status update and permanent waiver request by November 1, 2013.
cc:
Lisa Harvey
Curt Kiser
3
Florida Public Service Commission
WC Docket No. 11-42
October 24, 2013
INTRODUCTION AND SUMMARY
On February 6, 2012, the Federal Communications Commission (“FCC”) released a
Report and Order and Further Notice of Proposed Rulemaking (Order) regarding Lifeline and
Link Up Reform and Modernization (FCC 12-11).
The Order states that eligible
telecommunications carriers (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.5 The Order also requires 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 beginning June 1, 2012.6
Lifeline applicants in Florida have several options when applying for Lifeline.
A
consumer can apply directly to the Florida ETC. If consumers wish to use income criteria for
Lifeline qualification, they may apply for Lifeline through the Florida Office of Public Counsel
(OPC).7 A Florida consumer can request Lifeline when applying for Medicaid, Supplemental
Nutrition Assistance Program (SNAP), or Temporary Assistance to Needy Families (TANF) 8
through the Florida Department of Children and Families (DCF) which is the administrator of
those programs in Florida. The Florida Public Service Commission (FPSC) Lifeline Electronic
Coordinated Enrollment process with the DCF has been in place since 2007. Consumers already
participating in Medicaid, SNAP, or TANF can also apply for Lifeline on the FPSC website
which will confirm in real-time, participation in a Lifeline-qualifying DCF program, without
5
47 C.F.R. §54.407(d), 47 C.F.R. §54.410(b)(2)(ii), and 47 C.F.R. §54.410(c)(2)(ii).
47 C.F.R. §54.410(e).
7
Florida Statutes provide that the Florida Office of Public Counsel shall provide Lifeline applicant income criteria
certification for each local exchange telecommunications company that has more than one million access lines and
any wireless provider who elects to have OPC certify their income criteria applicants. See Section 364.10(2)(a),
Florida Statutes.
8
In Florida, TANF is known as Temporary Cash Assistance.
6
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WC Docket No. 11-42
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naming the particular program.9 Modifications have been made to the process over the years as
Lifeline requirements changed, including the attestations and certifications required by the
Lifeline Reform Order. The Florida Lifeline Electronic Coordinated Enrollment process does
not have the capability of printing out a hard-copy Lifeline application as required by FCC Rules
47 C.F.R. §54.407(d), 47 C.F.R. §54.410(b)(2)(ii), 47 C.F.R. §54.410(c)(2)(ii), and 47 C.F.R.
§54.410(e).
On April 25, 2012, the United States Telecom Association (US Telecom), without
consulting the FPSC, filed a Petition for Waiver of the hard-copy application requirement on
behalf of twenty states including Florida.10 On May 31, 2012, the FCC granted the US Telecom
Waiver until December 1, 2012, for eleven states, the District of Columbia, and the U.S. Virgin
Islands.11 On November 28, 2012, US Telecom filed another Waiver Request asking the FCC to
extend the Waiver period to June 1, 2013. On December 21, 2012, the FCC approved the US
Telecom Waiver extension until June 1, 2013, for seven states and the US Virgin Islands.12
On May 6, 2013, US Telecom requested another Waiver extension until December 1,
2013. On August 30, 2013, the FCC approved the US Telecom Waiver extension for eight states
including Florida, until the earlier of February 1, 2014, or once the state has come into
compliance with the FCC’s rules, or no longer requires a waiver because the ETCs in that state
9
Applicants wishing to qualify for Lifeline using Supplemental Security Income, Federal Public Housing
Assistance, Low-Income Home Energy Assistance Program, National School Lunch Free Lunch Program, or Bureau
of Indian Affairs Programs can complete a hard-copy Lifeline application available on the FPSC Web site, and
submit it to their telephone provider along with verification that they are currently participating in one of these
programs.
10
US Telecom also filed a Petition for Reconsideration and Clarification of the Lifeline Reform Order on April 2,
2012, which included in part, a request to reconsider the requirement of providing a copy of the Lifeline application
form to the ETC.
11
DA 12-863, Waiver Order for California, Colorado, District of Columbia, Florida, Idaho, Montana, Nebraska,
Nevada, Oregon, the U.S. Virgin Islands, Utah, Vermont, and Washington .
12
DA 12-2062, Waiver Order for the US Virgin Islands and the states of California, Colorado, Florida, Idaho,
Oregon, Utah, and Vermont.
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WC Docket No. 11-42
October 24, 2013
collect certification forms directly from consumers.13 The August 30, 2013 Waiver Order stated
that “...no later than November 1, 2013, each state still subject to this waiver must file a status
update with the Bureau explaining the steps it has taken to bring its processes into compliance,
and, if applicable, why it is unable to come into compliance by the end of the waiver period.” In
addition, the Waiver Order stated that “...if an ETC or state believes that it will be unable to
come into compliance and seeks a permanent waiver from the rules, it must provide in its request
for permanent relief an explanation for why such relief is appropriate.”
During these Waiver periods, the FPSC had numerous telephone conference calls with
FCC staff to describe the Florida Lifeline Electronic Coordinated Enrollment process and to
explain the reason why the Florida process meets the FCC requirements, and why the obligation
to provide hard-copy certifications of Lifeline applicants should not apply to Florida. As the
June 1, 2013 waiver period was expiring, the FPSC again contacted the FCC and inquired if
there was anything else the FPSC needed to do. The FCC recommended that the FPSC file a
description of the Florida process as an Ex Parte filing in Docket No. 11-42. The FPSC prepared
the requested description with screen shots of the Florida Lifeline Electronic Coordinated
Enrollment process and filed the documents in Docket No. 11-42 on May 31, 2013.14
STATUS UPDATE OF FEDERAL COMMUNICATIONS COMMISSION LIMITED
WAIVER OF 47 C.F.R. §54.407(d), 47 C.F.R. §54.410(b)(2)(ii), 47 C.F.R. §54.410(c)(2)(ii),
and 47 C.F.R. §54.410(e) FOR THE STATE OF FLORIDA
Florida has put in place a streamlined, efficient, and verifiable Lifeline Electronic
Coordinated Enrollment process that does not have the capability of printing out a hard-copy
Lifeline application.
13
14
The FPSC believes that the FCC requirement to provide hard-copy
DA 13-1853, Waiver Order for California, Colorado, Florida, Idaho, Nebraska, Oregon, Utah, and Vermont.
See http://apps.fcc.gov/ecfs/document/view?id=7022419940
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WC Docket No. 11-42
October 24, 2013
certifications is unnecessary in Florida, not cost effective, and would penalize Florida for using
Lifeline Electronic Coordinated Enrollment that is efficient and streamlined.
The Florida
Lifeline Electronic Coordinated Enrollment process allows ETCs to adhere to the requirements
of the Lifeline Reform Order without the need to require or maintain hard-copy Lifeline
certification applications.
The Florida Lifeline Electronic Coordinated Enrollment process was created to simplify
and streamline Lifeline enrollment and verify an applicant’s participation in Medicaid, SNAP, or
TANF. The FPSC believes that hard-copy documentation of a Lifeline applicant’s participation
in a qualifying program is not necessary when Florida’s Lifeline Electronic Coordinated
Enrollment process is used for initial program eligibility. A Florida ETC can easily make a note
in its records that the Florida Lifeline Electronic Coordinated Enrollment process was relied
upon to confirm a consumer’s initial eligibility for Lifeline, or the ETC could retain a copy of the
notification it receives from the FPSC when Lifeline applicants are verified and approved. The
FPSC believes that a permanent waiver of FCC Rules 47 C.F.R. §54.407(d), 47 C.F.R.
§54.410(b)(2)(ii), 47 C.F.R. §54.410(c)(2)(ii), and 47 C.F.R. §54.410(e) is necessary.
PETITION FOR PERMANENT WAIVER OF FEDERAL COMMUNICATIONS
COMMISSION RULES 47 C.F.R. §54.407(d), 47 C.F.R. §54.410(b)(2)(ii), 47 C.F.R.
§54.410(c)(2)(ii), and 47 C.F.R. §54.410(e)
The FPSC believes that the FCC requirements listed below are unnecessary, costprohibitive, and burdensome when the Florida Lifeline Electronic Coordinated Enrollment
Process is used for initial Lifeline enrollment. Therefore, the FPSC requests a Permanent Waiver
of the following FCC rules:
47 C.F.R. §407(d)
In order to receive universal service support reimbursement, an eligible
telecommunications carrier must certify, as part of each request for
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WC Docket No. 11-42
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reimbursement, that it is in compliance with all of the rules in this subpart, and, to
the extent required under this subpart, has obtained valid certification and recertification forms for each of the subscribers for whom it is seeking
reimbursement. (emphasis added)
47 C.F.R. §410(b)(2)(ii)
Where a state Lifeline administrator or other state agency is responsible for the
initial determination of a subscriber’s eligibility, an eligible telecommunications
carrier must not seek reimbursement for providing Lifeline service to a subscriber,
based on that subscriber’s income eligibility, unless the carrier has received from
the state Lifeline administrator or other state agency:
(i) Notice that the prospective subscriber meets the income-eligibility criteria set
forth in §§ 54.409(a)(1) or (a)(3); and
(ii) A copy of the subscriber’s certification that complies with the requirements set
forth in paragraph (d) of this section. (emphasis added)
47 C.F.R. §410(c)(2)(ii)
Where a state Lifeline administrator or other state agency is responsible for the
initial determination of a subscriber’s eligibility, when a prospective subscriber
seeks to qualify for Lifeline service using the program-based eligibility criteria
provided in §54.409, an eligible telecommunications carrier must not seek
reimbursement for providing Lifeline to a subscriber unless the carrier has
received from the state Lifeline administrator or other state agency:
(i) Notice that the subscriber meets the program-based eligibility criteria set forth
in §§ 54.409(a)(2), (a)(3) or (b); and
(ii) a copy of the subscriber’s certification that complies with the requirements set
forth in paragraph (d) of this section. (emphasis added)
47 C.F.R. §410(e)
State Lifeline administrators or other state agencies that are responsible for the
initial determination of a subscriber’s eligibility for Lifeline must provide each
eligible telecommunications carrier with a copy of each of the certification forms
collected by the state Lifeline administrator or other state agency from that
carrier’s subscribers. (emphasis added)
FPSC AND FLORIDA DEPARTMENT OF CHILDREN AND FAMILIES (DCF)
LIFELINE ELECTRONIC COORDINATED ENROLLMENT PROCESS
In 2010, the National Broadband Plan recommended that the FCC encourage state
agencies responsible for Lifeline and Link Up to streamline benefit enrollment and suggested the
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WC Docket No. 11-42
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use of unified online applications for social services. (FCC 12-11, ¶171) The Florida Lifeline
Electronic Coordinated Enrollment Process is consistent with the vision of the FCC. Florida
implemented a streamlined, efficient, and verifiable Lifeline Electronic Coordinated Enrollment
process to eliminate the possibility of fraud, waste, and abuse as was recommended in the
National Broadband Plan and mentioned in FCC Order 12-11.
The FCC’s March 4, 2011 Notice of Proposed Rulemaking also recommended use of a
coordinated enrollment process to improve administrative efficiency and protect and improve
program access. In this regard, the FCC stated:
We also seek comment on ways to reduce barriers to participation in the program
by service providers and low-income households, specifically through the use of
coordinated enrollment with other social service assistance programs and the
development of a national database that could be used for enrollment and
verification of ongoing eligibility. These proposals are intended to improve
administrative efficiency, improve service delivery, and protect and improve
program access for eligible beneficiaries. (FCC 11-32, ¶ 151)
Moreover, the FCC stated:
While we place limitations on how states’ automatic enrollment processes can be
utilized, we encourage coordinated enrollment and recognize coordinated
enrollment as a best practice in light of the overwhelming support in the record
and the benefits of coordinated enrollment (FCC 12-11, ¶174)
The FPSC has streamlined Florida Lifeline enrollment processes using current
technologies, and reduced paperwork burdens for the FPSC and ETCs, which embodies the
objectives mentioned in the Lifeline Reform Order.
A number of states currently engage in or are implementing coordinated
enrollment. For example, in 2007, Florida’s Department of Children and Families
(DCF) and the Florida Public Service Commission (FL PSC) established a
coordinated enrollment system in which applicants to three Lifeline eligible
programs (Food Stamps, Medicaid, and Temporary Assistance to Needy Families)
can also apply for Lifeline benefits at the same time.
When a consumer receiving benefits from DCF enrolls in one of these three DCF
programs online, the consumer is also presented with the option to enroll in
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Lifeline. If the consumer affirmatively enrolls in Lifeline, the consumer selects
an ETC from a list. The list of consumers and their ETC selections are sent to the
FL PSC. The FL PSC then sends each ETC the list of consumers who selected
that ETC as their Lifeline provider. (FCC 12-11 ¶175)
A Florida consumer applying for Medicaid, SNAP, or TANF must apply for the
assistance through the Florida DCF which is the administrator of those programs in Florida.
Included within the DCF’s application is a question asking whether the applicant wants to
receive a monthly discount on their phone service from the Florida Lifeline Assistance program.
If the applicants answer in the affirmative, they are asked if they presently have phone
service and if so, what their phone number is and whose name is on the monthly bill. They are
then asked to choose the name of their telephone provider from a drop-down menu which
appears with the names of all the Florida ETCs. If an applicant checks that they do not presently
have phone service but want to receive Lifeline Assistance, they are advised to contact their local
provider and sign up for telephone service. The application then lists all the attestations and
certifications required in the Lifeline Reform Order, and asks if the residential address listed on
the application is permanent or temporary. The applicants have to check whether they have read
and understand each of the attestations.
The DCF holds this information until a determination is made as to whether the applicant
becomes approved for Medicaid, SNAP, or TANF. Once an applicant has been approved for one
of these programs, and has indicated that he/she wants to participate in the Lifeline program, the
DCF computer automatically sends a message to the FPSC computer indicating this person has
been approved for a Lifeline qualifying program and has requested Lifeline Assistance.
The FPSC computer automatically queries the DCF message to retrieve the name of the
applicant’s ETC provider. The FPSC computer then generates an automatic message to the
appropriate ETC advising them that it has a Lifeline applicant’s information available for
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retrieval on the FPSC’s confidential website. The only time an ETC receives the message from
the FPSC is when an applicant has been certified that they participate in Medicaid, SNAP, or
TANF. The ETC can only view the Lifeline information of applicants who have applied to that
specific ETC through the coordinated enrollment process.
The ETC retrieves the Lifeline applicant’s information by logging in to the confidential
FPSC website to download the spreadsheet with the names, addresses and other information of
the applicants. In accordance with sections C.F.R. 54.410(b)(2)(i) and C.F.R. 54.410(c)(2)(i),
the confidential FPSC website includes a statement affirming “The subscribers herein have
complied with the Federal Communications Commission's (FCC) Lifeline eligibility
requirements and have executed a certification form as required by the FCC.” The spreadsheet
which the ETC downloads indicates whether the application was originated on the DCF website
or the FPSC (described below) website.
Only Lifeline applicants who have been verified as currently participating in Medicaid,
the SNAP, or the TANF program and who have had their identity verified by DCF are approved
through the Florida Lifeline Electronic Coordinated Enrollment process.
The DCF uses
LexisNexis Risk Solutions to authenticate the identity of people applying online for public
assistance. The LexisNexis technology helps the DCF confirm the identification of applicants
before processing their benefit applications. By verifying and authenticating the identity of the
applicant before processing his/her application, the DCF knows whether the person seeking
benefits is truly the individual applying for them.
By Florida Statute, ETCs have 60 days to place the applicant on Lifeline.15 By FPSC
rule, the ETC has to apply the Lifeline credit back to the date of the FPSC e-mail message sent to
15
See Section 364.10(1)(f), Florida Statutes.
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WC Docket No. 11-42
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them advising that an applicant has been approved for Lifeline. 16
Personal identifying
information of Lifeline applicants must be held confidential by Florida statute.17 However, the
statute provides that the applicant’s information may be released to the applicable ETC for
purposes directly connected with eligibility for, verification related to, or auditing of a Lifeline
Assistance Plan.
FPSC ON-LINE LIFELINE COORDINATED ENROLLMENT PROCESS
Consumers already participating in Medicaid, SNAP, or TANF can apply for Lifeline on
the FPSC website using English, Spanish, or Creole applications.18 The applicants provide their
name, address, telephone number, date of birth, and last four digits of their social security
number. They indicate whether their address is permanent or temporary, and whether they have
a different billing address. They select the name of their provider from a drop-down box listing
all Florida ETCs, and then indicate whether they are participating in Medicaid, SNAP, or TANF.
The application includes all the attestations and certifications required in the Lifeline Reform
Order.
Once the applicant agrees to the terms and conditions at the bottom of the application and
hits the submit button, the FPSC computer automatically conducts a real-time query in the DCF
computer to verify the applicant is actually participating in the program(s) checked by the
applicant. If the DCF computer response message confirms participation in a qualifying Lifeline
program (without naming the particular program), the FPSC computer automatically generates
an e-mail to the appropriate ETC that it has a Lifeline applicant’s information available for
retrieval on the FPSC confidential website. By Florida Statute, ETCs have 60 days to place the
16
See Rule 25-4.0665(10)(b), Florida Administrative Code.
See Section 364.107, Florida Statutes.
18
See https://secure.floridapsc.com/(S(ob1zlcip3q4efr45gkyhz255))/public/lifeline/lifelineapplication2.aspx.
17
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applicant on Lifeline.19 By FPSC rule, the ETC has to apply the Lifeline credit back to the date
of the FPSC e-mail message sent to them advising that an applicant has been approved for
Lifeline.20
If the DCF computer cannot verify current participation in the Lifeline qualifying
program, the FPSC generates a letter to the applicant notifying them that the FPSC could not
confirm participation in the Lifeline qualifying program they checked. The FPSC includes a
hard-copy Lifeline application with the letter along with a listing of all Florida ETCs and FPSC
telephone numbers if assistance is needed.
THE NATIONAL LIFELINE ACCOUNTABILITY DATABASE
The National Lifeline Accountability Database has been designed to help carriers identify
and resolve duplicate claims for Lifeline Program-supported service and prevent future
duplicates by conducting a nationwide real-time check if the consumer is already receiving a
Lifeline Program-supported service. 47 C.F.R. §54.404 (b)(6) requires the following information
for the database:
Eligible telecommunications carriers must transmit to the Database in a format
prescribed by the Administrator each new and existing Lifeline subscriber’s full
name; full residential address; date of birth and the 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.
The following information is provided to the ETC when a Lifeline applicant is approved through
the Florida PSC/DCF Coordinated enrollment Process: First Name; Last Name; Address 1;
19
20
See Section 364.10(1)(f), Florida Statutes.
See Rule 25-4.0665(10)(b), Florida Administrative Code.
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Address 2; City; Zip Code; Zip 4; State; Status (P or T) for permanent or temporary address;
Telephone number; Application date; Last 4 digits of Social Security Number; Agency (DCF or
FPSC); DOB; and, Qualifying Public Assistance Program(s) – this will include SNAP, Medicaid,
and/or TANF. Provision of this information allows the Florida Lifeline Electronic Coordinated
Enrollment process to make available all necessary information for Florida ETCs to comply with
the National Lifeline Accountability Database requirements in 47 C.F.R. §54.404 (b)(6).
DOCUMENTATION OF A LIFELINE APPLICANT’S PARTICIPATION IN A
QUALIFYING PROGRAM IS NOT NECESSARY WHEN FLORIDA’S LIFELINE
COORDINATED ENROLLMENT PROCESS IS USED FOR INITIAL PROGRAM
ELIGIBILITY.
The Florida Lifeline Electronic Coordinated Enrollment process uses three federal
programs (Medicaid, SNAP, and TANF) to verify a Lifeline applicant’s participation in a
Lifeline-qualifying program. The Lifeline Reform Order specifies that documentation of an
applicant’s participation in a qualifying federal program is not required when a state or federal
database such as in Florida is used to determine eligibility. Specifically, paragraph 98 of the
Lifeline Reform Order provides that:
Where ETCs access state or federal databases to make determinations about
consumer eligibility for Lifeline, we do not require ETCs to obtain from a new
subscriber documentation of his or her participation in a qualifying federal
program. The ETC or its representative must note in its records what specific
data was relied upon to confirm the consumer’s initial eligibility for Lifeline (e.g.,
name of a state database.) This rule will reduce administrative burdens on ETCs
by allowing them to leverage existing systems and processes. In states where the
ETC is not responsible for the initial determination of consumer eligibility, a state
agency or third-party administrator, as applicable, may query the database in lieu
of the ETC doing so.
Because the Florida Lifeline Electronic Coordinated Enrollment uses the DCF database using the
same vetted information as DCF, the same documentation requirements should apply. The
Florida Lifeline Electronic Coordinated Enrollment process was created to streamline Lifeline
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enrollment and verify an applicant’s participation in Medicaid, SNAP, or TANF. The FPSC
believes that hard-copy documentation of a Lifeline applicant’s participation in a qualifying
program is not necessary when Florida’s Lifeline Electronic Coordinated Enrollment process is
used for initial program eligibility. All applicant information was verified by DCF through their
benefits enrollment process. A Florida ETC can easily make a note in its records that the Florida
Lifeline Electronic Coordinated Enrollment process was relied upon to confirm a consumer’s
initial eligibility for Lifeline, or the ETC could retain a copy of the notification it receives from
the FPSC when Lifeline applicants are verified and approved.
GOOD CAUSE EXISTS TO GRANT A PERMANENT WAIVER OF FCC RULES 47
C.F.R. §54.407(d), 47 C.F.R. §54.410(b)(2)(ii), 47 C.F.R. §54.410(c)(2)(ii), and 47 C.F.R.
§54.410(e)
The FCC may waive its rules for good cause shown. 47 C.F.R. §1.3 provides the
following:
The provisions of this chapter may be suspended, revoked, amended, or waived
for good cause shown, in whole or in part, at any time by the Commission, subject
to the provisions of the Administrative Procedure Act and the provisions of this
chapter. Any provision of the rules may be waived by the Commission on its own
motion or on petition if good cause therefor is shown.
Good cause includes the existence of particular facts that make strict compliance with the rule
inconsistent with the public interest.21 The FCC may also take into account considerations of
hardship, equity, or more effective implementation of public policy on an individual basis.22
Requiring hard-copy signed applications/certifications would present an economic
hardship on the FPSC, the DCF, and the Florida ETCs, and may not even be possible with
Florida’s streamlined Lifeline Electronic Coordinated Enrollment process which averaged
21
Northeast Cellular Telephone Com. v. FCC, 897 F.2d 1164,1166 (D.C. Cir. 1990).
WAIT Radio v. FCC, 418 F.2d 1153, 1159 (D.C. Cir. 1969), cert. denied 409 U.S. 1027 (1972); Northeast
Cellular Telephone Com. v. FCC at 1166.
22
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receiving over 9,000 Lifeline applications/month for the first eight months of 2013. The Lifeline
application is embedded within the DCF application for assistance and cannot be retrieved and
printed. Changing the present coordinated enrollment process would be cost-prohibitive and
time consuming. The FPSC and the DCF have limited resources and fixed budgets dedicated to
the administration of the Lifeline program. The Florida DCF also has many other programs
which they administer including Adult Protective Services, Child Care, Domestic Violence,
TANF, SNAP, Medicaid, Child Welfare, Homelessness, Refugee Services, and
Substance
Abuse and Mental Health. The Lifeline coordinated enrollment program is only one small part
of their overall mission, and it took a number of years to create a process within the DCF
application for consumers to request Lifeline and make all the required attestations and
certifications. Any changes would be extremely costly, time consuming, and place additional
administrative burdens on the FPSC, the DCF, and the Florida ETCs.
Requiring hard-copy
application certifications to ETCs does nothing to enhance the validity of the subscriber's
eligibility when the Florida Lifeline Electronic Coordinated Enrollment process is used. It would
be extremely difficult if not impossible to isolate the required certification and application
information, create images of these documents and provide them to the relevant ETC.
Granting a permanent waiver of these rules would also be in the public interest. The
present Florida Lifeline Electronic Coordinated Enrollment process provides easy access for
consumers, and verifies in real time whether an applicant is currently participating in Medicaid,
SNAP, or TANF.23
Florida households are presently the number one recipients of SNAP
benefits in the United States with 1,952,890 households receiving SNAP benefits in June,
23
Florida has an estimated 929,200 participants in Lifeline as of August 2013, according to the USAC disbursement
database.
17
Florida Public Service Commission
WC Docket No. 11-42
October 24, 2013
2013.24 Over 74 percent of Lifeline applicants use the SNAP program to qualify for Lifeline
when using the Florida Lifeline Electronic Coordinated Enrollment process. The FPSC has
streamlined Lifeline enrollment processes using current technologies, and reduced paperwork
burdens for the FPSC, the DCF, and ETCs which embodies the objectives mentioned in the
Lifeline Reform Order.
CONCLUSION
The FPSC believes the FCC’s efforts to comprehensively reform and modernize the
Lifeline program substantially strengthens protections against waste, fraud, and abuse in the
Lifeline program and will limit the growth of the program to reduce the burden on all who
contribute to the Universal Service Fund. As a net contributor, Florida contributed $535 million
to the Universal Service Fund and received $245 million in 2011.25
The Florida PSC has been recognized by the FCC as being at the forefront of eliminating
fraud, waste, and abuse in the universal service program.
Florida was one of two states
personally commended by FCC Chairman Julius Genachowski for formidable efforts to identify
and eliminate fraud in the Lifeline Assistance program.
In his December 12, 2011 letter,
Chairman Genachowski praised the states’ efforts to end any potential fraud in the Universal
Service Fund, specifically recognizing actions by Florida and Wisconsin, and also urged state
commissions to join the FCC’s national effort “to reform the Lifeline program…and to take swift
and strong action when necessary to protect the program.”
Florida has put in place a streamlined, efficient, and verifiable Lifeline Electronic
Coordinated Enrollment process that does not have the capability of printing out a hard-copy
24
25
United States Department of Agriculture SNAP program data. http://www.fns.usda.gov/pd/SNAPmain.htm
2012 Universal Service Monitoring Report.
18
Florida Public Service Commission
WC Docket No. 11-42
October 24, 2013
Lifeline application. The Florida Lifeline Electronic Coordinated Enrollment process allows
ETCs to adhere to the requirements of the Lifeline Reform Order without the need to require or
maintain hard-copy Lifeline certification applications.
The FPSC believes that a Permanent Waiver for Florida of FCC Rules 47 C.F.R.
§54.407(d), 47 C.F.R. §54.410(b)(2)(ii), 47 C.F.R. §54.410(c)(2)(ii), and 47 C.F.R. §54.410(e) is
appropriate since there are special circumstances which warrant a deviation from the these rules,
and such deviation will serve the public interest. The FPSC believes that the FCC requirement to
provide hard-copy certifications is unnecessary in Florida, not cost effective, and would penalize
Florida’s Lifeline Electronic Coordinated Enrollment process for being efficient and streamlined.
The FPSC encourages the FCC to consider the facts noted in this petition and grant Florida a
permanent waiver of these rules.
DATED: October 24. 2013
Respectfully submitted,
/s/
Adam J. Teitzman, Attorney Supervisor
Office of the General Counsel
FLORIDA PUBLIC SERVICE COMMISSION
2540 Shumard Oak Boulevard
Tallahassee, Florida 32399-0850
(850) 413-6082
19
Attachment 2
DRAFT
Review Of The
2013 Ten-Year Site Plans
For Florida’s Electric Utilities
Florida Public Service Commission
Tallahassee, FL
October 2013
Table of Contents
Table of Contents ..............................................................................................................................i
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 Ten-Year Site Plans ............................................................................................. 1
Future Commission Actions ....................................................................................................... 4
Conclusion .................................................................................................................................. 5
Introduction ................................................................................................................................... 6
Statutory Authority ..................................................................................................................... 6
Information Sources for the Report ............................................................................................ 7
Structure of the Report ................................................................................................................ 8
Conclusions ................................................................................................................................. 8
Statewide Perspective ................................................................................................................... 9
Load and Energy Forecast ......................................................................................................... 10
Florida’s Electricity Customer Composition ............................................................................ 10
Growth in Customer Base and Consumption............................................................................ 11
Seasonal Peak Demand Forecast............................................................................................... 11
Impact of Electric Vehicles....................................................................................................... 13
Demand Side Management ....................................................................................................... 15
Florida Energy Efficiency and Conservation Act ..................................................................... 15
Demand Side Management Programs....................................................................................... 16
Projected Peak Demand & Energy Usage................................................................................. 17
Accuracy of Energy Forecasts .................................................................................................. 19
Renewable Generation................................................................................................................ 21
Existing Renewable Resources ................................................................................................. 21
Non-Utility Renewable Generation .......................................................................................... 22
Utility Owned Renewable Generation ...................................................................................... 22
Customer Owned Renewable Generation ................................................................................. 23
Planned Renewable Additions .................................................................................................. 24
Renewable Outlook................................................................................................................... 25
Traditional Generation............................................................................................................... 26
Existing Generation Resources ................................................................................................. 26
Impact of EPA Regulations ...................................................................................................... 27
Modernization and Efficiency Improvements........................................................................... 28
Planned Retirements ................................................................................................................. 29
Reserve Margin Requirements.................................................................................................. 30
2013 Ten-Year Site Plan Review
Page i
New Generation Resources ....................................................................................................... 32
Fuel Price Forecasts .................................................................................................................. 33
Fuel Diversity............................................................................................................................ 34
Projected New Units by Fuel Type ........................................................................................... 37
Power Plant Siting Act .............................................................................................................. 38
Transmission Capacity .............................................................................................................. 39
Utility Pe rspectives...................................................................................................................... 40
Florida Powe r & Light Company (FPL) .................................................................................. 41
Load and Energy Forecast......................................................................................................... 41
Generation Resources ............................................................................................................... 43
Duke Energy Florida, Inc. (DEF) .............................................................................................. 45
Load and Energy Forecast......................................................................................................... 45
Generation Resources ............................................................................................................... 47
Tampa Electric Company (TECO) ........................................................................................... 49
Load and Energy Forecast......................................................................................................... 49
Generation Resources ............................................................................................................... 51
Gulf Powe r Company (GPC) ..................................................................................................... 53
Load and Energy Forecast......................................................................................................... 53
Generation Resources ............................................................................................................... 55
Florida Municipal Powe r Agency (FMPA)............................................................................... 57
Load and Energy Forecast......................................................................................................... 57
Generation Resources ............................................................................................................... 59
Gainesville Regional Utilities (GRU)......................................................................................... 61
Load and Energy Forecast......................................................................................................... 61
Generation Resources ............................................................................................................... 63
JEA ............................................................................................................................................... 65
Load and Energy Forecast......................................................................................................... 65
Generation Resources ............................................................................................................... 67
Lakeland Electric (LAK)............................................................................................................ 69
Load and Energy Forecast......................................................................................................... 69
Generation Resources ............................................................................................................... 71
Orlando Utilities Commission (OUC) ....................................................................................... 73
Load and Energy Forecast......................................................................................................... 73
Generation Resources ............................................................................................................... 75
Seminole Electric Cooperative (SEC) ....................................................................................... 77
Load and Energy Forecast......................................................................................................... 77
Generation Resources ............................................................................................................... 79
City of Tallahassee Utilities (TAL) ............................................................................................ 81
Load and Energy Forecast......................................................................................................... 81
Generation Resources ............................................................................................................... 83
2013 Ten-Year Site Plan Review
Page ii
List of Figures
Statewide Perspective
Figure 1: State of Florida - Customer and Retail Energy Sale Growth Since 2003 ....................... 2
Figure 3: State of Florida - Natural Gas Usage (History & Forecast) ............................................ 3
Figure 2: State of Florida - Installed Capacity (Existing & Projected)........................................... 4
Figure 4: TYSP Utilities - Share of State Net Energy for Load ..................................................... 7
Figure 5: State of Florida - Number of Customers and Energy Usage by Class .......................... 10
Figure 6: State of Florida - Customer and Retail Energy Sale Growth Since 2003 ..................... 11
Figure 7: State of Florida - Daily Load Curve Example............................................................... 12
Figure 8: Generating IOUs - 2012 Daily Peak as a Percent of Annual Peak Demand ................. 13
Figure 9: State of Florida - Seasonal Peak Demand and Annual Energy Consumption............... 18
Figure 10: State of Florida - Generation Capacity Additions by Fuel Type and Decade ............. 26
Figure 11: State of Florida - Seasonal Reserve Margin (Summer & Winter) .............................. 31
Figure 12: State of Florida - Installed Capacity (Existing & Projected)....................................... 33
Figure 13: TYSP Utilities - Fuel Prices (History & Forecast) ...................................................... 34
Figure 14: State of Florida - Natural Gas Usage (History & Forecast) ........................................ 34
Figure 15: State of Florida - Fuel Diversity (History & Forecast) ............................................... 35
Utility Perspectives
Figure 16: FPL - Number of Customers and Energy Usage by Class .......................................... 41
Figure 17: FPL - Customer and Retail Energy Sale Growth Since 2003 ..................................... 41
Figure 18: FPL - Seasonal Peak Demand and Annual Energy Consumption............................... 42
Figure 19: FPL - Fuel Diversity (History & Forecast) ................................................................. 43
Figure 20: FPL - Seasonal Reserve Margin (Summer & Winter) ................................................ 44
Figure 21: DEF - Number of Customers and Energy Usage by Class.......................................... 45
Figure 22: DEF - Customer and Retail Energy Sale Growth Since 2003..................................... 45
Figure 23: DEF - Seasonal Peak Demand and Annual Energy Consumption .............................. 46
Figure 24: DEF - Fuel Diversity (History & Forecast) ................................................................. 47
Figure 25: DEF - Seasonal Reserve Margin (Summer & Winter) ................................................ 48
Figure 26: TECO - Number of Customers and Energy Usage by Class....................................... 49
Figure 27: TECO - Customer and Retail Energy Sale Growth Since 2003 .................................. 49
Figure 28: TECO - Seasonal Peak Demand and Annual Energy Consumption ........................... 50
Figure 29: TECO - Fuel Diversity (History & Forecast) .............................................................. 51
Figure 30: TECO - Seasonal Reserve Margin (Summer & Winter) ............................................. 52
Figure 31: GPC - Number of Customers and Energy Usage by Class ......................................... 53
Figure 32: GPC - Customer and Retail Energy Sale Growth Since 2003 .................................... 53
Figure 33: GPC - Seasonal Peak Demand and Annual Energy Consumption.............................. 54
Figure 34: GPC - Fuel Diversity (History & Forecast)................................................................. 55
2013 Ten-Year Site Plan Review
Page iii
Utility Perspectives (Continued)
Figure 35: GPC - Seasonal Reserve Margin (Summer & Winter)................................................ 56
Figure 36: FMPA - Number of Customers and Energy Usage by Class ...................................... 57
Figure 37: FMPA - Customer and Retail Energy Sale Growth Since 2003 ................................. 57
Figure 38: FMPA - Seasonal Peak Demand and Annual Energy Consumption........................... 58
Figure 39: FMPA - Fuel Diversity (History & Forecast) ............................................................. 59
Figure 40: FMPA - Seasonal Reserve Margin (Summer & Winter) ............................................ 60
Figure 41: GRU - Number of Customers and Energy Usage by Class......................................... 61
Figure 42: GRU - Customer and Retail Energy Sale Growth Since 2003 .................................... 61
Figure 43: GRU - Seasonal Peak Demand and Annual Energy Consumption ............................. 62
Figure 44: GRU - Fuel Diversity (History & Forecast) ................................................................ 63
Figure 45: GRU - Seasonal Reserve Margin (Summer & Winter) ............................................... 64
Figure 46: JEA - Number of Customers and Energy Usage by Class .......................................... 65
Figure 47: JEA - Customer and Retail Energy Sale Growth Since 2003 ..................................... 65
Figure 48: JEA - Seasonal Peak Demand and Annual Energy Consumption............................... 66
Figure 49: JEA - Fuel Diversity (History & Forecast) ................................................................. 67
Figure 50: JEA - Seasonal Reserve Margin (Summer & Winter) ................................................ 68
Figure 51: LAK - Number of Customers and Energy Usage by Class ......................................... 69
Figure 52: LAK - Customer and Retail Energy Sale Growth Since 2003 .................................... 69
Figure 53: LAK - Seasonal Peak Demand and Annual Energy Consumption ............................. 70
Figure 54: LAK - Fuel Diversity (History & Forecast) ................................................................ 71
Figure 55: LAK - Seasonal Reserve Margin (Summer & Winter) ............................................... 72
Figure 56: OUC - Number of Customers and Energy Usage by Class......................................... 73
Figure 57: OUC - Customer and Retail Energy Sale Growth Since 2003 .................................... 73
Figure 58: OUC - Seasonal Peak Demand and Annual Energy Consumption ............................. 74
Figure 59: OUC - Fuel Diversity (History & Forecast) ................................................................ 75
Figure 60: OUC - Seasonal Reserve Margin (Summer & Winter) ............................................... 76
Figure 61: SEC - Number of Customers and Energy Usage by Class .......................................... 77
Figure 62: SEC - Customer and Retail Energy Sale Growth Since 2003 ..................................... 77
Figure 63: SEC - Seasonal Peak Demand and Annual Energy Consumption .............................. 78
Figure 64: SEC - Fuel Diversity (History & Forecast) ................................................................. 79
Figure 65: SEC - Seasonal Reserve Margin (Summer & Winter) ................................................ 80
Figure 66: TAL - Number of Customers and Energy Usage by Class ......................................... 81
Figure 67: TAL - Customer and Retail Energy Sale Growth Since 2003 .................................... 81
Figure 68: TAL - Seasonal Peak Demand and Annual Energy Consumption.............................. 82
Figure 69: TAL - Fuel Diversity (History & Forecast)................................................................. 83
Figure 70: TAL - Seasonal Reserve Margin (Summer & Winter)................................................ 84
2013 Ten-Year Site Plan Review
Page iv
List of Tables
Statewide Perspective
Table 1: State of Florida - Proposed Generation Requiring Commission Approval ...................... 5
Table 2: State of Florida - Plug- in EVs Registered in Florida (2008 - 2013)............................... 14
Table 3: TYSP Utilities - Estimates of the Number of Plug-In EVs by Service Territory ........... 14
Table 4: TYSP Utilities - Estimates for EV Annual Energy Consumption (GWh)...................... 15
Table 5: TYSP Utilities - Accuracy of Retail Energy Sales Forecasts ......................................... 19
Table 6: TYSP Utilities - Accuracy of Retail Energy Sales Forecasts - Annual Analysis ........... 20
Table 7: State of Florida - Existing Renewable Resources........................................................... 21
Table 8: Renewable Generation Interconnections ....................................................................... 23
Table 9: State of Florida - Planned Renewable Resource Additions ............................................ 24
Table 10: State of Florida - List of Planned Renewable Firm Capacity ....................................... 24
Table 11: TYSP Utilities - Cost Estimates of EPA Rule Compliance (2013-2022)..................... 28
Table 12: TYSP Utilities - Planned Unit Retirements .................................................................. 30
Table 13: TYSP Utilities - Nuclear Unit Additions ...................................................................... 37
Table 14: TYSP Utilities - Natural Gas Unit Additions ............................................................... 38
Table 15: State of Florida - Proposed Generation Requiring Commission Approval .................. 39
Table 16: TYSP Utilities - Transmission Requiring TLSA Approval.......................................... 39
Utility Perspectives
Table 17: FPL - Planned Generation Additions............................................................................ 43
Table 18: DEF - Planned Generation Additions ........................................................................... 47
Table 19: TECO - Planned Generation Additions ........................................................................ 51
Table 20: GPC - Planned Generation Additions ........................................................................... 55
Table 21: SEC - Planned Generation Additions ........................................................................... 79
Table 22: TAL - Planned Generation Additions ........................................................................... 83
2013 Ten-Year Site Plan Review
Page v
List of Ten-Year Site Plan Utilities
Investor-Owned Electric Utilities
FPL
Florida Power & Light Company
DEF
Duke Energy Florida, Inc. (formerly Progress Energy Florida, Inc.)
TECO
Tampa Electric Company
GPC
Gulf Power Company
Municipal Electric Utilities & Rural Electric Cooperatives
FMPA
Florida Municipal Power Agency
GRU
Gainesville Regional Utilities
JEA
JEA (formerly Jacksonville Electric Authority)
LAK
Lakeland Electric
OUC
Orlando Utilities Commission
SEC
Seminole Electric Cooperative
TAL
City of Tallahassee Utilities
2013 Ten-Year Site Plan Review
Page vi
List of Acronyms
AB
CC
CR3
CT
DACS
DEP
DR
DSM
EIA
EPA
F.A.C.
F.S.
FEECA
FRCC
GWh
IC
IGCC
IL
IOU
LM
MMBtu
MSW
MW
NEL
NUC
NUG
OBS
PPSA
QF
RPS
SACE
ST
TLSA
TYSP
WDS
Agricultural Byproducts (Biomass)
Combined Cycle
Crystal River Unit 3 (Nuclear)
Combustion Turbine
Department of Agriculture and Consumer Services
Department of Environmental Protection
Demand Response
Demand-Side Management
Energy Information Administration
Environmental Protection Agency
Florida Administrative Code
Florida Statutes
Florida Energy Efficiency & Conservation Act
Florida Reliability Coordinating Council
Gigawatt-hour
Internal Combustion Generator
Integrated Gasification Combined Cycle
Interruptible Load
Investor-Owned Utility
Load Management
Million British Thermal Units
Municipal Solid Waste
Megawatt
Net Energy for Load
Nuclear Generation
Non-Utility Generator
Other Biomass Solids (Biomass)
Power Plant Siting Act
Qualifying Facilities
Renewable Portfolio Standard
Southern Alliance for Clean Energy
Steam Generator
Transmission Line Siting Act
Ten-Year Site Plan
Wood Waste Solids (Biomass)
2013 Ten-Year Site Plan Review
Page 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 TYSPs 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 2013 TYSPs for Florida’s electric utilities, filed by eleven reporting utilities. 1
All findings of the Commission are made available to the Department of Environmental
Protection (DEP) for its consideration at any subsequent electrical power plant site certification
proceedings pursuant to the Power Plant Siting Act (PPSA). 2 In addition, this document is
forwarded to the Department of Agriculture and Consumer Services (DACS) pursuant to Section
377.703(2)(e), F.S., which requires the Commission to provide a report on electricity and natural
gas forecasts. A copy of this report is also posted on the Commission’s website and is available
to the public.
Review of the Ten-Year Site Plans
Load & Demand Forecasting
The first step in any resource planning process is to focus on the efficient use of
electricity by consumers.
Government mandates, such as building codes and appliance
efficiency standards, provide the starting point for increasing energy efficiency.
Customer
choice is the next step in reducing the state’s need for electricity. Consequently, educating
consumers to make smart energy choices is particularly important.
Florida’s utilities can efficiently serve their customers by offering demand-side
management (DSM) and conservation programs designed to use fewer resources at lower cost.
Under the Florida Energy Efficiency and Conservation Act (FEECA), the Commission is
required to establish annual numeric goals for seasonal peak demand and annual energy
consumption reductions. 3 The Commission has already begun the next goal-setting proceeding,
which will be completed by the end of 2014.
Florida’s utilities project considerable demand and energy savings over the planning
period, with conservation and load management programs by 2022 reducing the system’s total
summer peak demand by over 9,200 megawatts (MW), and annual energy consumption by over
1
Investor-owned utilities (IOUs) filing 2013 TYSPs include Florida Power & Light Company (FPL), Duke Energy
Florida, Inc. (DEF) which filed under its previous name, Progress Energy Florida, Inc., Tampa Electric Company
(TECO), and Gulf Power Company (GPC). Municipal utilities filing 2013 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 2013 TYSP.
2
The Power Plant Siting Act is Sections 403.501 through 403.518, Florida Statutes
3
Sections 366.80 through 366.85 and Section 403.519, F.S.
2013 Ten-Year Site Plan Review
Page 1
Executive Summary
14,500 gigawatt-hours (GWh). Including these reductions, Florida is forecasted to experience by
2022 a net firm summer peak demand of 51,552 MW and annual net energy for load of 270,797
GWh.
Over the last ten years, the total number of electric customers in Florida has increased by
11.4 percent. Primarily this growth took place between 2003 and 2007, before the recession,
after which customer growth plateaued, with the annual average growth rate dropping from 2.5
percent to a tenth of that figure, at 0.2 percent, including two years of slight negative growth.
Forecasts estimate a higher rate of growth over the next ten years, at an annual average of 1.2
percent, below the average rate before the recession.
By comparison, retail energy sales in 2012 have only increased 0.6 percent over the past
ten years. Retail energy sales followed a similar growth pattern as customer growth before 2007,
but experienced an overall decline since the 2007 peak. Forecasts for energy sales also estimate
a growth, at an annual average rate of 1.4 percent. This rate is also below the growth rate
experienced before the recession, but is slightly higher than customer growth. Retail energy
sales are anticipated to exceed the 2007 peak by 2016. Figure 1 details these trends below for
number of customers and retail energy sales.
Figure 1: State of Florida - Customer and Retail Energy Sale Growth Since 2003
Source: 2013 FRCC Regional Load & Resource Plan
Renewable Generation
Renewable resources continue to expand in Florida, with approximately 1,470 MW of
renewable generation currently operating in Florida. Presently, municipal solid waste (MSW)
and biomass each represent roughly a third of renewable generation in Florida. Other major
types of renewable generation operating in the state include waste heat, hydroelectric, landfill
gas, and solar.
2013 Ten-Year Site Plan Review
Page 2
Executive Summary
Over the planning horizon, approximately 966 MW of additional renewable generation is
planned in Florida. The majority of these additions are solar and biomass. 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 on fossil
fuels.
Traditional Generation
Natural gas is anticipated to remain the dominant fuel over the planning horizon, with
usage in 2012 increasing to 64.8 percent of the state’s net energy for load (NEL), up from 57.7
percent of NEL in 2011. Figure 2 below illustrates the increasing use of natural gas as a
generating fuel for the electricity production during the last ten years, and the projected use
during the next decade. State-wide, natural gas usage is expected to decline slightly from its
current peak, to 58.8 percent in 2022. This is due to projected increases in nuclear generation,
and a limited impact of new environmental compliance requirements.
Figure 2: State of Florida - Natural Gas Usage (History & Forecast)
Source: 2013 FRCC Regional Load & Resource Plan
Generating capacity within the State of Florida is anticipated to grow to meet the increase
in customer demand, with approximately 9,960 megawatts (MW) of new utility-owned
generation added over the planning horizon. This figure represents an increase from last year’s
TYSPs, which estimated the need for about 7,200 MW new generation. Based on the 2013 TenYear 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 gasfired generating units make up a majority of the generation additions and now represent a
majority of capacity within the state. Retirements primarily consist of oil-fired and coal-fired
steam generation, in addition to DEF’s Crystal River Unit 3 (CR3), one of the five existing
nuclear units in Florida.
2013 Ten-Year Site Plan Review
Page 3
Executive Summary
Figure 3: State of Florida - Installed Capacity (Existing & Projected)
Source: 2013 TYSPs, 2013 FRCC Regional Load & Resource Plan
Future Commission Actions
Florida’s electric utilities must also consider environmental concerns associated with
existing 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 will
have an impact on Florida’s existing generation fleet, as well as on its proposed new facilities.
These EPA rules will limit allowable emissions from new and existing power plants for a
variety of pollutants, including mercury, other heavy metals, organic toxics, particulates, sulfur
oxides, and nitrogen oxides. While many facilities within the state already have sufficient
emissions control technologies to comply with these rules, some will require installation of new
equipment to bring generators into compliance. Other rules address concerns relating to cooling
water’s impact on aquatic life and the disposal of coal ash. All of these activities will require new
investment and the potential for extended outages of some generating units, which will require
careful planning to minimize any impact on system reliability.
2013 Ten-Year Site Plan Review
Page 4
Executive Summary
At this time, GPC’s coal-fired Plant Scholz and DEF’s Crystal River units 1 and 2 are the
only plants anticipated to be retired as a result of any of these regulations. Additionally, DEF’s
Suwanee River Units 1-3, which can use either residual oil or natural gas, will cease residual oil
operations in order to comply with the MATS rule. Several of the TYSP utilities have provided
preliminary estimates based upon known and proposed rule language, and with a range between
$2.4 and $5.5 billion, which may not encompass all associated potential costs.
As noted previously, the primary purpose of this review of the utilities’ TYSPs is to
provide information regarding new electric power plants to the DEP for its use in the
certification process. Table 1 displays those generation facilities included in the 2012 TYSPs
that have not yet received a certification under the PPSA by the Commission. Certification is
generally anticipated at four years in advance of the in-service date for a natural gas-fired
combined cycle unit.
Table 1: State of Florida - Proposed Generation Requiring Commission Approval
Utility
Generating Unit Name
DEF
Unnamed CC
DEF
Unnamed CC
SEC
Unnamed CC
SEC
Unnamed CC
Source: 2013 TYSPs
1
2
1
2
Summer
Capacity
(MW)
1,189
1,189
192
192
In-Service
Date
06/2018
06/2020
12/2020
12/2020
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.
Conclusion
The Commission has reviewed the 2013 TYSPs filed by the eleven reporting utilities, as
well as supplemental data provided through data requests, 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 Commission
does continue to monitor the increased dependence on natural gas for electricity production, and
the impact of this reduction in fuel diversity on the state. While low prices for natural gas have
made it the dominant fuel, its history of price volatility raises the specter of increased costs
should there be disruptions in natural gas production, supply, or markets.
Based on its review, the Commission finds the 2013 TYSPs filed by the reporting
utilities, augmented with supplemental data provided, to be suitable for planning purposes. Since
the TYSP is 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
TYSP at a public hearing.
2013 Ten-Year Site Plan Review
Page 5
Introduction
The Ten-Year Site Plans (TYSPs or 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. Because the TYSPs are considered to be planning
documents and can contain tentative data, they may not necessarily contain sufficient
information to allow regional planning councils, water management districts, and other
reviewing agencies to evaluate site-specific issues within their respective jurisdictions. Each
utility is responsible for providing detailed information based on individual assessments during
certification proceedings under the Power Plant Siting Act (PPSA), Sections 403.501-403.518,
Florida Statutes (F.S.), or the Transmission Line Siting Act (TLSA), Sections 403.52-403.5365,
F.S.
In addition, other regulatory processes may require utilities to provide additional
information as needed.
Statutory Authority
Section 186.801, F.S., requires that all major generating electric utilities submit a TYSP
to the Commission for annual review. Section 377.703(2)(e), F.S., requires the Commission to
analyze these plans and provide natural gas and electricity forecasts to the Department of
Agriculture and Consumer Services (DACS). The Commission has adopted Rules 25-22.070
through 25-22.072, Florida Administrative Code (F.A.C.) in order to fulfill these statutory
requirements.
Florida is served by 58 electric utilities, including 5 investor-owned utilities (IOUs), 35
municipal utilities, and 18 rural electric cooperatives. 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 TYSP, at least once every two years. In 2013,
eleven utilities filed TYSPs, including 4 IOUs, 6 municipal utilities, and 1 rural electric
cooperative. 4
Figure 4 below illustrates each TYSP utility’s representative share of the state’s net
energy for load for 2012. In total, the investor-owned TYSP utilities represent 78 percent of net
energy for load (NEL). Those utilities which are not required to file a TYSP make up the
approximately 1 percent of the state’s NEL.
4
IOUs filing 2013 TYSPs include Florida Power & Light Company (FPL), Duke Energy Florida, Inc. (DEF) which
filed under its previous name, Progress Energy Florida, Inc., Tampa Electric Company (TECO), and Gulf Power
Company (GPC). Municipal utilities filing 2013 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 2013 TYSP.
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Introduction
Figure 4: TYSP Utilities - Share of State Net Energy for Load
Source: 2013 TYSPs, 2013 FRCC Load & Resource Plan
As outlined in the Commission’s rules, each utility’s TYSP contains projections of the
utility’s electric power needs, fuel requirements, and general location of proposed power plant
sites and major transmission facilities. The utilities provide historic and projected information
on existing generating capacity, customer base and energy usage, impact of demand-side
management, fuel consumption, fuel diversity, anticipated reserve margin, and proposed new
generating units and transmission.
In accordance with Section 186.801, F.S., the Commission performs a preliminary study
of each TYSP and makes a determination as to whether it is suitable or unsuitable. This
determination is non-binding, and is made in recognition that the information provided is
tentative, and is subject to change by the utility upon written notice. The results of the
Commission’s study are contained in this report, Review of the 2013 Ten-Year Site Plans, and
are forwarded to the DEP for use in subsequent power plant siting proceedings.
Information Sources for the Report
Contained in each utility’s TYSP is a series of required tables which provide detailed
information on a number of items. This information, supplemented by additional data requests,
provides the basis of the Commission’s review.
The Florida Reliability Coordinating Council (FRCC) is also an important source of
information for the Commission’s review. Each year, the FRCC publishes its Regional Load and
Resource Plan which contains aggregate data on demand and energy, capacity and reserves, and
proposed new generating units and transmission line additions, both for Peninsular Florida and
for the state as a whole. The primary focus of the FRCC is the reliability of the electrical system
for Peninsular Florida.
In addition to its 2013 Regional Load and Resource Plan, the
Commission used the FRCC’s 2013 Reliability Assessment as a resource in the production of this
review. The Commission held a public workshop on September 25, 2013, to facilitate discussion
of the annual planning process and the Regional Load & Resource Plan and to allow for public
comments on the TYSPs that were filed with the Commission. In addition to the FRCC, the
2013 Ten-Year Site Plan Review
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Introduction
Sierra Club, also representing Earthjustice, and Southern Alliance for Clean Energy (SACE)
made presentations at the workshop.
Energy Conservation was the primary topic, with
discussion on various changes in building codes, increased customer education, and utility
programs reviewed by the Commission. Both the Sierra Club and SACE were aware of the
Commission’s open dockets to review utility energy conservation goals later next year.
Structure of the Report
This report is divided into multiple sections. The Statewide perspective provides a look
at the impact of all planned unit additions to the State as a whole, and is intended as a resource
for those seeking an understanding of Florida’s energy systems. Individual utility reports focus
on the issues facing each electric utility and its unique situation. Lastly, Appendix A contains
comments received from various review agencies, local governments, and others that have been
collected and included in this report.
Conclusions
As discussed in each of the individual utility’s reviews, the Commission’s review of the
eleven reporting utilities’ 2013 TYSPs finds them all suitable for planning purposes. Through
the review process, the Commission has determined that the projections of load growth appear
reasonable, and that reporting utilities have identified sufficient additional generation facilities to
maintain an adequate supply of electricity at a reasonable cost.
Since
classification
determination
any concerns
the TYSP is not a binding plan of action for electric utilities, the Commission’s
of these Plans as suitable or unsuitable does not constitute a finding or
in any docketed matters before the Commission. The Commission may address
raised by a utility’s TYSP at a public hearing.
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Load and Energy Forecast
Statewide Perspective
2013 Ten-Year Site Plan Review
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Load and Energy Forecast
Forecasting load growth is the first component of system planning for Florida’s electric
utilities. In order to maintain a reliable system, utilities must stay abreast of changes in customer
base as well as trends in demand and energy consumption. Utilities perform load and energy
forecasts to estimate the amount and timing of future capacity needs, taking into consideration
the number and type of customers served, changes in customer usage patterns, impacts of
mandated energy efficiency standards, new technologies, and demand-side management (DSM)
programs.
Historical data forms the foundation for utility load and energy forecasts. These sets of
data include energy usage patterns, trends in population growth, economic variables, and weather
data for each utility’s service territory. Econometric forecast models are then used to quantify
the historical impact of population growth, economic conditions, and weather on energy usage
patterns.
Finally, sets of forecast assumptions on future population growth, economic conditions,
and weather are assembled and together with the forecast models, yield the final demand and
energy forecasts. Each utility’s peak demand and energy forecasts serve as a starting point for
determining if and when new capacity additions are needed to reliably and efficiently serve the
anticipated load.
Florida’s Electricity Customer Composition
Florida is dominated by residential electric customers, which make up a majority in both
number of customers and retail energy sales, as shown in Figure 5 below. While commercial and
industrial customers may be lower in number, they consume far more per customer, and
combined represent the other half of energy consumed in Florida.
Figure 5: State of Florida - Number of Customers and Energy Usage by Class
Source: 2013 FRCC Regional Load & Resource Plan
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Load and Energy Forecast
Growth in Customer Base and Consumption
Florida traditionally has been a high growth state, with significant annual increases in
both customers and retail energy sales. The impact of the financial crisis changed these
tendencies, with customer growth plateauing and retail energy sales declining from their 2007
peak, with an annual increase only in 2010, associated with extreme winter weather. Over the
last ten years, Florida has experienced a growth in customers of 11.36 percent, but retail energy
sales in 2012 were only 0.65 percent higher than 2003. These trends are illustrated in Figure 6
below.
Figure 6: State of Florida - Customer and Retail Energy Sale Growth Since 2003
Source: 2013 FRCC Regional Load & Resource Plan
Customer growth and usage is projected to increase throughout the planning period,
although at a slower pace than at the beginning of the last decade, with retail energy sales
expected to exceed its 2007 peak by 2016. This is primarily based on assumptions of population
growth and improving economic indicators. The current gap between number of customers and
retail energy sales is projected throughout the planning period.
Seasonal Peak Demand Forecast
Since there exists no economically feasible means to store electricity at the grid-scale,
electric utilities must supply electricity near instantaneously to the time of its consumption. For
a majority of the time, system demand is significantly less than the daily peak. However, system
peak demand determines the timing of new generation needs, and is driven by seasonal weather
patterns. With a growing customer base dominated by residential customers, both the rate of
growth and usage patterns are important considerations in planning sufficient future generation
to meet the state’s projected customer load.
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Load and Energy Forecast
Figure 7 illustrates typical daily load curves for each season, which shows evidence of
the influence of residential customers. In summer, air-conditioning demand causes a steady
climb in the morning and a peak in early evening, before declining into the evening. In contrast,
winter’s demand curve is dominated by electric heating and water heating, causing a rapid peak
in mid-morning and a second peak in the late evening.
Figure 7: State of Florida - Daily Load Curve Example
Source: TYSP Utilities Data Response
Florida is typically a summer-peaking state, meaning that the summer peak demand
generally controls the amount of generation required. While winter peak demands tend to be
greater than summer, the higher peak is offset by the increased winter rating of power plants,
which can take advantage of lower ambient air and water temperatures to produce more
electricity from the same generating unit. During summer peak demand, higher temperatures
instead can decrease generation, as high water temperatures may reduce not only the quality, but
quantity of cooling water available based on environmental permits.
As with daily load, there is a great variation in seasonal peak load. Figure 8 below
illustrates this for 2012, showing daily peak demand as a percentage of the annual peak. As
demonstrated in the figure, winter peaks tend to be shorter duration events, while Florida’s
summer season has longer periods of high peak demands. The periods between the seasonal
peaks are referred to as “shoulder months,” and utilities take advantage of these periods of
relatively low demand to perform maintenance without impacting their ability to meet the daily
peak demand.
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Load and Energy Forecast
Figure 8: Generating IOUs - 2012 Daily Peak as a Percent of Annual Peak Demand
Source: 2013 TYSP Utilities Data Response
In general, a major controlling factor to seasonal peak demand is short-term weather
conditions. While utilities forecast annual peak demand based upon historic factors, customer
counts, and normalized weather patterns, utilities also continuously monitor weather conditions
in their service territory and prepare for any increases (or decreases) in customer demand. By
closely monitoring the weather situation, utilities can fine tune maintenance schedules to ensure
the highest unit availability during the utility’s peak demand.
Impact of Electric Vehicles
The FPSC also continues to examine the effects of plug-in electric vehicles (EVs) on the
electric grid. EVs include any vehicles that draw some or all of their energy from the electric
grid, as opposed to hybrid electric vehicles which, while conserving some energy through the
braking process, still rely entirely on gasoline or diesel for their energy.
At present, Florida Department of Highway Safety and Motor Vehicles (FHSMV) data
indicates that there were approximately 3,818 plug-in EVs registered in Florida as of May 1,
2013, with an additional 861 low-speed vehicles (such as electric golf carts and other
neighborhood electric vehicles) registered. 5 Since the FHSMV reports 18.8 million vehicles of
all types registered in Florida as of August 2013, EVs are still only approximately 0.025 percent
of that total. Table 2 shows the growth in the registrations of plug-in EVs since 2008, the year
the first modern EV, the Tesla Roadster, was made available.
5
FHSMV provides VIN data to Polk Consulting, who decode VINs in order to establish make and model. The
numbers include all electric-only vehicles, as well as the Chevy Volt, a plug-in hybrid. The statistics do not
differentiate clearly between other plug-in hybrid vehicles and gasoline-only hybrids, but these data should capture
most of the plug-in vehicles registered in the state of Florida.
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Load and Energy Forecast
Table 2: State of Florida - Plug-in EVs Registered in Florida (2008 - 2013)
Vehicle Category
2008
Plug-in EVs
2009
2010
2011
2012
2013*
Total
1
37
31
465
1,868
1,416
3,818
Low-Speed Vehicles
237
176
92
121
137
98
861
Total
238
213
123
586
2,005
1,514
4,679
* Through May 1, 2013.
Source: Polk Consulting, FHSMV.
Table 3 shows TYSP utilities’ projections of the number of EVs in their service territories
through 2022. While these numbers are presently limited, utilities project them to rise sharply
over the next ten years, to a total of 315,958 by 2022. Even if that figure is reached, however, it
would still represent less than 2 percent of projected vehicle registrations in Florida in 2022.
Table 3: TYSP Utilities - Estimates of the Number of Plug-In EVs by Service Territory
Utility
Year
FPL
DEF
2012
2,020
238
2013
5,006
1,054
2014
9,669
2015
16,413
2016
TECO
176
GPC
JEA
OUC
TAL
Total
169
9
537
16
3,165
NA
685
12
1,030
32
7,819
2,361
NA
1,344
20
1,624
58
15,076
4,045
NA
2,119
38
2,689
98
25,402
25,490
6,274
NA
3,015
214
4,037
157
39,187
2017
39,461
9,500
NA
3,998
431
5,685
235
59,310
2018
53,896
13,816
NA
5,141
651
7,646
329
67,663
2019
72,139
19,337
NA
6,447
876
9,937
461
109,197
2020
107,352
26,204
NA
7,921
1,104
12,574
645
155,800
2021
159,439
34,576
NA
9,566
2,006
15,570
838
221,995
11,248
2,924
18,859
1,048
315,958
2022
236,695
45,184
NA
Source: TYSP Utilities Data Response.
Table 4 shows the total projected energy consumption of the TYSP utilities associated
with EVs during the same time frame. While the additional consumption is quite modest at
present, utilities project it growing to almost 2,000 GWh in 2022.
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Load and Energy Forecast
Table 4: TYSP Utilities - Estimates for EV Annual Energy Consumption (GWh)
EV Contribution to Annual Energy Consumption (GWh)
Year
FPL
DEF
TECO
GPC
JEA
OUC
TAL
Total
2012
13
1.3
NA
0.7
0.0
0.2
5
20
2013
31
5.2
NA
2.8
0.1
0.5
11
51
2014
62
10.7
NA
5.5
0.2
1.0
19
98
2015
110
16.8
NA
8.7
0.4
1.6
33
171
2016
173
23.7
NA
12.4
2.3
2.4
53
267
2017
261
32.2
NA
16.4
4.8
3.4
79
397
2018
358
43.6
NA
21.1
7.6
4.6
111
546
2019
480
58.0
NA
26.5
10.8
6.0
155
736
2020
688
75.7
NA
32.5
14.2
7.5
218
1,036
2021
984
97.0
NA
39.3
26.9
9.3
283
1,440
2022
1,408
122.8
NA
46.2
40.9
11.3
354
1,983
Sources: TYSP Utilities Data Response
The effect these additional EVs will have on peak system demand is more difficult to
determine. Due to numerous uncertainties regarding EV deployment, including at what times
they will be charged and the possibility that EV charging may be shifted away from peak if
necessary, most TYSP utilities were unable to project EVs effects at system peak. TYSP utilities
did not report any current reliability or safety issues resulting from EVs, nor any needed system
upgrades necessitated by EV deployment. As EV deployment moves forward, the effects of EVs
on system peak should become clearer.
Demand Side Management
The first step in any resource planning process is to focus on the efficient use of
electricity by consumers.
Government mandates, such as building codes and appliance
efficiency standards, provide the starting point for increasing energy efficiency.
Customer
choice is the next step in reducing the state’s dependence upon expensive fuels and lowering
greenhouse gas emissions. Consequently, educating consumers to make smart energy choices is
particularly important.
Finally, Florida’s utilities can efficiently serve their customers by
offering DSM and conservation programs designed to use fewer resources at lower cost.
Florida Energy Efficiency and Conservation Act
The Florida Legislature directed the Commission to encourage utilities to decrease the
growth in seasonal peak demand and energy consumption in Sections 366.80 through 366.85 and
Section 403.519, F.S., known as the Florida Energy Efficiency and Conservation Act (FEECA).
Under FEECA, the Commission is required to set goals for demand and energy reduction for 7
electric utilities, namely the 5 investor-owned electric utilities (including Florida Public Utility
2013 Ten-Year Site Plan Review
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Load and Energy Forecast
Company, which is a non-generating utility and therefore does not file a TYSP) and 2 municipal
electric utilities (JEA and OUC). 6 These utilities represent 86 percent of sales in Florida.
The seven FEECA utilities currently offer DSM programs to residential, commercial, and
industrial programs. Energy audit programs provide a first step for utilities and customers to
evaluate conservation opportunities and serve as the foundation for other programs.
The last annual demand and energy goal-setting proceeding was completed in December
of 2009, providing annual goals for the period of 2010 through 2020. To meet the requirement
to set goals at least once every five years, the Commission must establish annual goals for the
2015 through 2025 period by the end of 2014. The Commission already established dockets for
each of the seven FEECA Utilities in July 2013, with hearing dates set for July 2014, and a final
decision by the Commission expected by October 2014.
Demand Side Management Programs
DSM Programs generally fall into three categories: interruptible or curtailable load (IL),
load management (LM), and conservation. The first two are generally considered dispatchable,
and are referred to as Demand Response (DR), meaning that the utility can call upon them during
a period of peak demand, but otherwise they are not in active use. In contrast, conservation
measures are considered passive and are always working to reduce customer demand and energy
consumption.
Interruptible or curtailable load is achieved through the use of agreements with large
customers to allow the utility to interrupt selected portions of the customer’s load during periods
of peak demand. Interrupted or curtailed customers could make up for this generation by
reducing their own industrial processes or by activating back-up generation. In exchange for the
ability to reduce their electrical load, the utility usually offers such customers a discounted rate
for energy or other credits which are paid for by all customers.
Load management programs involve the installation of a device that can interrupt a
customer’s appliance(s) for a short duration during a period of peak demand. These interruptions
tend to have less notice than those provided to interruptible customers, and generally do not fully
disconnect customers, but interrupt an individual appliance. Normally, interruptions are kept to
short periods and are cycled between groups of customers. Due to the nature of the program,
certain devices would be more appropriate to handle different seasonal demands. For example,
air conditioning units would be interrupted to reduce a summer peak, while water heaters being
interrupted may contribute more towards reducing a winter peak. As of 2013, over 3,145 MW of
interruptible load and load management is available for summer peak, and is anticipated to
expand to 3,618 MW by 2022.
In addition to active measures, customer-based conservation measures can have an
impact on peak demand without requiring activation by the utility. These passive conservation
measures typically involve improving a home or business’ building envelope, such as greater
insulation and energy-efficient windows, or installing more efficient appliances. These energy
efficiency improvements decrease the customer’s load at all times without requiring an
6
Sections 366.82(1)(a), F.S.
2013 Ten-Year Site Plan Review
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Load and Energy Forecast
interruption or reduction in service, and also have an impact on annual energy consumption. As
of 2013, over 3,592 MW of cumulative conservation for summer peak demand has been
installed, increasing to 5,009 MW by summer of 2022.
Projected Peak Demand & Energy Usage
Based on all of the factors and considerations above, Figure 9 below illustrates the
historic and projected seasonal peak demand and annual energy consumption for the state of
Florida. While seasonal peak demand is the instantaneous usage of a customer on the system,
annual energy consumption addresses the total cumulative demand on the system over time,
which determines the type of units required and the resulting amount of fuel consumed.
For each category the impacts of conservation (including some self-service generators),
and for seasonal peak demand, load management programs, and interruptible/curtailable load is
shown. The total demand or total energy for load represents what otherwise would be served if
not for the impact of demand response and conservation programs. The net firm demand or net
energy for load represents the anticipated final demand or energy value, and is used as a planning
number for the calculation of generating reserves.
For historic values of seasonal peak demand, the actual rates of activation for
interruptible/curtailable load and load management are shown. The amount of available demand
response exceeded the activated amount shown, but was not called upon due to sufficient
generation assets being available during the peak hour. Generally, residential load management
programs have been called upon to a limited degree during peak periods, with a lesser amount of
interruptible/curtailable load and commercial/industrial load management activated.
The
summer of 2008 and winter of 2009 are exceptions to this trend, when a larger portion of the
available demand response resources were called upon.
For forecasted values of seasonal peak demand, it is assumed that demand response will
be activated during the peak period. However, if companies have sufficient generating assets
and it is economical to serve all customer load, demand response resources may not be activated
or only partially activated based upon each utility’s future operating conditions.
It should be noted that the forecasts shown are based upon normalized weather
conditions, while historic demand and energy forecasts represent the actual impact of severe or
mild weather conditions on Florida’s electric customers. Florida relies heavily upon both air
conditioning in summer and electric heating in winter, so both seasons experience a great deal of
variability.
While Figure 9 shows historic and forecasted winter peak demand values as the highest
seasonal values, summer peak dominates planning for most TYSP Utilities because most
generating units are sensitive to ambient temperature and are able to generate more in the winter
than in the summer. This is illustrated later in the determination of the generating reserve
margin.
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Load and Energy Forecast
Figure 9: State of Florida - Seasonal Peak Demand and Annual Energy Consumption
(Historic & Forecast)
Source: 2013 FRCC Regional Load & Resource Plan
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Load and Energy Forecast
Accuracy of Energy Forecasts
For each utility filing a TYSP, the Commission reviewed the historical forecast accuracy
of past retail energy sales forecasts. The review compared actual retail energy sales for each
year to energy sales forecasts made three, four, and five years prior. For example, the actual
2012 energy sales were compared to the projected 2012 value from forecasts made in 2009,
2008, and 2007. These differences, expressed as a percentage error rate, were used to calculate
the utility’s historical forecast accuracy using a five year rolling average. For example, the 2012
error rate looks at the difference between actual retail energy sales for 2012 through 2008,
drawing upon projections made between 2009 through 2003. An average error with a negative
value indicates a tendency to under-forecast, while a positive value represents an overforecasting of retail energy sales. Absolute average error provides an indication of the total
magnitude of error, regardless of the tendency to under/over-forecast.
Table 5: TYSP Utilities - Accuracy of Retail Energy Sales Forecasts
TYSP
Year
2009
2010
2011
2012
2013
Source: 2004
Five Year
Period
2008 - 2004
2009 - 2005
2010 - 2006
2011 - 2007
2012 - 2008
- 2013 TYSPs
Forecast Error (% )
Absolute
Average
Average
1.79%
3.56%
5.01%
5.71%
8.31%
8.31%
11.91%
11.91%
15.10%
15.10%
Table 5 above illustrates the historical forecast error for the combined 2013 through 2009
TYSPs. These correspond to actual data from 2012 through 2008. Overall, a pattern of
increasing error in retail sales forecasts is shown, with error over 10 percent based in 2011 and
2012. The high error rate, which has increased each year for the past five years, seems to be
associated with the unexpected impacts of the recession on retail energy sales in Florida, both
from reduction in the state’s growth rate, but also from decreased usage per capita. As the five
year rolling average progresses and includes more years post-recession, the error values should
subside.
Table 6 below provides a more detailed data set used to calculate the average error rating,
showing forecasts made between one and six years prior. A significant increase in error is
evident in 2008 and beyond, with forecasts made post 2009 improving in accuracy and
approaching historic levels of error. As this analysis moves forward and begins to use forecasts
developed after the beginning of the recession, the error rate should fall back to typical levels.
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Load and Energy Forecast
Table 6: TYSP Utilities - Accuracy of Retail Energy Sales Forecasts - Annual Analysis
Years Prior
Year
6
5
2004
-4.96%
2005
-5.79%
-4.00%
2006
-3.24%
0.02%
2007
0.61%
2.31%
2008
7.02%
8.40%
2009
11.97%
12.17%
2010
12.94%
15.58%
2011
21.39%
20.63%
2012
26.30%
25.97%
Source: 2004 - 2013 TYSPs
4
-3.06%
-0.66%
1.08%
3.54%
8.55%
14.50%
14.89%
19.92%
23.03%
3
0.31%
-0.60%
2.35%
3.63%
9.97%
13.93%
13.70%
16.86%
8.47%
2
-0.47%
0.75%
2.48%
4.25%
9.24%
12.70%
10.56%
3.65%
3.90%
1
1.05%
0.93%
2.42%
3.09%
8.34%
10.19%
-0.73%
-0.06%
3.70%
Average
Error
-2.57%
-1.75%
1.15%
3.16%
8.97%
13.53%
14.72%
19.14%
19.15%
Absolute
Average
Error
2.78%
1.75%
1.15%
3.16%
8.97%
13.53%
14.72%
19.14%
19.15%
As indicated by this high error rate, utilities projected increased need for energy that has
not materialized due to the recession.
The TYSP utilities have responded to changing
circumstances by delaying or cancelling new generation and taking opportunities to modernize
existing plants, as discussed in previous annual reviews of the TYSPs.
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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 1,470 MW of firm and nonfirm generation capacity, which represents 2.2 percent of Florida’s overall generation capacity of
58,200 MW in 2012. 7 Table 7 below summarizes Florida’s existing renewable energy sources.
Table 7: State of Florida - Existing Renewable Resources
Renewable Fuel Type
Summer Net Capacity (MW)
Land Fill Gas
40
Municipal Solid Waste
466
Biomass
415
Solar
178
Hydro
Waste Heat
63
308
Wind
0
Total
1,470
Source: 2013 FRCC Regional Load & Resource Plan, TYSP Utilities Data Responses
7
Total MW capacities are based off summer ratings.
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Renewable Generation
Of the total 1,470 MW of renewable generation, approximately 434 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 U.S. 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. Section 366.051, F.S., provides:
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 its capacity and energy output under a firm contract. Rule 25-17.230, F.A.C., requires
each IOU to establish a standard offer contract with timing and rate of payments based on each
fossil-fueled 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 to
select the payment option that best fits its financing requirements and provides a basis from
which negotiated contracts can be developed. On June 25, 2013, the Commission approved
standard offer contracts resulting in the continuous offering of nearly 3,700 MW for Florida’s
four largest IOUs.
As previously discussed a large amount of renewable energy is generated on an asavailable 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.
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.
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Renewable Generation
A significant portion of the utility owned renewable generation is from three solar energy
facilities, totaling 110 MW, operated by FPL. The three solar projects, 2 solar PV facilities and
1 solar thermal facility, were approved for cost recovery pursuant to Section 366.92, F.S. which
has since been revised, but previously stated:
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
generation, up to a total of 110 megawatts statewide.
In 2008, the Commission approved a petition by FPL seeking eligibility for cost recovery
pursuant to the referenced Statute. At the time of its filing, FPL estimated that the three solar
facilities would cost an additional $573 million above traditional generation costs over the life of
the facilities. Based on actual data provided by FPL, the combined cost of generation of the
three solar facilities was $.45/kWh in 2012.
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 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 attributed 3 MW
of renewable capacity. As of 2012, approximately 44 MW of renewable capacity from nearly
5,300 systems had been installed statewide. Table 8 below, summarizes the growth of customer
owned renewable generation interconnections.
Table 8: Renewable Generation Interconnections
Year
2008
2009
2010
2011
2012
Facilities
577
1,625
2,833
3,994
5,296
MW
3
13
20
29
44
Source: Annual Net M etering Reports
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Renewable Generation
Planned Renewable Additions
Florida’s utilities plan to construct or purchase an additional 966 MW of renewable
generation over the ten-year planning period. Table 9 summarizes the planned renewable
capacity increases by generation type.
Table 9: State of Florida - Planned Renewable Resource Additions
Renewable Fuel Type
Land Fill Gas
Summer Net Capacity (MW)
12
Municipal Solid Waste
125
Biomass
470
Solar
359
Hydro
0
Waste Heat
0
Wind
0
Total
966
Source: 2013 FRCC Regional Load & Resource Plan, TYSP Utilities Data Response
Of the 966 MW of planned renewable capacity, 510 MW are projected to be from firm
resources. All of the projected firm capacity additions are from renewable contracts with nonutility generators. Table 10 summarizes the firm capacity renewable resources that are planned
over the ten-year horizon.
The remaining planned capacity from renewable resources is
projected to be from non-firm resources including several 50 MW solar facilities.
Table 10: State of Florida - List of Planned Renewable Firm Capacity
Purchasing
Utility
Facility Name
Fuel
Type
Capacity
(MW)
In-Service
Date
FPL
EcoGen Clay
OBS
60
2021
FPL
EcoGen Martin
OBS
60
2021
FPL
EcoGen Okeechobee
OBS
60
2021
FPL
Solid Waste Authority of Palm Beach #2
MSW
70
2016
GRU
Gainesville Renewable Energy Center
WDS
100
2014
DEF
FB Energy
AB
60
2013
DEF
Transworld Energy
WDS
40
2013
DEF
EcoGen Polk
WDS
60
2014
Total
510
Source: 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
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Renewable Generation
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. Navigant’s assessment identified several
key drivers that impact renewable energy development in Florida. Three of the “key drivers”
were the cost of natural gas, the cost of CO 2 , and the adoption of a Renewable Portfolio Standard
(RPS).
Under a scenario considered to be favorable in fostering renewable generation, Navigant
assumed natural gas prices between $11-$14/MMBTU, CO 2 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 $3.88/MMBTU in 2013, there is no current federal pricing for CO 2
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, as discussed
in the next chapter, and reduces dependence upon 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.
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Traditional Generation
While renewable generators contribute to the state’s generating capacity, a majority is
made up of fossil-fueled steam and turbine generators that have been added to the grid over the
last several decades. Due to forecasted increases in peak demand, further fossil-fired generation
is anticipated over the planning horizon.
Historically, Florida’s utilities relied upon oil-fired generation as the primary source of
electricity until the increase in oil prices associated with the oil embargo. Since that time,
Florida’s utilities have sought a variety of other fuel sources to diversify the generating capacity
and economically serve Florida’s electric customers. Solid fuels, such as coal and nuclear, were
utilized in greater quantity. Finally, natural gas has emerged as the dominant generating fuel.
The swings of fuel prices, availability, environmental concerns, and other factors have resulted in
a variety of capacity on Florida’s existing system.
Existing Generation Resources
Florida’s generating fleet includes incremental new additions to the 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 continue safe operation. Figure 10 below illustrates the decade currently
operating generating capacity was originally added to the grid, with the largest additions
occurring in the 2000s.
Figure 10: State of Florida - Generation Capacity Additions by Fuel Type and Decade
Source: 2013 FRCC Regional Load & Resource Plan
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Traditional Generation
The existing generating fleet will be impacted by several events over the planning period.
Retirements, including Crystal River 1 through 3 and Scholz 1 and 2, will reduce the existing
fleet, while modernizations will replace older generation with newer, more efficient resources,
and several units may have to install new pollution control equipment that may reduce net
capacity. These items are discussed below.
Impact of EPA Regulations
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 EPA has
finalized or proposed several rules which will impact both existing and planned generating units
in the state. Potential environmental requirements and their associated costs must be considered
to fully evaluate any new supply-side resources, as well as the maintenance and dispatch of
existing generating units.
Four EPA rules are anticipated to potentially affect electric generation in Florida:
•
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 gnerators, as well as particulate matter, sulfur dioxide, and nitrogen oxide from
new and modified coal and oil units.
•
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. Due to ongoing litigation, the only
costs utilities reported associated with CSAPR are stranded costs.
•
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.
•
Coal Combustion Residuals (CCR) - Requires liners and ground monitoring to be
installed on new landfills in which coal ash is disposed.
At this time, GPC’s coal-fired Plant Scholz units 1 & 2 and DEF’s Crystal River units 1
& 2 are the only plants anticipated to be retired as a result of any of these regulations.
Additionally, DEF’s Suwanee River Units 1-3, which can use either residual oil or natural gas,
will cease residual oil operations in order to comply with the MATS rule. GPC has estimated
that the costs for complying with the MATS Rule will make the operation of Plant Scholz
uneconomical, and it will cease operation on April 1, 2015. Crystal River Units 1 and 2 are
expected to cease operation in April of 2016, following a one-year MATS extension to perform
transmission upgrades needed to take the units offline without affecting reliability.
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Traditional Generation
For many of the plants 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. Several of the TYSP utilities have provided preliminary estimates based upon
known and proposed rule language, and are shown in Table 11 below.
Table 11: TYSP Utilities - Cost Estimates of EPA Rule Compliance (2013-2022)
Preliminary Total Cost Estimates ($ Millions)
Utility
Florida Power & Light
Duke Energy Florida
(Capital Costs Only)
MATS
CSAPR
CWIS
CCR
Total
$226
0
$122-$1,515
Unavailable
$348-$1,741
85-130*
0
80-1,200
Unavailable
165-1,330
Tampa Electric Company
18.6
0
860
$141**
1,020
544-843
0
38-125
255-414
837-1,382
Florida Municipal Power Agency
Unavailable
Unavailable
Unavailable
Unavailable
Unavailable
Gainesville Regional Utilities
Unavailable
Unavailable
0
Unavailable
Unavailable
JEA
Unavailable
Unavailable
Unavailable
Unavailable
Unavailable
Lakeland Electric
Unavailable
Unavailable
Unavailable
Unavailable
Unavailable
Orlando Utilities Commission
2.3
$11
Unavailable
13
26
Seminole Electric Cooperative
0
0
Unavailable
Unavailable
0
Unavailable
$1,100$3,700
Unavailable
Unavailable
$2,396$5,499
Gulf Power Company
City of Tallahassee
Unavailable
Unavailable
$876Total
$1,220
$11
* Excludes costs related to Crystal River Units 1 and 2.
** Excludes Capital Costs.
Source: TYSP Utility Data Responses
$409-$568
Modernization and Efficiency Improvements
Recently, several of Florida’s utilities have taken advantage of high reserve margins and
engaged in modernizations of existing plant sites. These projects involve removing existing
generator units that may not be as economical to operate, such as oil-fired steam units, and
reusing the 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 price lower than new construction.
The Commission has previously granted determinations of need for several conversions
of oil-fired steam to natural gas-fired combined cycle units, including FPL’s Cape Canaveral,
Riviera, and Port Everglades sites. The Commission has also granted determinations of need for
conversion of existing combustion turbines into combined cycle units, including the conversion
of TECO’s Polk Units 2 through 5 in 2012. DEF has also recently conducted a conversion of its
Bartow plant, but this did not require a determination of need from the Commission.
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Traditional Generation
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 investigated before
considering new construction. Utilities should continue to explore potential conversion projects
and report the feasibility and economic viability of each conversion in next year’s TYSPs and
before any need determination filing.
For some existing units, generation output can be improved by installing more advanced
equipment.
The Commission has previously granted determinations of need for uprates at
existing nuclear units, resulting in an additional 440 MW in new capacity. FPL also plans
improvements in several of its combined cycle generating units by upgrading the integrated
combustion turbines.
Planned Retirements
This year’s update of the utility’s TYSPs includes a large number of retirements. The
most notable of these is DEF’s announcement of the retirement of Crystal River Unit 3 (CR3),
one of only five nuclear plants within the state of Florida. CR3 had been offline for several years
due to complications from a steam generator replacement project meant to expand the life of the
unit beyond its initial 40 year planned life. As a going forward concern, this retirement reduces
the fuel diversity of the existing generation fleet, further increasing dependence on natural gas
which has served as the primary replacement fuel.
Table 12 below lists all planned retirements by TYSP Utilities of existing generating
units over the planning period, totaling 4,144 MW, a majority of which is oil-fired steam
generation. These is due to a combination of factors, with specific units retired due to the
modernization of existing plants, the proposed EPA Rules discussed above, or the generating
unit reaching the end of its design life.
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Traditional Generation
Table 12: TYSP Utilities - Planned Unit Retirements
Summer
Planned
Capacity
Retirement
Notes
(MW)
Date*
Nuclear Units
DEF** Crystal River 3
Nuclear Steam
850
01/2013
Oil-Fired Units
FPL
Port Everglades 3 & 4
Oil Steam
761
01/2013
Modernization
FPL
Turkey Point 1 & 2
Oil Steam
788
01/2013*
DEF
Suwannee River 1 - 3
Oil Steam
129
06/2018
DEF
Various
Oil Turbine
56
04/2016
Coal-Fired Units
DEF
Crystal River 1 & 2
Coal Steam
869
04/2016
EPA Rules Related
GPC
Scholz 1 & 2
Coal Steam
92
04/2015
EPA Rules Related
Gas-Fired Units
FPL
Municipal Plant 2 & 5
Gas CC
44
01/2017
FPL
Municipal Plant 1, 3, 4
Gas Steam
94
01/2014
DEF
Various
Gas Turbine
129
06/2016
GPC
Pea Ridge 1-3
Gas Turbine
12
12/2018
GRU
Various
Gas Steam
98
10/2015*
GRU
JR Kelly GT01-03
Gas Turbine
42
02/2018*
TAL
Various
Gas Turbine
56
03/2015*
TAL
Various
Gas Steam
124
12/2013*
Total
4,144
*Planned Retirement Date is for earliest unit retirement. Other units may retire later than indicated here
** Multiple Joint Owners for Crystal River 3. Primary owner listed here.
Source: 2013 TYSPs, 2013 FRCC Regional Load & Resource Plan
Utility
Generating Unit
Name
Generator
Type
Reserve Margin Requirements
In order to maintain stability in the electric system, utilities must constantly adjust system
output to match demand from moment to moment. As demand fluctuates, utilities must generate
the precise amount of electrical power that will keep the system in balance while also performing
periodic maintenance on its generating units. In addition, utilities must be prepared at any
moment to meet unforeseen circumstances, such as extreme weather events or unit outages.
Therefore, each utility must maintain a certain amount of “extra” or reserve capacity in the event
that demand rises above or supply drops below forecasted levels. This additional amount of
generating capacity is expressed as a percentage of firm demand and is referred to as the reserve
margin.
Reserve margins in Florida typically remain well above the FRCC minimum of 15
percent for most of the year, and usually will only approach minimum levels in the summer peak
season when air conditioning loads are at their highest levels. The higher margins during winter
peak seasons are also due to the fact that generating units can operate at a higher capacity in
colder temperatures. The three largest IOUs, FPL, DEF, and TECO, were party to a stipulation
approved by the Commission setting a 20 percent reserve margin planning criterion.
The values in Figure 11 below include both supply-side and demand-side contributions,
and shows that planning is mostly controlled by summer peak demand. It should be noted that
2013 Ten-Year Site Plan Review
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Traditional Generation
the figure below is for the State of Florida, and therefore contains generating capacity outside of
the FRCC region.
Figure 11: State of Florida - Seasonal Reserve Margin (Summer & Winter)
Source: 2013 FRCC Regional Load & Resource Plan
Role of Demand Side Management in Reserve Margin
It should be noted that the reserve margin figures above are calculated using the net firm
system demand for the diagonal shaded value, which assumes full use of interruptible load and
load management devices to reduce peak demand, while the total system demand, which only
includes generation and conservation, is the solid value. Participation in interruptible rates and
load management programs are voluntary, for which incentives are provided in the form of lower
rates or credits paid to the participant. As shown in Figure 11 above, the state as a whole has
2013 Ten-Year Site Plan Review
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Traditional Generation
sufficient generation capacity planned throughout a majority of the period to meet the minimum
reserve margin of 15 percent without relying on demand response. As noted previously, these
customers have not typically been activated during periods of peak demand.
New Generation Resources
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 traditional generating capacity still exists. While reductions in demand
have been significant, the total demand for electricity and the per-capita consumption 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 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 12 below illustrates the present and future aggregate capacity mix. The capacity
values in Figure 12 incorporate all proposed additions, changes, and retirements contained in the
reporting utilities’ 2013 Ten-Year Site Plans.
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Traditional Generation
Figure 12: State of Florida - Installed Capacity (Existing & Projected)
Source: 2013 TYSPs, 2013 FRCC Regional Load & Resource Plan, 2013 TYSP Utilities Data Responses
Fuel Price Forecasts
Fuel price forecast is the primary factor affecting the type of generating unit added by an
electric utility. In general, the capital cost of a generating unit is inversely proportional to the
cost of the fuel used to generate electricity from that unit. Historically, when the forecasted price
difference between coal or nuclear and natural gas was small, the addition of a natural gas unit
became the more attractive option. As the fuel price gap widened, a coal-fired or nuclear unit
would normally be the more likely choice.
From 2003 to 2005, the price of natural gas was substantially higher than utilities had
forecasted. This disparity led to concern regarding escalating customer bills and an expectation
that natural gas prices would continue to be high and extremely volatile. As a result, Florida’s
utilities began making plans to build coal-fired units rather than continuing to increase the
reliance on natural gas. Due to concerns regarding potential future environmental regulations
and other projected costs, coal-fired generation was not selected. However, as Figure 13 shows,
the price of natural gas began to return to more historic levels after peaking in 2008, and has
declined in the years since. Forecasts predict that gas prices will increase at a steady rate
throughout the planning horizon. This trend has encouraged utilities to switch units to be
capable of burning natural gas, either as a starter fuel, supplemental fuel, or the primary fuel by
changing the fuel type of a generating unit entirely.
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Traditional Generation
Figure 13: TYSP Utilities - Fuel Prices (History & Forecast)
Source: TYSP Utilities Data Responses
Fuel Diversity
Natural gas has risen to become one of the dominant fuels in the state in the last ten
years, displacing coal, and in 2012 generated more net energy for load than all other fuels
combined in Florida. As Figure 14 shows, natural gas now makes up greater than 64.8 percent of
electric energy consumed in Florida. Natural gas usage is anticipated to decline somewhat,
remaining at approximately 60 percent throughout the planning period, ending up at 58.8 percent
by 2022.
Figure 14: State of Florida - Natural Gas Usage (History & Forecast)
Source: 2013 FRCC Regional Load & Resource Plan
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Traditional Generation
Combustion turbine technology is more efficient when used in a combined cycle mode, in
which waste heat is recovered to generate steam, than steam generation alone. This gives natural
gas a technological edge above its normal fuel price, so less fuel is required per unit of electricity
generated. Because of this, despite coal having a lower price per unit energy, it is typically
dispatched after natural gas based on current and projected fuel prices. As this gap widens again
towards the end of the period, some increases in coal-fired generation are anticipated.
Utility plans for a balanced fuel system have historically been highly dependent upon the
accuracy of long-term fuel price forecasts, mostly due to the long lead times required for coal
and especially nuclear generators. However, in recent years the options available to utilities for
the addition of supply-side generation have been limited, and this situation seems unlikely to
change at this time.
Utilities will be faced with selecting technologies for new generation that
will either continue to increase the already very high percentage of natural gas resources, or
attempting to obtain approval for solid fuel resources that may have a negative near term rate
impact.
The anticipated decline in natural gas consumption over the planning period is the result
of increased nuclear generation from FPL’s uprates, which had many of their units off-line in
2012, and a slight increase in contribution to NEL from coal-fired generation.
Nuclear
generation is anticipated to increase at the end of the planning period, with the addition of
Turkey Point 6 in the middle of 2022, to be followed the next year, outside of this planning
period, by Turkey Point 7 in 2023. Figure 15 below illustrates the anticipated contribution by
natural gas, coal, nuclear, oil, and all other sources, including interchange, non-utility generators,
and renewables.
Figure 15: State of Florida - Fuel Diversity (History & Forecast)
Source: 2004 & 2013 FRCC Regional Load & Resource Plan
Compared to other states, Florida’s usage of natural gas for electric generation is high
when compared to total natural gas usage. At the TYSP Workshop, the FRCC provided data
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Traditional Generation
from the Energy Information Administration (EIA) that shows that in 2011 Florida used
approximately 86 percent of natural gas consumed in the state for electric generation, the highest
rate in the nation. Natural gas is typically not used in end-user heating, with a majority of
Florida’s residential heating from electrical generation.
Table 13: FRCC - Ten Largest States for Natural Gas Consumption (2011 Data)
State
Total Annual
Natural Gas
Consumption
(Bcf)
Annual NG
Consumption
for Electric
Generation
(Bcf)
Total Annual
Total
Marketed
Total Miles
Storage
Natural Gas of Natural Gas
Capacity
Production
Pipeline
(Bcf)
(Bcf)
Texas
3,646
1,555
7,113
58,588
812
California
2,153
651
250
11,770
571
Louisiana
1,398
462
3,029
18,900
690
1,218
1,050
15
4,971
0
1,217
427
31
5,018
246
Illinois
987
50
2
11,911
997
Pennsylvania
963
304
1,311
8,680
777
Ohio
820
93
79
7,670
580
Michigan
776
100
138
9,722
1,075
New Jersey
661
188
0
1,520
0
24,385
7,884
24,036
305,954
8,849
5.0%
13.3%
0.06%
1.6%
0%
Florida
New York
Total US
Florida as % of Total
Source: FRCC 2013 TYSP Workshop Presentation
As shown above, Florida has very little production and no gas storage capacity, yet is the
fourth largest overall consumer of natural gas. Because of geographic constraints, Florida will
most likely continue to rely on out of state production and storage to satisfy the growing electric
demands in the state.
Coal generation, beyond the reduction in dispatch due to the cost-competitiveness of
natural gas as a baseload fuel, faces challenges relating to new environmental compliance
requirements. As discussed above, new EPA regulations will potentially require installation of
new environmental controls, which could lead to the retirement of units if it is deemed
uneconomic to upgrade its emission control equipment.
Because a balanced fuel supply can enhance system reliability and mitigate the effects of
volatile fuel price fluctuations, it is important that utilities have the greatest possible level of
2013 Ten-Year Site Plan Review
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Traditional Generation
flexibility in their generation fuel source mix. Although the Commission has cited the growing
lack of fuel diversity within the State of Florida as a major strategic concern for the past several
years, natural gas is anticipated to remain the dominant fuel over the planning horizon.
Excluding renewables, all new generation facilities planned within the State of Florida over the
ten-year period are natural gas-fired units.
Projected New Units by Fuel Type
In the last ten years, almost all capacity additions to Florida’s electric system use natural
gas as the primary fuel. Coal units that were planned have been cancelled, and a majority of new
nuclear units that have been approved have been delayed beyond the planning horizon. Gas fired
units have almost exclusively been selected in recent years due to higher thermal efficiencies,
lower capital costs, short periods for permitting and construction, and sometimes the smaller land
areas required. With the recent decrease in fuel prices due to unconventional natural gas
production using hydraulic fracturing, natural gas is the favored fuel for all traditional generating
units with the exception of new nuclear units.
Currently, other than approximately 966 MW of renewable generation and 1,220 MW in
uprates and new nuclear units, all of the additional generation planned for the next ten years will
use natural gas as a fuel source.
Nuclear
Nuclear capacity, while an alternative to natural gas-fired generation, is capital-intensive
and requires a long lead time to construct. Florida’s utilities project an expansion of nuclear
power in the state through uprates at existing nuclear power plants, and the construction of two
new nuclear units. Table 14 below shows new nuclear capacity anticipated in the planning
period. The Commission previously approved uprates for all existing nuclear units in Florida.
The only remaining uprate to be completed is FPL’s Turkey Point Unit 4, completed earlier this
year. FPL also projects the first of its two new nuclear generating units to come online within
the planning period, Turkey Point Unit 6. The second unit is anticipated to be in-service by
2023. DEF’s 2012 TYSP included the return to service of an uprated CR3 in 2014. DEF’s 2013
TYSP reflects the fact that CR3 has been retired and will not return to service.
Table 14: TYSP Utilities - Nuclear Unit Additions
Summer
Capacity
(MW)
FPL
Turkey Point 4 Uprate
120
FPL
Turkey Point 6
1,100
Total Nuclear Additions
1,220
* This units have not yet received PPSA Certification
Source: 2013 TYSPs
Utility
Generating Unit Name
Certification Dates
Need Approved
PPSA
(Commission)
Certified
01/2008
10/2008
04/2008
*
In-Service
Date
03/2013
06/2022
Pursuant to a multi-party stipulation, DEF has elected to discontinue construction of its
Levy Nuclear Plants. DEF will, however, continue its efforts to obtain a combined operating
license from the Nuclear Regulatory Commission for the Levy Nuclear Project.
2013 Ten-Year Site Plan Review
Page 37
Traditional Generation
Natural Gas
With the exception of the aforementioned renewable and nuclear capacity, all remaining
new generation comes in the form of natural gas fired combustion turbines or combined cycle
units.
Natural gas-fired combined cycles represent the most abundant type of generating
capacity in the State of Florida, making up approximately 38.5 percent of installed capacity in
2012. Combustion turbines run in simple cycle mode 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 unless part of a combined cycle system, they do not require siting
under the PPSA. Table 15 below includes approximately 8,683 MW of natural gas-fired
generation included in the 2013 TYSPs.
Table 15: TYSP Utilities - Natural Gas Unit Additions
Summer
Certification Dates
In-Service
Capacity
Need Approved
PPSA
Date
(MW)
(Commission)
Certified
Combined Cycle Units
FPL
Cape Canaveral
1,210
09/2008
10/2009
06/2013
FPL
Riviera Beach
1,277
09/2008
11/2009
06/2014
FPL
Port Everglades
1,212
04/2012
03/2013
06/2016
DEF
Unnamed CC 1
1,189
*
*
06/2018
DEF
Unnamed CC 2
1,189
*
*
06/2020
TECO Polk 2-5 CC Conversion
459
12/2012
*
01/2017
SEC
Unnamed CC 1
192
*
*
12/2020
SEC
Unnamed CC 2
192
*
*
12/2020
Combustion Turbine Units
SEC
Unnamed CT 1
198
**
**
12/2019
TECO
Future CT
190
**
**
05/2020
TAL
Hopkins 5
46
**
**
05/2020
SEC
Unnamed CT 2 & 3
396
**
**
12/2020
SEC
Unnamed CT 4 - 7
792
**
**
12/2021
DEF
Unnamed CT
187
**
**
06/2022
Total Natural Gas Additions
8,683
* These units have not yet received a Determination of Need and/or a PPSA Certification.
** These units are not regulated under the PPSA, and do not require a Determination of Need.
Source: TYSP Utilities Data Response
Utility
Generating Unit Name
Power Plant Siting Act 8
The Florida PSC is given exclusive jurisdiction by the Legislature, through the PPSA, to
be the forum for determining the need for new electric power plants. Any proposed steam or
solar generating unit of at least 75 MW requires certification under the Power Plant Siting Act.
Approximately 9,960 MW of new utility-owned generating units are planned to enter
service over the next 10-year period, with 82 percent of that subject to the PPSA. A majority of
8
Sections 403.501 through 403.518, F.S.
2013 Ten-Year Site Plan Review
Page 38
Traditional Generation
this portion new generation has already received a determination of need from the Commission.
A total of 2,762 MW still requires certification, as shown in Table 16.
Table 16: State of Florida - Proposed Generation Requiring Commission Approval
Utility
Generating Unit Name
DEF
Unnamed CC
DEF
Unnamed CC
SEC
Unnamed CC
SEC
Unnamed CC
Total Capacity
Source: 2013 TYSPs
1
2
1
2
Summer
Capacity
(MW)
1,189
1,189
192
192
2,762
In-Service
Date
06/2018
06/2020
12/2020
12/2020
Transmission Capacity
As generation capacities increase, the transmission system must grow accordingly to
maintain the capability of delivering the energy to the end user. 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.
The Commission has authority over certain proposed transmission lines under the
To require certification under Florida’s TLSA, a
Transmission Line Siting Act (TLSA). 9
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 also exempt from TLSA requirements. The Commission determines the reliability
need for and the proposed starting and ending points for lines requiring TLSA certification. The
Commission must issue a final order granting or denying a determination of need within 90 days
of the petition filing. The proposed corridor route is determined by the 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 the proposed line.
Table 17 below lists all proposed transmission lines in the 2013 TYSPs 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 17: TYSP Utilities - Transmission Requiring TLSA Approval
Utility
Transmission Line
DEF
Intercession City - Gifford
FPL
Manatee - Bob White
FPL
St. Johns - Pringle
Source: TYSP Utilities Data Responses
9
Line
Length
(Miles)
Nominal
Voltage
(kV)
13
30
25
230
230
230
Certification
Need
Approved
(Commission)
09/2007
08/2006
05/2005
Dates
TLSA
Certified
Commercial
In-Service
Date
01/2009
11/2008
04/2006
05/2013
12/2014
12/2017
Sections 403.52 through 403.5365, F.S.
2013 Ten-Year Site Plan Review
Page 39
Utility Perspectives
2013 Ten-Year Site Plan Review
Page 40
Florida Power & Light Company (FPL)
FPL is the state’s largest electric utility. The utility’s service territory is within the FRCC
region, and is primarily in southern Florida and along the east coast. As FPL is an IOU, the
Commission has regulatory authority over all aspects of operations, including rates, reliability,
and safety.
Load and Energy Forecast
In 2012, FPL had approximately 4,572,800 customers, with annual retail energy sales of
101,678 GWh, or approximately 47.3 percent of the state of Florida’s NEL. Total number of
customers and annual energy consumption by customer class are below in Figure 16.
Figure 16: FPL - Number of Customers and Energy Usage by Class
Source: 2013 T YSP Schedule 2
Figure 17 illustrates the company’s historic and projected growth as a percentage of its
total number of customers and retail energy sales in 2003. Over the last ten years, FPL has
increased/decreased its total number of customers by 11.2 percent, while increasing retail energy
sales by 2.7 percent. The company forecasts continued positive growth for all years of the
planning period, with retail energy sales exceeding the historic 2007 peak by 2014.
Figure 17: FPL - Customer and Retail Energy Sale Growth Since 2003
Source: 2013 T YSP Schedule 2
2013 Ten-Year Site Plan Review
Page 41
Florida Power & Light (FPL)
Seasonal Peak Demand & Annual Energy for Load
The following three graphs in Figure 18 show FPL’s historic peak demand for both the
summer and winter seasons, and net energy for load for the years 2003 through 2012. The
forecasted values are also shown through the current planning horizon, including the effect of the
utility’s DSM programs. Available demand response values are shown below for the previous
ten years, but demand response was not activated during the historic seasonal peak demand
hours, excluding the winters of 2010 and 2011.
Figure 18: FPL - Seasonal Peak Demand and Annual Energy Consumption
(Historic & Forecast)
Source: 2013 T YSP Schedule 3
2013 Ten-Year Site Plan Review
Page 42
Florida Power & Light (FPL)
Generation Resources
Fuel Diversity
Figure 19 shows FPL’s historic fuel mix for 2003 and 2012, and the projected fuel mix
for 2022. FPL’s primary generation fuel is natural gas, which has increased from 34.8 percent of
system energy in 2003, to 72.6 percent in 2012. A portion of this increase is due to long-term
outages of several nuclear units on FPL’s system for uprates during 2012, with nuclear
representing FPL’s next highest fuel usage. The return to service of the uprated nuclear units
will slightly decrease FPL’s natural gas usage, estimated at 66.1 percent in 2013. The trend of
natural gas being the primary system fuel will continue, with another decrease in usage, to 63.2
percent in 2022, due to an increase in nuclear generation with the addition of Turkey Point 6 for
a portion of the year. Natural gas usage is anticipated to decline again in 2023 with a full year of
operation of Turkey Point 6 and a partial year for Turkey Point 7.
Figure 19: FPL - Fuel Diversity (History & Forecast)
Source: 2013 T YSP Schedule 6
Planned Generation
FPL’s 2013 TYSP includes five planned generation additions, including three combined
cycle units, a nuclear uprate, and a new nuclear unit. A second new nuclear unit, Turkey Point 7,
is planned in 2023, outside of the 2013 TYSP planning period. The planned units are detailed
below in Table 18. This is consistent with the company’s 2012 TYSP, featuring no new
generating units. The previous TYSP also included the uprates completed in 2012 to FPL’s other
three nuclear units.
Table 18: FPL - Planned Generation Additions
Summer
In-Service
Capacity (MW)
Date
Natural Gas Units
Cape Canaveral Energy Center
Combined Cycle
1,210
06/2013
Riviera Beach Energy Center
Combined Cycle
1,277
06/2014
Port Everglades Energy Center
Combined Cycle
1,212
06/2016
Nuclear Units
Turkey Point Unit 4 Uprate
Steam Turbine
120*
03/2013
Turkey Point Unit 6
Steam Turbine
1,100
06/2022
Turkey Point Unit 7
Steam Turbine
1,100
12/2023
*This capacity represents the uprate only, not the full capacity of the generating unit
Source: 2013 TYSP Schedule 8
Generating Unit Name
2013 Ten-Year Site Plan Review
Generator Type
PPSA
Approved
Approved
Approved
Approved
Pending
Pending
Page 43
Florida Power & Light (FPL)
Reserve Margin
FPL maintains a minimum 20 percent reserve margin for planning purposes based on a
stipulation approved by the Commission. Figure 20 displays the forecast planning reserve
margin for FPL through the planning period for both seasons including the effects of projected
conservation activities. The impact of demand response programs on reserve margin is also
included. As shown in the figure, FPL is a summer peaking utility.
Figure 20: FPL - Seasonal Reserve Margin (Summer & Winter)
Source: 2013 T YSP Schedule 7
2013 Ten-Year Site Plan Review
Page 44
Duke Energy Florida, Inc. (DEF)
DEF is an investor-owned utility, and Florida’s second largest TYSP utility. The utility’s
service territory is within the FRCC region, and is primarily located in central and west central
Florida. The company’s TYSP was filed under its previous business name, Progress Energy
Florida, Inc. (PEF). As DEF is an IOU, the Commission has regulatory authority over all aspects
of operations, including rates, reliability, and safety.
Load and Energy Forecast
In 2012, DEF had approximately 1,624,400 customers, with annual retail energy sales of
33,135 GWh, or approximately 17.6 percent of the state of Florida’s NEL. Total number of
customers and annual energy consumption by customer class are below in Figure 21.
Figure 21: DEF - Number of Customers and Energy Usage by Class
Source: 2013 T YSP Schedule 2
Figure 22 illustrates the company’s historic and projected growth as a percentage of its
total number of customers and retail energy sales in 2003. Over the last ten years, DEF has
increased its total number of customers by 9.2 percent, while retail energy sales have declined by
4.2 percent. The company forecasts positive growth for all years of the planning period, with
retail energy sales exceeding the historic 2006 peak by 2017.
Figure 22: DEF - Customer and Retail Energy Sale Growth Since 2003
Source: 2013 T YSP Schedule 2
2013 Ten-Year Site Plan Review
Page 45
Duke Energy Florida (DEF)
Seasonal Peak Demand & Annual Energy for Load
The following three graphs in Figure 23 show DEF’s historic peak demand for both the
summer and winter seasons, and net energy for load for the years 2003 through 2012. The
forecasted values are also shown through the current planning horizon, including the effect of the
utility’s DSM programs. Available demand response values are shown below for the previous
ten years, but generally these programs have not been activated during summer peak periods.
Demand response was utilized during seasonal peak demand periods in the summer of 2005 and
winters of 2003, 2006 through 2008, and 2010.
Figure 23: DEF - Seasonal Peak Demand and Annual Energy Consumption
(Historic & Forecast)
2013 Ten-Year Site Plan Review
Page 46
Duke Energy Florida (DEF)
Source: 2013 T YSP Schedule 3
Generation Resources
Fuel Diversity
Figure 24 shows DEF’s historic fuel mix for 2003 and 2012, and the projected fuel mix
for 2022. DEF’s primary generation fuel is natural gas, which has increased from 14 percent of
system energy in 2003, to 58.2 percent in 2012. A portion of this increase is due to the
retirement of the Crystal River 3 nuclear unit, which previously provided over ten percent of
system energy. Coal has the second highest fuel usage, but is anticipated to decline and be
replaced by natural gas over the planning period. Purchased power makes up a sizeable portion
of DEF’s system energy, at 17.1 percent in 2012, with a peak projected in 2017 at 24 percent of
system energy. Purchased power is anticipated to decline while natural gas increases with the
addition of new natural gas-fired generation discussed below.
Figure 24: DEF - Fuel Diversity (History & Forecast)
Source: 2013 T YSP Schedule 6
Planned Generation
DEF’s 2013 TYSP includes three planned generation additions, two combined cycle units
and a combustion turbine. All units are unsited at this time. The planned units are detailed
below in Table 19. This represents an increase from the company’s 2012 TYSP in both number
of generating units and total capacity. The previous TYSP had projected a return to service of an
uprated Crystal River 3 by the end of 2014 and a single combined cycle unit in 2019.
Table 19: DEF - Planned Generation Additions
Generating Unit Name
Unnamed CC 1
Unnamed CC 2
Unnamed CT 1
Summer
Capacity (MW)
Natural Gas Units
Combined Cycle
1,189
Combined Cycle
1,189
Combustion Turbine
187
Generator Type
In-Service
Date
PPSA
06/2018
06/2020
06/2022
Required
Required
N/A
Source: 2013 T YSP Schedule 8
2013 Ten-Year Site Plan Review
Page 47
Duke Energy Florida (DEF)
Reserve Margin
DEF maintains a minimum 20 percent reserve margin for planning purposes based on a
stipulation approved by the Commission. Figure 25 displays the forecast planning reserve
margin for DEF through the planning period for both seasons including the effects of projected
conservation activities. The impact of demand response programs on reserve margin is also
included. As shown in the figure, DEF is a summer peaking utility.
Figure 25: DEF - Seasonal Reserve Margin (Summer & Winter)
Source: 2013 T YSP Schedule 7
Due to the retirement of CR3, combined with the potential retirement of oil and coal-fired
units totaling over 1,000 MWs due to potential EPA emissions rules, DEF will require a large
amount of firm capacity to meet customer demand on a fairly short basis. While DEF projects
construction of several generating units within the planning period, the earliest is anticipated to
enter service in 2018, after any potential EPA related retirements. Therefore, DEF will require
firm purchased power in the interim, especially for summer peaks. The company has issued two
requests for proposals, seeking power both from within and outside Florida, and is in the process
of negotiating with suppliers. It appears at this time that there is sufficient capacity available
from other parties to provide for the required firm capacity purchases. The Commission will
continue to monitor DEF’s efforts to secure firm capacity for its customers.
2013 Ten-Year Site Plan Review
Page 48
Tampa Electric Company (TECO)
TECO is an investor-owned electric utility, and Florida’s third largest TYSP utility. The
utility’s service territory is within the FRCC region, and consists primarily of the Tampa
metropolitan area. As TECO is an IOU, the Commission has regulatory authority over all
aspects of operations, including rates, reliability, and safety.
Load and Energy Forecast
In 2012, TECO had approximately 676,300 customers, with annual retail energy sales of
16,582 GWh, or approximately 8.2 percent of the state of Florida’s NEL. Total number of
customers and annual energy consumption by customer class are below in Figure 26.
Figure 26: TECO - Number of Customers and Energy Usage by Class
Source: 2013 T YSP Schedule 2
Figure 27 illustrates the company’s historic and projected growth as a percentage of its
total number of customers and retail energy sales in 2003. Over the last ten years, TECO has
increased its total number of customers by 13.1 percent, while increasing retail energy sales by
1.0 percent. The company forecasts continued positive growth most years of the planning
period, with retail energy sales exceeding the historic 2007 peak by 2020.
Figure 27: TECO - Customer and Retail Energy Sale Growth Since 2003
Source: 2013 T YSP Schedule 2
2013 Ten-Year Site Plan Review
Page 49
Tampa Electric Company (TECO)
Seasonal Peak Demand & Annual Energy for Load
The following three graphs in Figure 28 show TECO’s historic peak demand for both the
summer and winter seasons, and net energy for load for the years 2003 through 2012. The
forecasted values are also shown through the current planning horizon, including the effect of the
utility’s DSM programs. Available demand response values are shown below for the previous
ten years, but generally these programs have not been activated, excluding three summer peaks,
in 2005, 2007, and 2009.
Figure 28: TECO - Seasonal Peak Demand and Annual Energy Consumption
(Historic & Forecast)
Source: 2013 T YSP Schedule 3
2013 Ten-Year Site Plan Review
Page 50
Tampa Electric Company (TECO)
Generation Resources
Fuel Diversity
Figure 29 shows TECO’s historic fuel mix for 2003 and 2012, and the projected fuel mix
for 2022. TECO’s primary generation fuel is coal, one of only two utilities in the state that relied
upon the solid fuel over natural gas in 2012, with 50.3 percent of system energy generated by
coal. Coal usage has declined however, primarily with the increase of natural gas, which is the
next highest fuel for TECO’s system energy. Natural gas has risen to 39.2 percent of system
energy in 2012, up from only 2.4 percent in 2003. Coal is anticipated to remain the main system
fuel throughout the planning period, making up 49.4 percent in 2022, although natural gas is
projected to replace purchased power and increase its share of system energy to 43.9 percent in
2022.
Figure 29: TECO - Fuel Diversity (History & Forecast)
Source: 2013 T YSP Schedule 6
Planned Generation
TECO’s 2013 TYSP includes two planned generation additions.
The first is a
modernization of their existing Polk plant site by converting the existing combustion turbines
into a combined cycle unit. The second is a combustion turbine to be sited somewhere in
Hillsborough County. These units are described below in Table 20. This is consistent with the
company’s 2012 TYSP, which included similar generating units. The primary change is the
increase in capacity and one year delay in the in-service date of the planned combustion turbine.
Table 20: TECO - Planned Generation Additions
Summer
In-Service
PPSA
Capacity (MW)
Date
Natural Gas Units
Polk 2-5 Conversion
Combined Cycle
459
01/2017
Pending
Future CT 1
Combustion Turbine
190
05/2020
N/A
*Represents additional steam capacity from conversion, not including the original CT units.
Generating Unit Name
Generator Type
Source: 2013 T YSP Schedule 8
2013 Ten-Year Site Plan Review
Page 51
Tampa Electric Company (TECO)
Reserve Margin
TECO maintains a minimum 20 percent reserve margin for planning purposes based on a
stipulation approved by the Commission. Figure 30 displays the forecast planning reserve
margin for TECO through the planning period for both seasons including the effects of projected
conservation activities. The impact of demand response programs on reserve margin is also
included. As shown in the figure, TECO is generally a winter-peaking utility, during certain
periods summer peak demand can be of greater concern. TECO also maintains a minimum
supply-side contribution to its reserve margin, set at 7 percent, which it exceeds by more than
100 percent in all years of the planning period.
Figure 30: TECO - Seasonal Reserve Margin (Summer & Winter)
Source: 2013 T YSP Schedule 7
2013 Ten-Year Site Plan Review
Page 52
Gulf Power Company (GPC)
GPC is the smallest investor-owned generating utility, and the sixth largest TYSP utility.
The utility’s service territory includes western Florida. GPC is a member of the Southern
Company electric system and has the SERC as its regional reliability entity. Because GPC plans
and operates its system in conjunction with the other Southern Company utilities, not all of the
energy generated by the GPC units is consumed in Florida. As GPC is an IOU, the Commission
has regulatory authority over all aspects of operations, including rates, reliability, and safety.
Load and Energy Forecast
In 2012, GPC had approximately 433,900 customers, with annual retail energy sales of
10,637 GWh, or approximately 4.9 percent of the state of Florida’s NEL. Total number of
customers and annual energy consumption by customer class are below in Figure 31.
Figure 31: GPC - Number of Customers and Energy Usage by Class
Source: 2013 T YSP Schedule 2
Figure 32 illustrates the company’s historic and projected growth as a percentage of its
total number of customers and retail energy sales in 2003. Over the last ten years, GPC has
increased its number of customers by 11.4 percent, though retail energy sales have declined 2.0
percent. The company forecasts continued positive growth for all of the planning period, with
retail energy sales exceeding the historic 2008 peak by 2017.
Figure 32: GPC - Customer and Retail Energy Sale Growth Since 2003
Source: 2013 T YSP Schedule 2
2013 Ten-Year Site Plan Review
Page 53
Gulf Power Company (GPC)
Seasonal Peak Demand & Annual Energy for Load
The following three graphs in Figure 33 show GPC’s historic peak demand for both the
summer and winter seasons, and net energy for load for the years 2003 through 2012. The
forecasted values are also shown through the current planning horizon, including the effect of the
utility’s DSM programs. GPC does not currently include any demand response in its forecasts.
Figure 33: GPC - Seasonal Peak Demand and Annual Energy Consumption
(Historic & Forecast)
Source: 2013 T YSP Schedule 3
2013 Ten-Year Site Plan Review
Page 54
Gulf Power Company (GPC)
Generation Resources
Fuel Diversity
Figure 34 shows GPC’s historic fuel mix for 2003 and 2012, and the projected fuel mix
for 2022. GPC is a net energy exporter, and as a result produces more energy than its system
consumes each year, with exports planned to increase over the planning period. GPC’s primary
fuel in 2012 was natural gas, at 90.7 percent of system energy, which displaced coal for the first
time in the past ten years. Coal has declined from producing 109 percent of system energy in
2003, to only 46.5 percent in 2012. By the end of the planning period, GPC forecasts that coal
will once again become the dominant system fuel, at 85.8 percent, with natural gas still
contributing over half of system energy, at 58.4 percent.
Figure 34: GPC - Fuel Diversity (History & Forecast)
Source: 2013 T YSP Schedule 6
Planned Generation
GPC’s 2013 TYSP included a single generation addition at their existing Perdido landfill
gas site in Escambia County. This is an increase from the company’s 2012 TYSP, which
included no new generating units.
Table 21
Table 21: GPC - Planned Generation Additions
Generating Unit Name
Perdido 3
Summer
Capacity (MW)
Renewable Units
Landfill Gas-fired IC
1.8
Generator Type
In-Service
Date
PPSA
8/2014
N/A
Source: 2013 T YSP Schedule 8
2013 Ten-Year Site Plan Review
Page 55
Gulf Power Company (GPC)
Reserve Margin
GPC is not within the FRCC region, and therefore not subject to its minimum reserve
margin requirements. GPC operates within SERC, and as part of the Southern Power Pool has a
planning reserve margin of 15 percent after 2015. Figure 35 displays the forecasted planning
reserve margin for GPC through the planning period for both seasons, including the effects of
projected conservation activities. As shown in the figure, GPC is a winter-peaking utility for
most years and has sufficient reserve margin to meet projected customer demands for both
seasons throughout the planning period.
Figure 35: GPC - Seasonal Reserve Margin (Summer & Winter)
Source: 2013 T YSP Schedule 7
2013 Ten-Year Site Plan Review
Page 56
Florida Municipal Power Agency (FMPA)
FMPA is a governmental wholesale power company owned by multiple municipal
electric utilities located throughout Florida. It is collectively the state’s eighth largest TYSP
utility. As FMPA is a municipal utility, the Commission’s regulatory authority is limited to
safety, rate structure, territorial boundaries, bulk power supply, operations, and planning.
FMPA’s direct responsibility for power supply is with the All-Requirements Power Supply
Project (ARP). FMPA plans and supplies all of the power requirements for the ARP utilities
Load and Energy Forecast
In 2012, FMPA’s members had approximately 265,300 customers, with total retail
energy sales of 5,549 GWh, or approximately 2.6 percent of the state of Florida’s NEL. Total
number of customers and annual energy consumption by customer class are below in Figure 36.
Figure 36: FMPA - Number of Customers and Energy Usage by Class
Source: 2013 T YSP Schedule 2
Figure 37 illustrates the company’s historic and projected growth as a percentage of its
total number of customers and retail energy sales in 2003. Over the last ten years, FMPA has
seen a decrease in customers by 2.1 percent, and a decrease in retail energy sales by 13.2 percent.
The company does not project to exceed its 2003 retail energy sales within the next ten years.
Figure 37: FMPA - Customer and Retail Energy Sale Growth Since 2003
Source: 2013 T YSP Schedule 2
2013 Ten-Year Site Plan Review
Page 57
Florida Municipal Power Agency (FMPA)
Seasonal Peak Demand & Annual Energy for Load
The following three graphs in Figure 38 show FMPA’s historic peak demand for both the
summer and winter seasons, and net energy for load for the years 2003 through 2012. The
forecasted values are also shown through the current planning horizon, including the effect of
member utility’s DSM programs. As FMPA did not provide separate annual conservation data,
only the utility’s net firm demand and net energy for load are shown below.
Figure 38: FMPA - Seasonal Peak Demand and Annual Energy Consumption
(Historic & Forecast)
Source: 2013 T YSP Schedule 3
2013 Ten-Year Site Plan Review
Page 58
Florida Municipal Power Agency (FMPA)
Generation Resources
Fuel Diversity
Figure 39 shows FMPA’s historic fuel mix for 2003 and 2012, and the projected fuel mix
for 2022. Natural gas is the primary generation fuel on FMPA’s system, contributing 81.9
percent of system energy in 2012. A slight reduction in usage is forecast by 2022, with an
increase in purchased power and coal usage reducing natural gas to approximately two-thirds of
energy generation.
Figure 39: FMPA - Fuel Diversity (History & Forecast)
Source: 2013 T YSP Schedule 6
Planned Generation
FMPA’s 2013 TYSP did not contain any planned generation additions. This is consistent
with the company’s 2012 TYSP, which also included no new generation through 2021.
2013 Ten-Year Site Plan Review
Page 59
Florida Municipal Power Agency (FMPA)
Reserve Margin
FMPA maintains a 15 percent reserve margin based on FRCC planning requirements. In
addition, the utility uses a planning reserve margin of 18 percent for summer peak reserve
margin planning. Figure 40 displays the forecasted planning reserve margin for FMPA through
the planning period for both seasons, including the effects of projected conservation activities.
As shown in the figure, FMPA is a summer-peaking utility and has sufficient reserve margin to
meet projected customer demands for both seasons throughout the planning period.
Figure 40: FMPA - Seasonal Reserve Margin (Summer & Winter)
Source: 2013 T YSP Schedule 7
2013 Ten-Year Site Plan Review
Page 60
Gainesville Regional Utilities (GRU)
GRU is a municipal utility and the state’s smallest TYSP utility. The company’s service
area is within the FRCC region, and includes the City of Gainesville and its surrounding urban
area. GRU also provides wholesale power to the City of Alachua and Clay Electric Cooperative.
As GRU is a municipal utility, the Commission’s regulatory authority is limited to safety, rate
structure, territorial boundaries, bulk power supply, operations, and planning
Load and Energy Forecast
In 2012, GRU had approximately 95,600 customers, with annual retail energy sales of
1,675 GWh, or approximately 0.8 percent of the state of Florida’s NEL. Total number of
customers and annual energy consumption by customer class are below in Figure 41.
Figure 41: GRU - Number of Customers and Energy Usage by Class
Source: 2013 T YSP Schedule 2
Figure 42 illustrates the company’s historic and projected growth as a percentage of its
total number of customers and retail energy sales in 2003. Over the last ten years, GRU has
increased its number of customers by 10.9 percent, but retail energy sales have declined 4.8
percent. The company forecasts positive growth for the entire planning period, but does not
project retail energy sales to exceed its 2003 level within the next ten years.
Figure 42: GRU - Customer and Retail Energy Sale Growth Since 2003
Source: 2013 T YSP Schedule 2
2013 Ten-Year Site Plan Review
Page 61
Gainesville Regional Utilities (GRU)
Seasonal Peak Demand & Annual Energy for Load
The following three graphs in Figure 43 show GRU’s historic peak demand for both the
summer and winter seasons, and net energy for load for the years 2003 through 2012. The
forecasted values are also shown through the current planning horizon, including the effect of the
utility’s DSM programs.
Figure 43: GRU - Seasonal Peak Demand and Annual Energy Consumption
(Historic & Forecast)
Source: 2013 T YSP Schedule 3
2013 Ten-Year Site Plan Review
Page 62
Gainesville Regional Utilities (GRU)
Generation Resources
Fuel Diversity
Figure 44 shows GRU’s historic fuel mix for 2003 and 2012, and the projected fuel mix
for 2022. While the company has historically relied upon coal, natural gas was the dominant
fuel in 2012, producing 43.1 percent of energy, over coal’s contribution of 35.4 percent. All
forms of native fuel use, including natural gas, nuclear, and coal, are anticipated to decline as
purchased power is forecast to become the dominant fuel in 2022. A majority of this purchased
power is associated with a single renewable PPA with the Gainesville Renewable Energy Center,
a 100 MW biomass plant that utilizes wood and wood wastes for fuel.
Figure 44: GRU - Fuel Diversity (History & Forecast)
Source: 2013 T YSP Schedule 6
Planned Generation
GRU’s 2013 TYSP did not contain any planned generation additions. This is consistent
with the company’s 2012 TYSP, which also included no new generation through 2021.
2013 Ten-Year Site Plan Review
Page 63
Gainesville Regional Utilities (GRU)
Reserve Margin
GRU maintains a 15 percent reserve margin based on FRCC planning requirements.
Figure 45 displays the forecasted planning reserve margin for GRU through the planning period
for both seasons, including the effects of projected conservation activities. As shown in the
figure, GRU is a summer-peaking utility. As the figure below illustrates, GRU’s reserve margin
is forecasted to remain well above the minimum level throughout the planning period.
Figure 45: GRU - Seasonal Reserve Margin (Summer & Winter)
Source: 2013 T YSP Schedule 7
2013 Ten-Year Site Plan Review
Page 64
JEA
JEA, formerly known as Jacksonville Electric Authority, is a municipal electric utility,
and the state’s fifth largest TYSP utility, and is the largest generating municipal 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 JEA is a municipal utility, the Commission’s regulatory
authority is limited to safety, rate structure, territorial boundaries, bulk power supply, operations,
and planning.
Load and Energy Forecast
In 2012, JEA had approximately 420,600 customers, with annual retail energy sales of
11,540 GWh, or approximately 5.3 percent of the state of Florida’s NEL. Total number of
customers and annual energy consumption by customer class are below in Figure 46.
Figure 46: JEA - Number of Customers and Energy Usage by Class
Source: 2013 T YSP Schedule 2
Figure 47 illustrates the company’s historic and projected growth as a percentage of its
total number of customers and retail energy sales in 2003. Over the last ten years, JEA has
increased its number of customers by 13.7 percent, but retail energy sales have declined 3.8
percent. The company forecast growth for the entire planning period, with retail energy sales
exceeding the historic 2010 peak by 2019.
Figure 47: JEA - Customer and Retail Energy Sale Growth Since 2003
Source: 2013 T YSP Schedule 2
2013 Ten-Year Site Plan Review
Page 65
JEA
Seasonal Peak Demand & Annual Energy for Load
The following three graphs in Figure 48 show JEA’s historic peak demand for both the
summer and winter seasons, and net energy for load for the years 2003 through 2012. The
forecasted values are also shown through the current planning horizon, including the effect of the
utility’s DSM programs. Historic conservation data is not available, so only net firm demand
and net energy for load is shown for the previous ten years.
Figure 48: JEA - Seasonal Peak Demand and Annual Energy Consumption
(Historic & Forecast)
Source: 2013 T YSP Schedule 3
2013 Ten-Year Site Plan Review
Page 66
JEA
Generation Resources
Fuel Diversity
Figure 49 shows JEA’s historic fuel mix for 2003 and 2012, and the projected fuel mix
for 2022. Natural gas was the primary fuel on JEA’s system in 2012, contributing 46.9 percent
of energy. Coal is anticipated to become the dominant fuel by the end of the planning period,
with 43.2 percent system energy in 2022, with the next largest fuel source being the combined
category of interchange, non-utility generators, renewables, and other fuels. Petroleum coke,
classified as ‘other’ below, makes up a majority of this category for JEA.
Figure 49: JEA - Fuel Diversity (History & Forecast)
Source: 2013 T YSP Schedule 6
Planned Generation
JEA’s 2013 TYSP did not contain any planned generation additions. This is consistent
with the company’s 2012 TYSP, which also included no new generation through 2021.
2013 Ten-Year Site Plan Review
Page 67
JEA
Reserve Margin
JEA maintains a 15 percent reserve margin based on FRCC planning requirements.
Figure 50 displays the forecasted planning reserve margin for JEA through the planning period
for both seasons, including the effects of projected conservation activities. The impact of
demand response programs is also included in the figure below. As shown in the figure, JEA is a
winter-peaking utility and has sufficient reserve margin to meet projected customer demands for
both seasons throughout the planning period. The increase in reserve margin in 2019 is
associated with the expiration of a power sale with FPL from a jointly owned unit. FPL
anticipates this sale will expire at an earlier period, in 2017.
Figure 50: JEA - Seasonal Reserve Margin (Summer & Winter)
Source: 2013 T YSP Schedule 7
2013 Ten-Year Site Plan Review
Page 68
Lakeland Electric (LAK)
LAK is the municipal utility, and is the state’s third smallest TYSP utility. LAK is
owned and operated by the City of Lakeland. As LAK is a municipal utility, the Commission’s
regulatory authority is limited to safety, rate structure, territorial boundaries, bulk power supply,
operations, and planning.
Load and Energy Forecast
In 2012, LAK had approximately 113,100 customers, with annual retail energy sales of
2,612 GWh, or approximately 1.2 percent of the state of Florida’s NEL. Total number of
customers and annual energy consumption by customer class are below in Figure 51.
Figure 51: LAK - Number of Customers and Energy Usage by Class
Source: 2013 T YSP Schedule 2
Figure 52 illustrates the company’s historic and projected growth as a percentage of its
total number of customers and retail energy sales in 2003. Over the last ten years, LAK has
increased its number of customers by 6.1 percent, while retail energy sales have declined 0.3
percent. The company forecasts positive growth for all years of the planning period, with retail
energy sales exceeding the historic 2010 peak by 2014.
Figure 52: LAK - Customer and Retail Energy Sale Growth Since 2003
Source: 2013 T YSP Schedule 2
2013 Ten-Year Site Plan Review
Page 69
Lakeland Electric (LAK)
Seasonal Peak Demand & Annual Energy for Load
The following three graphs in Figure 53 show LAK‘s historic peak demand for both the
summer and winter seasons, and net energy for load for the years 2003 through 2012. The
forecasted values are also shown through the current planning horizon, including the effect of the
utility’s DSM programs. As LAK did not provide separate annual conservation data, only the
utility’s net firm demand and net energy for load are shown below.
Figure 53: LAK - Seasonal Peak Demand and Annual Energy Consumption
(Historic & Forecast)
Source: 2013 T YSP Schedule 3
2013 Ten-Year Site Plan Review
Page 70
Lakeland Electric (LAK)
Generation Resources
Fuel Diversity
Figure 54 shows LAK’s historic fuel mix for 2003 and 2012, and the projected fuel mix
for 2022. Natural gas was the primary fuel on LAK’s system, contributing 85.8 percent of
system energy. With a total of 12.2 percent of system energy as exports, coal made up the
remaining generation. Overall, natural gas is forecast to slightly decline along with exports,
while coal remains at a little over a quarter of system energy.
Figure 54: LAK - Fuel Diversity (History & Forecast)
Source: 2013 T YSP Schedule 6
Planned Generation
LAK’s 2013 TYSP did not contain any planned generation additions. This is consistent
with the company’s 2012 TYSP, which also included no new generation additions through 2021.
2013 Ten-Year Site Plan Review
Page 71
Lakeland Electric (LAK)
Reserve Margin
LAK maintains a 15 percent reserve margin based on FRCC planning requirements.
Figure 55 displays the forecasted planning reserve margin for LAK through the planning period
for both seasons, including the effects of projected conservation activities. As shown in the
figure, LAK is a winter-peaking utility for most years and has sufficient reserve margin to meet
projected customer demands for both seasons throughout the planning period.
Figure 55: LAK - Seasonal Reserve Margin (Summer & Winter)
Source: 2013 T YSP Schedule 7
2013 Ten-Year Site Plan Review
Page 72
Orlando Utilities Commission (OUC)
OUC is a municipal utility, and the state’s seventh largest TYSP utility. The utility’s
service territory is within the FRCC region, and serves the Orlando metropolitan area. As OUC
is a municipal utility, the Commission’s regulatory authority is limited to safety, rate structure,
territorial boundaries, bulk power supply, operations, and planning.
Load and Energy Forecast
In 2012, OUC had approximately 213,300 customers, with annual retail energy sales of
5,851 GWh, or approximately 3 percent of the state of Florida’s NEL. Total number of
customers and annual energy consumption by customer class are below in Figure 56.
Figure 56: OUC - Number of Customers and Energy Usage by Class
Source: 2013 T YSP Schedule 2
Figure 57 illustrates the company’s historic and projected growth as a percentage of its
total number of customers and retail energy sales in 2003. Over the last ten years, OUC has
increased its number of customers by 20.4 percent, and retail energy sales have increased by 7.3
percent. The company forecasts continued positive growth throughout the planning period, with
retail energy sales exceeding the historic 2008 peak by 2014.
Figure 57: OUC - Customer and Retail Energy Sale Growth Since 2003
Source: 2013 T YSP Schedule 2
2013 Ten-Year Site Plan Review
Page 73
Orlando Utilities Commission (OUC)
Seasonal Peak Demand & Annual Energy for Load
The following three graphs in Figure 58 show OUC’s historic peak demand for both the
summer and winter seasons, and net energy for load for the years 2003 through 2012. The
forecasted values are also shown through the current planning horizon. Figure 58 below includes
the effect of the utility’s DSM programs.
Figure 58: OUC - Seasonal Peak Demand and Annual Energy Consumption
(Historic & Forecast)
Source: 2013 T YSP Schedule 3
2013 Ten-Year Site Plan Review
Page 74
Orlando Utilities Commission (OUC)
Generation Resources
Fuel Diversity
Figure 59 shows OUC’s historic fuel mix for 2003 and 2012, and the projected fuel mix
for 2022. Natural gas is the primary fuel on OUC’s system in 2012, contributing 46.3 percent of
system energy. This is projected to decline to under a quarter of system energy by 2022, with
coal producing approximately two-thirds of system energy by the end of the planning period.
Figure 59: OUC - Fuel Diversity (History & Forecast)
Source: 2013 T YSP Schedule 6
Planned Generation
OUC’s 2013 TYSP did not contain any planned generation additions. This represents a
decrease from the company’s 2012 TYSP, which included a single combustion turbine.
2013 Ten-Year Site Plan Review
Page 75
Orlando Utilities Commission (OUC)
Reserve Margin
OUC maintains a 15 percent reserve margin based on FRCC planning requirements.
Figure 60 displays the forecasted planning reserve margin for OUC through the planning period
for both seasons, including the effects of projected conservation activities. As shown in the
figure, OUC is a summer-peaking utility and has sufficient reserve margin to meet projected
customer demands for both seasons throughout the planning period.
Figure 60: OUC - Seasonal Reserve Margin (Summer & Winter)
Source: 2013 T YSP Schedule 7
2013 Ten-Year Site Plan Review
Page 76
Seminole Electric Cooperative (SEC)
SEC is a generation and transmission rural electric cooperative that serves only wholesale
customers that purchase power from SEC under long-term wholesale power contracts, and is
collectively the state’s fourth largest TYSP utility. SEC is within the FRCC Region, with load
serviced throughout the State of Florida. Its generation assets are primarily within the central
region. As SEC is a rural electric cooperative, the Commission’s regulatory authority is limited
to safety, rate structure, territorial boundaries, bulk power supply, operations, and planning
Load and Energy Forecast
In 2012, SEC’s members had approximately 850,000 customers, with annual retail
energy sales of 14,387 GWh, or approximately 6.7 percent of the state of Florida’s NEL. Total
number of customers and annual energy consumption by customer class are below in Figure 61.
Figure 61: SEC - Number of Customers and Energy Usage by Class
Source: 2013 T YSP Schedule 2
Figure 62 illustrates the company’s historic and projected growth as a percentage of its
total number of customers and retail energy sales in 2003. Over the last ten years, SEC’s
member cooperatives had increased the number of customers by 12.3 percent and retail sales by
3.6 percent. The company forecasts a decline in 2014 due to the loss of Lee County Electric
Cooperative, which will purchase power from FPL. but otherwise positive annual growth over
the planning period, with retail energy sales exceeding the historic 2007 peak by 2021.
Figure 62: SEC - Customer and Retail Energy Sale Growth Since 2003
Source: 2013 T YSP Schedule 2
2013 Ten-Year Site Plan Review
Page 77
Seminole Electric Cooperative (SEC)
Seasonal Peak Demand & Annual Energy for Load
The following three graphs in Figure 63 show SEC’s historic peak demand for both the
summer and winter seasons, and net energy for load for the years 2003 through 2012. The
forecasted values are also shown through the current planning horizon. Figure 63 below includes
the effect of member cooperative’s DSM programs.
Figure 63: SEC - Seasonal Peak Demand and Annual Energy Consumption
(Historic & Forecast)
Source: 2013 T YSP Schedule 3
2013 Ten-Year Site Plan Review
Page 78
Seminole Electric Cooperative (SEC)
Generation Resources
Fuel Diversity
Figure 64 shows SEC’s historic fuel mix for 2003 and 2012, and the projected fuel mix
for 2022. SEC’s primary generation fuel is coal, with 49.2 percent of system energy generated
by coal. Coal usage has declined however, primarily with the increase of natural gas, which is
the next highest fuel for SEC’s system energy. Natural gas has risen to 44.4 percent of system
energy in 2012, up from only 14.4 percent in 2003. Coal is anticipated to remain the main
system fuel throughout the planning period, making up 52.5 percent in 2022, although natural
gas is projected to increase its share of system energy to 43.3 percent in 2022.
Figure 64: SEC - Fuel Diversity (History & Forecast)
Source: 2013 T YSP Schedule 6
Planned Generation
SEC’s 2013 TYSP includes a total of nine planned generating units, two combined cycles
and seven combustion turbines. With the exception of one of the combined cycle units, all are to
be sited at a location to be determined in Gilchrist County. The planned units are detailed below
in Table 22. This represents a decrease in the number and total capacity of generation additions
from the company’s 2012 TYSP, which included three combined cycle units and nine
combustion turbines.
Table 22: SEC - Planned Generation Additions
Generating Unit Name
Unnamed
Unnamed
Unnamed
Unnamed
Unnamed
Unnamed
Unnamed
Unnamed
Unnamed
CT
CC
CC
CT
CT
CT
CT
CT
CT
1
1
2
2
3
4
5
6
7
Generator Type
Natural
Combustion Turbine
Combined Cycle
Combined Cycle
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combustion Turbine
Combustion Turbine
Summer
Capacity (MW)
Gas Units
198
192
192
198
198
198
198
198
198
In-Service
Date
12/2019
12/2020
12/2020
12/2020
12/2020
12/2021
12/2021
12/2021
12/2021
PPSA
N/A
Required
Required
N/A
N/A
N/A
N/A
N/A
N/A
Source: 2013 T YSP Schedule 8
2013 Ten-Year Site Plan Review
Page 79
Seminole Electric Cooperative (SEC)
Reserve Margin
SEC is within the FRCC region and is required to meet a 15 percent reserve margin
requirement for planning purposes. Figure 65 displays the forecasted planning reserve margin
for SEC through the planning period for both seasons, including the effects of projected
conservation activities. The impact of demand response programs on reserve margin is also
included. As shown in the figure, SEC has sufficient reserve margin to meet projected customer
demands for both seasons throughout the period when including demand response.
Figure 65: SEC - Seasonal Reserve Margin (Summer & Winter)
Source: 2013 T YSP Schedule 7
2013 Ten-Year Site Plan Review
Page 80
City of Tallahassee Utilities (TAL)
City of Tallahassee Utilities (TAL)
TAL is a municipal utility, and the state’s second smallest TYSP utility. The utility’s
service territory is within the FRCC region, in Leon County, and primarily serves the City of
Tallahassee. As TAL is a municipal utility, the Commission’s regulatory authority is limited to
safety, rate structure, territorial boundaries, bulk power supply, operations, and planning.
Load and Energy Forecast
In 2012, TAL had approximately 115,000 customers, with annual retail energy sales of
2,604 GWh, or approximately 1.2 percent of the state of Florida’s NEL. Total number of
customers and annual energy consumption by customer class are below in Figure 66.
Figure 66: TAL - Number of Customers and Energy Usage by Class
Source: 2013 T YSP Schedule 2
Figure 67 illustrates the company’s historic and projected growth as a percentage of its
total number of customers and retail energy sales in 2003. Over the last ten years, TAL has
increased its total number of customers by 15.5 percent, while only increasing retail energy sales
by 0.1 percent. The company forecasts continued positive growth for the next ten years, with
retail energy sales exceeding the historic 2007 peak by 2017.
Figure 67: TAL - Customer and Retail Energy Sale Growth Since 2003
Source: 2013 T YSP Schedule 2
2013 Ten-Year Site Plan Review
Page 81
City of Tallahassee Utilities (TAL)
Seasonal Peak Demand & Annual Energy for Load
The following three graphs in Figure 68 show TAL’s historic peak demand for both the
summer and winter seasons, and net energy for load for the years 2003 through 2012. The
forecasted values are also shown through the current planning horizon, including the effect of
DSM. As seen below, TAL has a demand response program for summer peak demand, but not
for the winter period.
Figure 68: TAL - Seasonal Peak Demand and Annual Energy Consumption
(Historic & Forecast)
Source: 2013 T YSP Schedule 3
2013 Ten-Year Site Plan Review
Page 82
City of Tallahassee Utilities (TAL)
Generation Resources
Fuel Diversity
Figure 69 shows TAL’s historic fuel mix for 2003 and 2012, and the projected fuel mix
for 2022. TAL relies almost exclusively on natural gas for its generation, excluding some small
amount of purchases from other utilities. This dependency is anticipated to remain throughout
the planning period, with only natural gas-fired generation to be added, and purchases from other
utilities forecasted to decrease.
Figure 69: TAL - Fuel Diversity (History & Forecast)
Source: 2013 T YSP Schedule 6
Planned Generation
TAL’s 2013 TYSP includes a single generating unit addition at their existing Hopkins
plant site in Leon County. The unit is detailed below in Table 23. This represents an increase
over the company’s 2012 TYSP, which included no generation additions.
Table 23: TAL - Planned Generation Additions
Generating Unit Name
Hopkins 5
Summer
Capacity (MW)
Natural Gas Units
Combustion Turbine
46
Generator Type
In-Service
Date
5/2020
PPSA
N/A
Source: 2013 T YSP Schedule 8
2013 Ten-Year Site Plan Review
Page 83
City of Tallahassee Utilities (TAL)
Reserve Margin
TAL is within the FRCC region and is required to meet a 15 percent reserve margin
requirement. However, TAL has adopted an 18 percent planning reserve margin requirement.
Figure 70 displays the forecast planning reserve margin for TAL through the planning period for
both seasons including the effects of projected conservation activities. The impact of the utility’s
demand response programs, which are focused on summer demand only, is also included in the
summer reserve margin. As shown in the figure, TAL is a summer peaking utility and has
sufficient reserve margin to meet projected customer demands throughout the period when
including demand response.
Figure 70: TAL - Seasonal Reserve Margin (Summer & Winter)
Source: 2013 T YSP Schedule 7
2013 Ten-Year Site Plan Review
Page 84
APPENDIX A
Appendix A
Comments On The
2013 Ten-Year Site Plans
For Florida’s Electric Utilities
Florida Public Service Commission
Tallahassee, FL
October 2013
APPENDIX A
APPENDIX A
Ten-Year Site Plan Comments List
State Agencies
• Department of Economic Opportunity
• Department of Environmental Protection
• Department of Transportation
Regional Planning Councils
• Central Florida Regional Planning Council
• East Central Florida Regional Planning Council
• North Central Florida Regional Planning Council
• Northeast Florida Regional Planning Council
• Treasure Coast Regional Planning Council
Water Management Districts
• South Florida Water Management District
• Southwest Florida Water Management District
• St. John’s River Water Management District
• Suwannee River Water Management District
Local Governments
• Citrus County
Other Organizations
• Sierra Club and Earthjustice
APPENDIX A
APPENDIX A
State Agencies
• Department of Economic Opportunity
• Department of Environmental Protection
• Department of Transportation
APPENDIX A
Rick Scott
Jesse Panuccio
GOVERNOR
EXECUTIVE DIRECTOR
FLORIDA DEPARTMENT •/
ECONOMIC OPPORTUNITY
July 18, 2013
Mr. Phillip Ellis
Engineering Specialist Ill
Florida Public Service Commission
2540 Shumard Oak Boulevard
Tallahassee, Florida 32399-0850
Dear Mr. Ellis:
At your request we have reviewed the 2013 Ten-Year Site Plans ofthe electric utilities.
The Department of Economic Opportunity's review focused on potential sites for future power
generation, and the compatibility of those sites with the applicable local comprehensive plan,
including the adopted future land use map, adjacent land uses, and natural resources on or
adjacent to the potential sites.
Our review ofthe 2013 Ten-Year Site Plans addressed ten potential power plant sites
identified in the Ten-Year Site Plans ofthe following utilities: Florida Power & Light Company,
Gulf Power Company, and Seminole Electric Cooperative. None of the potential sites were
found to be incompatible with the applicable local comprehensive plan.
Should you have any questions regarding these comments, please call Scott Rogers,
Planning Analyst, at (850) 717-8510, or by email at [email protected] .myflorida .com.
r:zi"X t11 ~d~
Mike McDaniel
Comprehensive Planning Manager
MM/sr
Enclosure: Department Comments
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APPENDIX A
2013 Ten-Year Site Plan Review
Three utilities, Gulf Power, Florida Power and Light, and Seminole Electric, have identified a
total of ten potential sites for future power generation. Potential sites are identified in Rule 2522.070, F.A.C., as "sites within the state that an electric utility is considering for possible
location of a power plant, a power plant alteration, or an addition resulting in an increase in
generating capacity." These sites are discussed below.
1. Gulf Power
In its Ten-Year Site Plan, Gulf Power stated it will consider four properties as potential sites for
future generating facilities. Two potential sites contain existing power plants: Plant Crist site in
Escambia County and Plant Smith Site in Bay County. Two potential sites are undeveloped:
Caryville Site in Holmes and Washington Counties and North Escambia Site in Escambia County.
A. Plant Crist Site. This site, located in Escambia County, is designated Industrial and
Agriculture on the adopted Future land Use Map (FLUM). Electric power generation facilities
are an allowed use in the Industrial category and may be allowed as a conditional use in
Agriculture through the land Development Code. The northern and eastern parts of the site
are located in the coastal high hazard area and contain wetlands and 100-year floodplain.
Adjacent land uses are Industrial, Conservation, Agriculture, and Mixed-Use Suburban.
For information regarding the location of the coastal high hazard area relative to the site,
contact Julie Dennis with the Department of Economic Opportunity, Bureau of Comprehensive
Planning, at (850) 717-8478. For wetland compatibility issues, contact the Department of
Environmental Protection (DEP) Office of Submerged lands and Environmental Resources at
(850) 245-8474. For information on floodplain compatibility, contact the State of Florida
Floodplain Management Office at (850) 413-9960.
B. Plant Smith Site. located in Bay County, the Plant Smith site is adjacent to the North Bay
area of St. Andrews Bay. The site is located in the Category 1, 2, 3 and 4 storm surge zones. It
is designated Industrial and Conservation on the adopted FlUM. Public utilities are allowed
uses in both Industrial and Conservation. Adjacent land uses are Agriculture-Timber and
Conservation. Wetlands and 100-year floodplains are also located onsite.
For further information regarding the location of storm surge zones relative to the site, Gulf
Power should contact Julie Dennis with the Department of Economic Opportunity, Bureau of
Comprehensive Planning, at (850) 717-8478. For assistance with wetland compatibility issues,
contact the DEP Office of Submerged lands and Environmental Resources at (850) 245-8474.
For information on floodplain compatibility, contact the State of Florida Floodplain
Management Office at (850) 413-9960.
APPENDIX A
C. Caryville Site. The Caryville site is located in Holmes County, Washington County, and the
City of Caryville, and it is adjacent to t he Choctawhatchee River. The site is designated
Agriculture in Holmes County, Agriculture/Silviculture in Washington County, and Agriculture
and Conservation in Caryville. In all three jurisdictions, public utilities are allowed in areas
designated Agriculture. The site is su rrounded by agricultural land uses. Floodplain and
wetland areas exist throughout the site.
Gulf Power should contact the following DEP offices for further information: {1) for
compatibility with Outstanding Florida Waters, contact the Standards and Assessment section
at {850) 245-8064; and (2) for wetland compatibility issues, contact the Office of Submerged
Lands and Environmental Resources at (850) 245-8474. For information on floodplain
compatibility, contact the State of Florida Floodplain Management Office at {850) 413-9960.
D. Northern Escambia Site. The site is located in northern Escambia County, approximately five
miles southwest of the City of Century and west of the Escambia River. The Escambia County
Future Land Use Map designates the site predominantly as Agriculture with a very small part
designated as Rural Community. Elect ric power generation facilities may be allowed as a
conditional use in Agriculture and Rural Community through the land development code. The
site is surrounded predominantly by Agriculture future land uses and a small area of Rural
Community. The site and surrounding area are primarily used for timber harvesting and
agricultural use, and the site is in close proximity to transmission, natural gas pipelines, railroad,
major highways and access to water. The site contains a substantial amount of uplands with
some wetlands, and Mitchell Creek that traverses the site.
For information regarding wetland compatibility issues, contact the Department of
Environmental Protection Office of Submerged Lands and Environmental Resources at {850)
245-8474.
2. Florida Power and light. Florida Power and Light (FPL) has identified five potential sites as
described below.
A. Babcock Ranch, Charlotte County. This site is designated Babcock Ranch Overlay District
(BROD) on the FLUM. The Development Order for the Babcock Ranch Development of Regional
Impact (DRI) identifies this site as a Primary Active Greenway approved for the placement of
solar generating facilities. Adjacent land uses to the east, west and south are also BROD. Land
north of the site is designated Resource Conservation. The BROD is being developed under a
cohesive set of policies, guided by the County's comprehensive plan, through the Master
Incremental DRI process. No environmental or other compatibility issues have been identified
for this site.
B. DeSoto Solar Expansion, DeSoto County. This site is designated Electrical Generating Facility
on the County's adopted Future Land Use Map. The surrounding FLUM designations are
Electrical Generating Facility and Rural/ Agriculture. The site has been disturbed as a result of
agricultural activities on the property. The site is adjacent to an existing transportation corridor
APPENDIX A
with roadway capacity. Demands on water facilities have already been considered in the
growth projections ofthe County's comprehensive plan. No environmental or other
compatibility issues have been identified for this site.
C. Manatee Plan site, Manatee Count y. This site is designated Public/Semipublic-2 on the
adopted FLUM. Power generating facilities are an allowed use in this FLUM category. Adjacent
uses are Public/Semipublic-2 and Agricultural-Rural. The site is also adjacent to Lake Parrish,
which provides water to the existing power facility. Much of the property is disturbed due to
agricultural activities onsite. No environmental or other compatibility issues have been
identified for this site.
D. Martin County site. FPL is currently evaluating potential sites in Martin County for a future
solar facility. No specific locations have been selected. The County's adopted comprehensive
plan contains provisions for siting power generating facilities which use renewable energy
sources. Future Land Use Policy 4.8C.l allows alternative energy facilities in appropriate zoning
districts. The policy states that "As the technology for wind, solar and other forms of power
generation advance, the Land Development Regulations shall be revised to permit different
forms of power generation in appropriate zoning districts." Policy 4.13A.12, which addresses
the Public Utilities future land use category, states that "electrical power facilities solely
utilizing solar, wind or other renewable energy fuel or energy source may be permitted in any
other Future Land Use Designation, consistent with the Land Development Regulations."
For assistance with wetland compatibility issues, FPL should contact the Office of Submerged
Lands and Environmental Resources at (850) 245-8474. For information on floodplain
compatibility, contact the State of Florida Floodplain Management Office at (850) 413-9960.
E. Putnam County site. FPL is currently evaluating potential sites in Putnam County for a future
solar facility or natural gas-powered facility. No specific locations have been identified. Sites
currently under investigation are approximately 2,800 acres in area. The Industrial and
Community Facilities and Services land use categories allow electrical generating plants. The
County's Comprehensive Plan contain s policies that address compatibility and suitability of land
uses, as well as directing development away from environmentally sensitive lands.
3. Seminole Electric.
Seminole Electric has identified one site, a 350-acre parcel located northeast of the City Bell in
Gilchrist County, as a potential power plant site. Much of the site has been used for silviculture
(pine plantation) and consists of large t racts of planted longleaf and slash pine community. The
site is designated Agricultural on the adopted Future Land Use Map. Electric generating
facilities may be permitted as a special use in areas designated Agricultural. Issues that would
be considered by the County through the special use review process include the amount of
water projected to be used by the facility, the impact of water use on agricultural activities, and
the impact of the facility on natural resources, including aquifer recharge areas and wetlands.
The Gilchrist parcel is located near the Wacasassa Flats, a 50,000-acre high quality wetlands-to-
. .
'
.
APPENDIX A
uplands ecosystem located in the middle of the County. Wacasassa Flats is a perched water
table system that provides significant water storage, water filtering and wildlife habitat.
For assistance with wetland compatibility issues, Seminole Electric should contact the Office of
Submerged Lands and Environmental Resources at (850) 245-8474. For information on
floodplain compatibility, contact the State of Florida Floodplain Management Office at (850)
413-9960.
4. Utilities With No Potential Sites Identified in the TYSP: The following utilities identified no
potential sites in their TYSPs: Gainesville Regional Utilities, Progress Energy Florida, Lakeland
Electric, City of Tallahassee, Florida Municipal Power Agency, Tampa Electric Company, JEA, and
Orlando Utilities Commission.
APPENDIX A
From:
To:
Cc:
Subject:
Date:
Bull, Robert
Phillip Ellis
Mulkey, Cindy
DEP Siting Coordination Office Ten Year Site Plan Review
Monday, July 22, 2013 10:57:45 AM
The Department of Environmental Protection’s Siting Coordination Office (SCO) has
reviewed the 2013 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.
Thank you,
Bobby Bull, P.E.
Florida Department of Environmental Protection
Siting Coordination Office
2600 Blairstone Road, MS 5500
Tallahassee, FL 32399-2400
[email protected]
850/717-9111
Please take a few minutes to share your comments on the service you received from the department
by clicking on this link DEP Customer Survey.
APPENDIX A
RECEI,l;3:D
JUN 2 7 2013
BY:
Florida Department of Transportation
RICK SCOTT
GOVERNOR
605 Suwannee Street
Tallahassee, FL 32399-0450
ANANTH PRASAD, P.E.
SECRETARY
June 26, 2013
Phillip Ellis
Division of Regulatory Analysis
Public Service Commission
2540 Shumard Oak Boulevard
Tallahassee, FL 32399-0850
Dear Mr. Ellis:
The Siting Coordination Office has reviewed the ten-year site plans and find these are
suitable as planning documents. If you have any questions please feel free to call me at
(850)414-4572 .
Sincerely,
Connie Mitchell
Siting Coordination Office
www .dot.state.fl.us
APPENDIX A
APPENDIX A
Regional Planning Councils
• Central Florida Regional Planning Council
• East Central Florida Regional Planning Council
• North Central Florida Regional Planning Council
• Northeast Florida Regional Planning Council
• Treasure Coast Regional Planning Council
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
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: August 1, 2013
Subject: 2013 Ten-Year Site Plans Review
- Florida Power and Light
- Orlando Utilities Commission
- Progress Energy
The East Central Florida Regional Planning Council staff has completed a review of the 2013 Ten-Year Site
Plans for the agencies listed above. Staff comments to each utility are italicized below.
Florida Power and Light (FPL)
Staff finds the document to be suitable for planning purposes. Council staff will provide further comments on
environmental and regional impacts when new or modified units, projects or transmission lines are proposed
and additional data and information are provided.
Orlando Utilities Commission (OUC)
Staff finds the document to be suitable for planning purposes. Council staff will provide further comments on
environmental and regional impacts when new or modified units, projects or transmission lines are proposed
and additional data and information are provided.
Progress Energy Florida (PEF)
Staff finds the document to be suitable for planning purposes. Council staff will provide further comments on
environmental and regional impacts when new or modified units, projects or transmission lines are proposed
and additional data and information are provided.
If you require any further information or comments, please contact Tara McCue, AICP at [email protected] or
by phone at (407) 262-7772
Executive Committee
Chair
Melanie Chase
Gubernatorial Appointee
Seminole County
Vice Chair
Patty Sheehan
City Commissioner
City of Orlando
Secretary
Chuck Nelson
County Commissioner
Brevard County
Treasurer
Welton Cadwell
County Commissioner
Lake County
Serving Brevard, Lake, Orange, Osceola, Seminole, and Volusia Counties.
Member at Large
Cheryl L. Grieb
City Commissioner
City of Kissimmee
APPENDIX A
APPENDIX A
Serving
Alachua • Bradford
Central
Florida
Regional
Planning
Council
Columbia • Dixie • Gilchrist
Hamilton • Lafayette • Madison
Suwannee • Taylor • Union Counties
2009 NW 67th Place, Gainesville, FL 32653-1 603 • 352.955.2200
July 16, 2013
Mr. Phillip Ellis
Division ofRegulatory Analysis
Florida Public Service Commission
Capitol Circle Office Center
2540 Shumard Oak Blvd
Tallahassee, FL 32399-0850
RE:
Regional Review ofTen-Year Site Plan, 2013-2022
Seminole Electric Cooperative, Inc.
Dear Mr. Ellis:
Pursuant to Section 186.801, Florida Statutes, Council staffhas reviewed the proposed Ten-Year Site
Plan and provides the following comments.
The above-referenced ten-year site plan proposes to construct eight natural gas-powered electrical
generation stations by 2022 to be located within Gilchrist County. The combined summer electrical
generating capacity of the stations will be 1,770 megawatts, while the combined winter electrical
generating capacity of the stations will be 2,080 megawatts. The ten-year site plan notes that 385
megawatts of the summer generating capacity and 456 megawatts of the winter generating capacity will
be cooled by water using wet cooling towers with forced air draft fans .
The subject property of the Gilchrist County site is located adjacent to Waccasassa Flats, a Natural
Resource of Regional Significance as identified and mapped in the North Central Florida Strategic
Regional Policy Plan. Page IV-55 of the North Central Florida Strategic Regional Policy Plan notes the
following regarding Waccasassa Flats.
Occupying approximately 61,653 acres, Waccasassa Flats runs down the center of Gilchrist
County. The flats are part of a larger wetland system which runs into Levy County and the
Withlacoochee Regional Planning District. During the rainy season, waters in the aquifer build
up sufficient pressure to spill out of the many sinkholes and ponds scattered throughout the flats
to inundate the area.
The area is predominantly comprised of commercial pine plantation. Pine stands are interspersed
among numerous cypress ponds, depression marshes, hydric hammock, and other wetland
communities. Several lakes (the largest of which is 150 acres), small areas of upland hardwood
forest, sandhill, and other minor natural communities contribute to the diversity of the flats.
Applicable regional plan goals and policies include the following:
REGIONAL GOAL 4.7. Maintain the quantity and quality ofthe region's surface water systems
in recognition of their importance to the continued growth and development of the region.
Dedicated to impro v ing the quality of life of the Region ' s cit izens,
by coordinating growth management, protecting reg ional resources,
promoting economic development and providing technical services to local governments .
APPENDIX A
J
Letter to Mr. Phillip Ellis
Page2
July 16,2013
Policy 4.7.5. Use non-structural water management controls as the preferred water management
approach for rivers, lakes, springs, and fresh water wetlands identified as natural resources of
regional significance.
Policy 4.7.6. Support the coordination of land use and water resources planning for surface water
resources designated as natural resources of regional significance among the Council, local
governments, and the water management districts through regional review responsibilities,
participation in committees and study groups, and ongoing communication.
Policy 4.7.12. Ensure that local government comprehensive plans, DRis, and requests for federal
and state funds for development activities reviewed by the Council include adequate provisions
for storm water management, including retrofit programs for known surface water runoff problem
areas, and aquifer recharge protection in order to protect the quality and quantity of water
contained in the Floridan Aquifer and surface water systems identified as natural resources of
regional significance.
Policy 4.7.13. Work with local governments, state and federal agencies, and the local water
management districts in the review of local government comprehensive plans and developments
of regional impact as they affect wetlands identified as natural resources of regional significance
to ensure that any potential adverse impacts created by the proposed activities on wetlands are
minimized to the greatest extent possible.
The proposed electrical power generation site to be located in Gilchrist County will be consistent with the
regional plan provided the water consumption of the electrical generating stations does not result in
significant and adverse impacts to the wetland functions ofWacassassa Flats. However, the ten-year site
plan does not indicate the water source or the amount of water to be used to cool the electrical generating
stations. Additionally, the ten-year site plan does not provide an analysis of environmental impacts to
Wacassassa Flats of the withdrawal of groundwater used to cool the electrical generating units.
Therefore, it is recommended that the ten-year site plan include information on the water consumption of
the electrical generating stations as we!l as an analysis of envircmmental impacts to Wacassassa F!ats as a
result of their water consumption. Finally, it is recommended that an alternative environmental impact
analysis be provided whereby 100 percent ofthe electrical generation capacity ofthe site is cooled using
air.
If you have any questions concerning this matter, please do not hesitate to contact Steven Dopp, Senior
Planner of the Planning Council's Regional and Local Government Programs staff, at 352.955.2200,
extension 109.
Sincerely,
Scott R. Koons, AICP
Executive Director
v:\chouse\responses\20 12-13_ 60-docx
APPENDIX A
Serving
Alachua • Bradford
Central
Florida
Regional
Planning
Council
Columbia • Dixie • Gilchrist
Hamilton • Lafayette • Madison
Suwannee • Taylor • Union Counties
2009 NW 67th Place, Gainesville, FL 32653 -1 603 • 352. 955. 2200
REGIONAL CLEARINGHOUSE
INTERGOVERNMENTAL COORDINATION AND RESPONSE
Date:
7-16-13
PROJECT DESCRIPTION
#60-
Seminole Electric Cooperative, Inc., Ten-Year Site Plan 2013 -2022
TO:
_x_
Mr. Phillip Ellis
Division of Regulatory Analysis
Florida Public Service Commission
Capitol Circle Office Center
2540 Shumard Oak Blvd
Tallahassee, FL 32399-0850
COMMENTS ATTACHED
NO COMMENTS REGARDING TillS PROJECT
IF YOU HAVE ANY QUESTIONS REGARDING THESE COMMENTS, PLEASE CONTACT
STEVEN DOPP, SENIOR PLANNER, AT THE NORTH CENTRAL FLORIDA REGIONAL
PLANNING COUNCIL AT (352) 955-2200 OR SUNCOM 625-2200, EXT 109
Dedicated to improving the quality of life of the Reg ion's citizens,
by coordinating growth management, protecting regional resources,
promoting economic development and providing technical services to local governments.
APPENDIX A
Serving
Alachua • Bradford
Central
Florida
Regional
Planning
Council
Colurnbia • Dixie • Gilchrist
Harnilton • Lafayette • Madison
Suwannee • Taylor • Union Counties
2009 N\1\/ 67th Place, Gainesville, FL 32653 -1 603 • 352. 955. 2200
REGIONAL CLEARINGHOUSE
INTERGOVERNMENTAL COORDINATION AND RESPONSE
Date:
7-16-13
PROJECT DESCRIPTION
#58-
Progress Energy Florida, Inc. Ten-Year Site Plan, 2013-2023
TO:
Mr. Phillip Ellis
Division ofRegulatory Analysis
Florida Public Service Commission
540 Shumard Oak Blvd.
Tallahassee, FL 32399-0850
CO~ENTSATTACHED
__x_
NO COMMENTS REGARDING THIS PROJECT
IF YOU HAVE ANY QUESTIONS REGARDING THESE COMMENTS, PLEASE CONTACT
STEVEN DOPP, SENIOR PLANNER, AT THE NORTH CENTRAL FLORIDA REGIONAL
PLANNING COUNCIL AT (352) 955-2200 OR SUNCOM 625-2200, EXT 109
Ded icated to improvin g the quality of life of the Region ' s citizens,
by coordinating growth management, protecting regional resources,
promoting economic development and providing technical services to local governments .
APPENDIX A
Serving
Alachua • Bradford
Central
Florida
Regional
Planning
Council
Columbia • Dixie • Gilchrist
Hamilton • Lafayette • Madison
Suwannee • Taylor • Union Counties
2009 NW 67th Place, Gainesville, FL 32653 -1 603 • 352. 955. 2200
REGIONAL CLEARINGHOUSE
INTERGOVERNMENTAL COORDINATION AND RESPONSE
Date:
7-16-13
PROJECT DESCRIPTION
#59-
Gainesville Regional Utilities- 2013 Ten-Year Site Plan
TO:
Mr. Phillip Ellis
Division ofRegulatory Analysis
Florida Public Service Commission
540 Shumard Oak Blvd.
Tallahassee, FL 32399-0850
CO~ENTSATTACHED
___x_
NO COMMENTS REGARDING THIS PROJECT
IF YOU HAVE ANY QUESTIONS REGARDING THESE COMMENTS, PLEASE CONTACT
STEVEN DOPP, SENIOR PLANNER, AT THE NORTH CENTRAL FLORIDA REGIONAL
PLANNING COUNCIL AT (352) 955-2200 OR SUNCOM 625-2200, EXT 109
Dedicated to improving the quality of life of the Region's citizens,
by coordinating growth management, protecting regional resources,
promoting economic development and providing technical services to local governments.
APPENDIX A
Ref!ional
Coun<:il
Bringing Communities Together
Baker • Clay • Duval •
Fla~ler
• Nassau • Putnam • St. johns
June 7, 2013
Ms. Jeanette Sickel
Florida Public Service Commission
Division of Economic Regulation
2540 Shumard Oak Blvd.
Tallahassee, FL 32399-0850
Dear Ms. Sickel:
Please find attached the Northeast Florida Regional Council's review for JEA's ten-year
site plan.
JEA Ten-year Site Plan: The ten-year site plan, as required by Section 186.801 of the
Florida Statutes (F.S.), was reviewed by the Northeast Florida Regional Council staff.
Action taken: Staffs review was approved by the Council and authorized for
transmittal to the Florida Public Service Commission.
If you have any further requests or questions, please contact Ms. Ameera Sayeed, Senior
Regional Planner, (904) 279-0885, ext. 151 or [email protected]
Edward Lehman
Director of Planning & Development
Attachment
RECEIVED
JUN 21 Z013
EL/ag
BY:
6850 Be lfort Oaks Place • j ackso nvi ll e, FL 322 16 • (904) 279-0880 • Fax (904) 279-088 1 • Sun com 874-0880 • Sunco m fax 874-088 1
WEB SIT[: www. nefrc.arQ • EMAIL: [email protected] rQ
Eout
0PPORTL
vm
fi1PLOltR
APPENDIX A
ReQional
council
Brlnfllnfl Communities Toflether
Baker • Clay • Duval • Flagler • Nassau • Putnam • St. Johns
MEMORANDUM
DATE:
May 31,2013
TO:
Northeast Florida Regional Council
THRU:
FROM:
Planning and Growth Management Policy Committee
!()
fr>
Ameera F. Sayeed, GISP, Senior Regional Planner
RE:
Review of JEA Ten-Year Power Plant Site Plan 2013-2022
Introduction
Each year every electric utility in the State of Florida produces a ten-year site plan that includes
an estimate of future electric power generating needs. The purpose of the ten-year site plan is to
disclose the general location of proposed power plant sites and facilitate coordinated planning
efforts. Pursuant to Section 186, Florida Statues, Council staff reviewed the most recent ten-year
site plan prepared by the Jacksonville Electric Authority (JEA). The purpose of this report is to
summarize JEA's plans for future power generation and provide comments for transmittal to the
Florida Public Service Commission (Commission).
Statutory Authority
Section 186.801, Florida Statutes, requires that all major generating electric utilities in Florida
submit a Ten-Year Site Plan to the Commission for review. Each Ten-Year Site Plan contains
projections of the utility's electric power needs for the next ten years and the general location of
proposed power plant sites and major transmission facilities. In accordance with the statute, the
Commission performs a preliminary study of each Ten-Year Site Plan and must determine
whether it is "suitable" or "unsuitable". In conducting its review, the Commission considers the
views of appropriate local and state agencies. The Northeast Florida Regional Council reviews
electric utility Ten-Year Site Plans within the region and submits comments to the Commission
for review. The Commission forwards the Ten-Year Site Plan review, upon completion, to the
Florida Department of Environmental Protection (DEP) for use in subsequent power plant siting
proceedings. To fulfill the requirements of Section 186.801, Florida Statutes, the Commission
has adopted Rules 25-22.070 through 25-22.072, Florida Administrative Code. Electric utilities
must file the Ten-Year Site Plan by April 1st.
APPENDIX A
Board Memorandum
May 31, 2013
Purpose
The intent of the Ten-Year Site Plans is to give state, regional, and local agencies advance notice
of proposed power plants and transmission facilities. However, the Ten-Year Site Plans are not a
binding plan of action on electric utilities. As such, the Commission's classification of a TenYear Site Plan as suitable or unsuitable has no binding effect on the utility. Such a classification
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. Because the Ten-Year Site Plans are planning documents containing tentative data, they
may not contain sufficient information to allow regional planning councils, water management
districts, and other reviewing agencies to evaluate site-specific issues within their jurisdictions.
Each utility is responsible for providing detailed data, based on in-depth environmental
assessments, during Power Plant Siting Act or Transmission Line Siting Act certification
proceedings.
Summary of the Plan
JEA is the seventh largest municipally owned electric utility in the United States in terms of
number of customers. JEA's electric service area covers most of Duval County and portions of
Clay and St. Johns counties. JEA's service area covers approximately 900 square miles and
serves approximately 420,000 customers. The evaluation has revealed that JEA has included in
this ten-year plan the necessary analysis. The existing JEA electric supply resources, forecasts of
customer energy requirements and peak demands, forecasts of fuel process and availability, and
an analysis of alternatives for resources that would meet JEA's future capacity and energy needs
were reported in the ten-year plan. JEA forecasts accounted for the system peak demand growth
and energy consumption resource plan; in addition to cost considerations, environmental and
land use considerations were amply factored into the ten-year plan. JEA had provided population
estimates in previous ten-year site plans and it appears that the current plan no longer includes
the population forecast and accompanying discussion.
JEA consists of three separate entities: The JEA Electric system, the St. Johns River Power Park
and the Robert W. Scherer system. Collectively, these plants consist of two dual-fired (petroleum
coke/coal) Circulating Fluidized Bed steam turbine-generator units (Northside steam Units 1 and
2); one dual-fired (oil/gas) steam turbine-generator unit (Northside steam Unit 3); five dual-fired
(gas/diesel) combustion turbine-generator units (Kennedy GT1 and GT8, and Brandy Branch
GTI, CT2, and CT3); two natural gas-fired combustion turbine-generator units (GEC GT1 and
GT2); four diesel-fired combustion turbine-generator units (Northside GTs 3, 4, 5, and 6); and
one combined cycle heat recovery steam generator unit (Brandy Branch steam Unit 4). The St.
Johns River Power Park (SJRPP) is jointly owned by JEA (80 percent) and Florida Power and
Light (FPL) (20 percent). SJRPP consists of two nominal 638 MW bituminous coal fired units
located north of the Northside Generating Station in Jacksonville, Florida.
Nuclear Generation
In March 2008, JEA approved the policy of pursuing nuclear energy partnerships with the goal
of providing 10 percent of JEA' s power from nuclear sources. In June 2008, JEA entered into a
purchase power agreement with the Municipal Electric Authority of Georgia (MEAG) for a
portion of MEAG's entitlement to the Vogtle Units 3 and 4, which are proposed new nuclear
units. These two new nuclear units are under construction at the existing Plant Vogtle location in
2
\\fs2\global\Planning and Growth Management\Planning\Power Site Plan reviews\2013VEA 2013 .doc
APPENDIX A
Board Memorandum
May 31,2013
Burke County, GA. JEA is entitled to net firm capacity of206 MW from the proposed units. JEA
assumes they will have available capacity beginning in the year 2017 from Unit 3 and additional
capacity from Unit 4 beginning in the year 2018.
Clean Power and Renewable Energy
JEA has pursued several clean power initiatives and is in the process of evaluating potential
renewable energy resources. JEA has worked with the Sierra Club of Northeast Florida, the
American Lung Association and local environmental groups to establish a process to maintain an
action plan entitled "Clean Power Action Plan". This Plan includes an advisory Panel that is
comprised of community representatives. Also, JEA has included in their review and planning
installation of solar photovoltaic, solar thermal, landfill and wastewater treatment biogas
capacity and wind capacity. Progress has extended to include installation of clean power
systems, unit efficiency improvements, commitment to purchase power agreements (including
nuclear power), legislative and public education activities, and research into and development of
clean power technologies.
Solar
JEA has installed 35 solar PV systems, totaling 222 kW, on public high schools in Duval
County, as well as many of JEA's facilities, and the Jacksonville International Airport. JEA
implemented the Solar Incentive Program in early 2002. This program continues to provide
rebates for the installation of solar thermal systems. In addition to the solar thermal system
incentive program, JEA established a residential net metering program to encourage the use of
customer-sited solar PV systems, which was revised as the Tier 1 & 2 Net Metering policy in
2009, to include all customer-owned renewable generation systems up to and equal to 100 kW.
In 2011, JEA established the Tier 3 Net Metering Policy for customer-owned renewable
generation systems greater than 100 kW up to 2 MW. JEA signed a purchase power agreement
with Jacksonville Solar, LLC in May 2009 to provide energy from a 15.0 MW DC rated solar
farm, which began operation in summer 2010.
Landfill
JEA owns three internal combustion engine generators that are fueled by the methane gas
produced by the landfill. JEA also receives landfill gas from the North landfill, which is fed to
the Northside Generating Station and is used to generate power at Northside Unit 3.
Wind
JEA purchases 10MW of wind capacity from NPPD's (Nebraska Public Power District) and in
tum the NPPD buys back the energy at specified on/off peak charges. JEA receives
environmental credits associated with green projects. JEA entered into a 20-year agreement with
Nebraska Public Power District to continue to participate in the wind generation project located
in Ainsworth, Nebraska.
Biomass
JEA owns three internal combustion engine generators located at the Girvin Road landfill. This
facility was placed into service in July 1997, and is fueled by the methane gas produced by the
landfill. The facility originally had four generators, with an aggregate net capacity of 3 MW. Gas
3
\\fs2\global\Planning and Growth Management\Planning\Power Site Plan reviews\20 13\JEA 2013 .doc
APPENDIX A
Board Memorandum
May31,2013
generation has declined, and one generator was removed and placed into service at the Buckman
Wastewater Treatment facility.
In 2011, JEA started a co-firing biomass in the Northside Units 1 and 2, utilizing wood chips
from JEA tree trimming activities as a biomass energy source. Northside 1 and 2 has produced a
total of 2,154 MWh of energy from wood chips during 2011 and 2012. JEA has received bids
from local sources to provide sized biomass for potential use for Northside Units 1 and 2.
Plug-in Electric Vehicle Peak Demand
In 2012, JEA developed the PEV demand and energy forecast for the service territory using the
2011 information from the Electric Power Research Institute (EPRI), the Edison Electric Institute
(EEi), the U.S. Census Bureau, and the Bureau of Economic and Business Research (BEBR).
JEA's baseline forecast of the numbe:- ef p!ug-irr vehicles in the area was determined from
BEBR's forecasted population growth rate, the U.S. Census Bureau's 2010 estimated number of
vehicles, and EPRI' s forecasted low scenario PEV penetration rate. JEA forecasted the average
usable battery capacity per vehicle using the upcoming plug-in vehicle model rollouts from
Toyota, Honda, Ford, and General Motors, and grew the capacity by 1 kWh per year. The
baseline forecast assumed that charging would initially be uncontrolled at home until the mid2020s when public infrastructure became feasible and available. When comparing Pike's 2012
PEV forecasted vehicle sales with JEA's 2012 forecast, JEA's baseline projections were 63
percent higher than Pike. Because of this difference, JEA shifted the start of its PEV forecast
back 5 years to 2017. Because Pike did not provide forecast data for Duval County, JEA
maintained the previously forecasted annual increases.
Staff Evaluation
The JEA forecasts are much more statistically sound. In the past JEA used regression analyses,
which would not necessarily account for statistical anomalies. To address the variability, in
recent year with the demand, JEA also used historical data, growth rates and established
regression analyses for the 13-year progression to establish periods of economic downturn and
prerecession periods. JEA forecasted the Net Energy Load to increase at an average of 1.17
percent per year during the last ten-year period. JEA views demand to decline in 2012 and hence
over the 13 years the average annual growth rate for total energy is expected to be at 0.73 percent
and 0.49 percent for net energy.
Council staff supports JEA and the State of Florida's efforts to continue to develop new
programs to: 1) reduce the reliance on coal and oil as energy sources; 2) increase conservation
activities to offset the need to construct new power plants; and 3) plan to develop an
environmentally sound power supply strategy that may provide reliable electric service at the
lowest practical cost.
Recommendation
Staff recommends that the Committee and Council approve this report and authorize its
transmittal to the Florida Public Service Commission.
4
\\fs2\global\Planning and Growth Management\Planning\Power Site Plan reviews\2013VEA 2013 .doc
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
Water Management Districts
• South Florida Water Management District
• Southwest Florida Water Management District
• St. John’s River Water Management District
• Suwannee River Water Management District
APPENDIX A
SOUTH fLORIDA WATER MANAGEMENT DISTRICT
June 28, 2013
Mr. Phillip Ellis
Engineering Specialist Ill
Division of Engineering
Florida Public Service Commission
2540 Shumard Oak Boulevard
Tallahassee, Florida 32399-0850
RF-C~~ T~""'lVED
JUL 0 2 2013
BY:
Dear Mr. Ellis:
Subject:
2013 Ten-Year Site Plans for Florida Electric Utilities
Thank you for your May 21, 2013 letter requesting that the South Florida Water
Management District (District) review the 2013 Ten-Year Site Plans for the Florida
Power & Light Company (FPL), Progress/Duke Energy Florida (DEF), and Tampa
Electric Company (TECO). The District has completed its review of the site plans.
The ten-year site plans provided by DEF and TECO do not include existing or proposed
facilities within the boundaries of the District. The District forwards no comments
regarding these proposed sites.
The District finds the ten-year site plan provided by FPL suitable as a planning
document. The District offers the following comments to assist electric utilities with
ongoing planning .
In planning for siting future facilities, utilities should recognize that water availability is
limited in specified areas by the District's Restricted Allocation Area rule. The criteria
associated with the Restricted A!!ocation Area Rule can be found in Section 3.2 .1 of the
Basis of Review for Water Use Permit Applications within the South Florida Water
Management District (October 23, 2012).
For assistance or additional information, please contact John Morgan, Lead Policy
Analyst, at (561) 682-2288 or [email protected] .gov.
Sincerely,
Sharon M. Trost, P.G. , AICP
Director, Regulation Division
South Florida Water Management District
SMT/jm
3301 Gun Club Road, West Palm Beach, Florida 33406 • (561) 686-8800 • FL WATS 1-800-432-2045
Mailing Address: P. 0. Box 24680, West Palm Beach, FL 33416-4680 • www.sfwrnd.gov
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
Bryan K. Beswick
DeSoto, Hardee, Highlands
Thomas E. Bronson
Hernando, Marion
Jennifer E. Closshey
Hillsborough
Wendy Griffin
Hillsborough
George W. Mann
Polk
Vacant
Charlotte, Sarasota
Vacant
Citrus, Lake, Levy, Sumter
Blake C. Guillory
Executive Director
June 11, 2013
Mr. Phillip Ellis, Engineering Specialist III
Division of Engineering
Florida Public Service Commission
2540 Shumard Oak Boulevard
Tallahassee, FL 32399-0850
Subject: Electric Utility 2013 Ten-Year Site Plans
Dear Mr. Ellis:
In response to your request, the Southwest Florida Water Management District
(District) has completed its review of the 2013 Ten-Year Site Plans (Site Plan) for
Progress/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.”
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 two new combined cycle units are proposed in 2018 and 2020 at undesignated
sites. The Site Plan for TECO indicates that conversion of the Polk Power
Station’s simple cycle combustion turbines (Units 2-5) to a natural gas combined
cycle unit is currently undergoing site certification review and is proposed for 2017.
The Site Plan for TECO also indicates that a new combustion turbine is proposed
in 2020 at an undesignated site.
With the exception of the TECO Polk Power Station Units 2-5 project, which is
currently undergoing site certification review, no information was provided for the
other TECO project and the two DEF projects concerning identification of the
proposed project sites, water sources, and water demands. Without this
information, the District’s ability to comment on the “suitability” of the Site Plans is
extremely limited.
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.
APPENDIX A
Mr. Phillip Ellis, Engineering Specialist III
June 11, 2013
Page 2
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 of 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 restrictions. 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 lake levels
and reduced stream flows, which have been caused by excessive ground water
withdrawals. Regional recovery strategies are being implemented to address the
adverse water resource impacts. Consequently, the District has heightened concerns
regarding potential impacts due to future groundwater demands and availability within
these areas.
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
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
Local Governments
• Citrus County
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
APPENDIX A
Other Organizations
• Sierra Club and Earthjustice
APPENDIX A
Mr. Phillip O. Ellis
Strategic Analysis & Government Affairs
Public Service Commission
2540 Shumard Oak Boulevard
Tallahassee, FL 32399-0850
[email protected]
CC: Traci Matthews
[email protected]
Re: Comments on 2013 Ten-Year Plan Submittals
Dear Mr. Ellis and Ms Matthews:
Thank you for accepting these comments on behalf of the Sierra Club and its nearly 27,000 Florida
members and on behalf of Earthjustice. We appreciated the opportunity to participate in the Public
Service Commission (PSC)’s Ten-Year Plan review process in 2012, and are happy to continue our
participation this year.
In last year’s comments,1 we asked that the PSC consider the implications of the retirement of Duke
(then Progress) Energy’s Crystal River Units 1 & 2, and of Gulf Power’s Lansing Smith Units 1 & 2.
We advised the PSC that the units had significant environmental compliance obligations which
rendered them noneconomic to run in the near-term, but that neither company had included full
analysis of that possibility in its submittal.
We appreciate that the PSC addressed these retirement issues in its review of the 2012 plans. See, e.g.,
PSC, Review of the 2012 Ten-Year Site Plans (“2012 Review”) at 3. We respectfully submit that that
analysis should continue in further depth this year because both utilities have now confirmed our
retirement predictions from last year. Duke has committed to retiring Crystal River 1 & 2 for
economic reasons and Gulf, though it has not made a final decision, has deferred further
environmental compliance work on Lansing Smith and has requested PSC approval for transmission
upgrades which would allow for Lansing Smith 1 & 2 to shut down.
In its review, the PSC assumed that the capacity of these retiring units would be replaced by natural
gas, which would increase natural gas’s share in Florida’s electric generation to 62.9% by 2022 (up
from 56.7% without the retirements, and from 57.7% in 2011). Id. The PSC states that it views “the
growing lack of fuel diversity” within Florida as a “major strategic concern.” Id. at 39. Although we
certainly welcome the retirements of these dangerous coal plants, we share this fuel diversity
concern: Undue dependence on natural gas leaves the state overly vulnerable to fuel price volatility,
even as potential LNG exports and other shifts in the gas market seem likely to increase gas prices in
the medium term. For this reason, we strongly suggest that the PSC consider planning scenarios
which employ other, less risky, resources to make up some or all of the share of generation now
served by the retiring plants.
1
Attached as Exhibits 1 & 2, for your reference.
1
APPENDIX A
In particular, we believe that demand-side management measures, including energy efficiency, other
demand response programs, and demand-side renewable energy, can make up a significant portion
of any resource gap left by the likely retirements. Increased supply side renewable energy can also
increase the diversity of the state’s resource mix. Because the PSC will be considering new goals for
both Duke and Gulf under the Florida Energy Efficiency and Conservation Act (FEECA) this year,
this is a particularly good time to develop the data needed for sensible planning.
I.
Coal Retirements
Both Duke and Gulf have confirmed that retirement is likely in the cards for their economically
vulnerable plants, though Duke has gone further and confirmed that Crystal River 1 & 2 will
certainly retire. Duke appears to be planning to address these retirements largely through adding
new generating capacity. Gulf intends to rely on power imports in the near term.
Duke/Progress
Duke has confirmed “expected retirement of Crystal River 1 & 2 in 2016.” Duke TYSP at 3-2. As
Duke explains in testimony filed in the Environmental Cost Recovery Docket, the lifecycle projected
system cost for retiring units 1 & 2 is far lower than the cost of retrofitting the units to comply with
environmental compliance obligations: The difference between the retirement and retrofit scenarios
is $ 1.32 billion in Duke’s base case analysis; retrofit is unfavorable only in the extremely unlikely
case of very high gas prices and no CO2 regulation. Direct Testimony of Benjamin M. H. Borsch on
Behalf of Progress Energy Florida (Apr. 1, 2013) at 4, Docket No. 130007-EI; see also Progress
Energy Florida, Review of Integrated Clean Air Compliance Plan (Apr. 1, 2013) (“Duke Compliance Plan”) at
25-26.
To be sure, Duke has held out the option of making short-term fuel mix adjustments which might
allow the units to continue operating, perhaps as long as 2020. Duke Compliance Plan at 21.
Continued operation would plainly be economically imprudent. As we demonstrated in our
comments and workshop presentation on last year’s plan, and as the figure below shows, the Crystal
River units already verge on noneconomic when compared even against the substantial expense of
constructing a new combined cycle natural gas plant to replace their capacity, much less against
more sensible options, including demand side programs.2
This figure is drawn from our 2012 workshop presentation and is based on work by Synapse Energy Economics, using
public cost estimates from the Energy Information Administration’s cost reporting forms and the EPA’s Integrated
Planning Model, developed by Sargent & Lundy.
2
2
APPENDIX A
Because Crystal River 1 & 2 are uneconomic by almost any measure (as Duke acknowledges), the
pertinent question is how best to replace any portion of their 965 MW in nameplate capacity which
will be required going forward. (In practice, this lost capacity is smaller: both units have been
relatively little used in recent years.) Lost capacity from the 860 MW Crystal River 3, the retired
nuclear unit at the site, will also play a substantial role in system planning, of course.
Over the period from 2013 to 2022, Duke expects its firm summer peak demand to grow by 1287
MW, TYSP at 3-7, and increase of just shy of 15% over the next decade, or about 1.5% per year. At
present, Duke reports that it intends to make up necessary capacity to match this growth through
“planned power purchases from 2016 through 2020 and planned installation of combined cycle
facilities in 2018 and 2020 at undesignated sites.” Id. at 3-2. According to Duke, these energy
imports are likely to grow an additional 1470 MW above its current ~ 1900 MW of imported
capacity, id. at Schedule 7.1. The addition of a 1307 MW (winter capacity) combined cycle facility in
2018, and a second 1307 MW facility in 2020 then replaces these imports. See id. at 3-7, 3-10 – 3-11.
This additional capacity is 764 MW greater than the capacity which Duke is losing, leading to a 21%
reserve margin by 2022.
As we discuss below, Duke’s strategy of increasing its built generating capacity substantially in
response to projected growth, and relying on natural gas generation to do so, is not the prudent one
for either the company or for Florida.
3
APPENDIX A
Gulf Power
As the figure above indicates, Lansing Smith 1 & 2 are even less economically attractive to operate
than the uncontrolled Crystal River coal units. Gulf has not yet committed to retirement publicly,
but its filings in this docket and in the Environmental Cost Recovery docket make clear that it is
preserving that option.
Specifically, Gulf has requested the PSC approve a $77 million transmission upgrade project, which
it explains is necessary to ensure that Lansing Smith is not a must run unit. Gulf Power, Third
Supplemental Petition of Gulf Power Company Regarding its Environmental Compliance Program, Docket No.
13007-EI (Mar. 29, 2013) at 8. According to Gulf, these upgrades will allow Plant Smith to run at
lower levels or to close, and would be “required if these units retire or are controlled as a result of
[the mercury and air toxics rule].” Id. at 8. Gulf, thus, maintains that it intends to “reserve the
decision to install … controls or to retire the two units for a future time when more is known with
regard to costs of compliance requirements associated with additional environmental regulations.”
Id.
Because Gulf Power – unlike Duke – has not shared cost information with the public comparing the
cost of controlling versus retiring the plant, see Gulf Power, Environmental Compliance Program
Update, Docket No. 13007-EI (Mar, 29, 2013) at 22-27, it is clear that it anticipates considerable
additional compliance obligations at Plant Smith, including additional air, water, and waste rules. Id.
at 22. Although Gulf has not provided economic analysis of a retirement option, it is clear that
operating costs from the mercury rule alone would “greatly increase the variable operating cost of
Smith Units 1 and 2,” id. at 23, enough so that spending $77 million on transmission to reduce the
operating need for the plant is more economic than continuing to run it, id. at 26.
We certainly agree that it is better to run Plant Smith less. The truth, however, is that Plant Smith is
not economic to run at all under current conditions. It is certainly not economic to run going
forward as environmental compliance costs increase. The appropriate course for Gulf Power is to
retire the facility, rather than simply building transmission which will allow it to operate the costly
plant somewhat less. Its transmission project, apparently, will enable that retirement, which remains
an option. We urge the PSC to continue to analyze retirement possibilities.
In this regard, Gulf’s Ten Year Site Plan submission does not clearly discuss all the implications of
Plant Smith. It acknowledges, again, that “potential incremental capital expenditures for compliance
may be substantial,” Gulf TYSP at 3, but does not yet appear to provide a straightforward
retirement analysis. Gulf anticipates 575 MW in summer peak demand growth by 2022 (about 20%
growth over that period, or, according to Gulf, a 1.9% annual increase over the next decade). See
Gulf TYSP at Schedule 3.1.
Gulf’s plan indicates that capacity additions are not necessary to manage this projected growth. Gulf
reports that a power purchase agreement (PPA) which it has signed with Shell Energy for use of 885
MW of capacity from an existing gas combined cycle plant will meet its needs through 2023, after
which it will construct additional in-system capacity. Id. at 2-3. For this reason, the PSC’s projection
last year that Lansing Smith’s retirement will lead to gas generation increases in Florida appears to be
incorrect in the near term. As with Crystal River’s retirement, however, we believe that demand-side
4
APPENDIX A
options and other non-gas resources should be emphasized to meet any capacity needs that
eventually arise.
II.
Implications for the Ten-Year Plan and FEECA Goal-Setting Processes
Because the PSC will shortly move fully into the FEECA goal-setting process for the next five years,
this is a particularly appropriate time to consider alternate futures for the Duke and Gulf power
networks, with an emphasis on resources which the Legislature designed FEECA to encourage. The
cost of adding new fossil capacity will almost always be higher than the cost of demand-side
measures. The savings possible through an efficiency-focused strategy, coupled with efficiency’s
potential to help Florida avoid the undue dependence on natural gas which the PSC is seeking to
avoid, argue strongly for a careful analysis of these questions in this year’s Ten-Year Site Plan
Review.
The Legislature has determined that it is “critical to utilize the most efficient and cost-effective
demand-side renewable energy systems and conservation systems in order to protect the health,
prosperity, and general welfare of the state and its citizens.” Section 366.81, F.S. A study
commissioned by the Legislature this past year confirmed these findings, concluding that “FEECA
appears to provide a positive net benefit to ratepayers.” Galligan et al., Evaluation of Florida’s Energy
Efficiency and Conservation Act (Dec. 7, 2012) (“FEECA Study”) at 9.
Despite these benefits, the PSC has, in the past, opted to suspend further program expansion for
Duke and FPL, on cost grounds. See, e.g., Re: Progress Energy Florida, Inc., Docket No. 1000160-EG,
2001 WL 3659327 (Aug. 6, 2011). The PSC should revisit this position during this year’s goalsetting process in view of the positive findings of the legislative study, and the pressing need to
address the retirements of vulnerable coal units in ways that best protect the ratepayers from further
risk from fossil fuel price shifts and regulatory uncertainty. Ratepayers will face costs associated
with new capacity and loss of fuel supply diversity which are far greater than those imposed by
demand-side programs --- programs which the legislative study have determined have net benefits.
In particular, the PSC should view with skepticism Duke’s proposal to construct 2614 MW of
natural gas generation in just the next few years in order to cope with a 1.5% annual average growth
rate in its predicted demand. Initially, Duke has a history of significant positive errors in its
forecasts. As the PSC explained in its 2012 Ten Year Site Plan Review, Duke overestimated net
energy for load forecasts by 11.36% on average between 2007 and 2011, and by 6.17% between
2006 and 2010. 2012 Review at 19. Certainly the recession contributed to some of this overage, but
the size of the error should give the PSC pause.
More importantly, however, the 1.6% demand growth rate which Duke forecasts, even if accurate, is
within the range of load growth rates which demand-side management can address. According to
the legislative FEECA study, many states require annual reductions far greater. See FEECA Study at
177-180. States requiring savings of at least 1% a year, according to that study, include Arizona,
Indiana, Maine, Maryland, Michigan, Minnesota, New York, Ohio, and Texas, with many other
states not far behind (still other states, including California, are listed as having very large reduction
goals, but a percentage reduction is not specified). See id. Such reduction rates would entirely offset
Duke’s projected load growth, obviating the need for much, if not all, of its projected capacity needs
in light of the Crystal River retirements.
5
APPENDIX A
Duke plainly has the potential to greatly expand its programs. It reports that only 25% (405,000
customers out of 1.6 million) take part in its demand response program, for instance. Duke TYSP at
1-1. This low participation is likely one reason that Duke is well below its FEECA goals for
summer MW and annual GWh reductions – missing the annual target by more than 60%. See PSC,
Annual Report on Activities Pursuant to [FEECA] (Feb. 2013) at 19. Duke has told the PSC that it was
unable to reach its performance levels because “of the Commission decision to not approve a new
DSM plan” for the company. Id. at 20. Thus, if the PSC engages with Duke to approve an improved
plan, Duke may well be able to increase efficiency programs sufficiently to greatly decrease its
capacity needs.
This analysis also applies to Gulf. Although Gulf does not plan new capacity for the next decade, it,
too, has potential for further improvements, failing to meet even its modest existing FEECA goal by
12%. Id. at 19. If Gulf were performing at the level of nationally leading utilities – saving more than
1.5% of its demand per year – it could likely avoid those projected capacity additions.
Such enhanced performance could help Florida, as a whole, to meet the Legislature’s directive in
FEECA. At present, Florida ranks in the bottom half of the states with regard to energy efficiency.
See American Council for an Energy-Efficient Economy, State Scorecard 2012 (ranking Florida #29).3
The coal retirements before the PSC provide a strong incentive to do better.
We understand that the PSC will be conducting substantial analysis on this front during its FEECA
goal-setting process, see Section 366.82, F.S., which requires careful consideration of the “full
technical potential” of demand-side programs. We suggest that the PSC conduct that analysis in
tandem with its Ten-Year Site Plan review, valuing demand-side programs as a resource which can
be used to address capacity and energy issues arising from the coal retirements announced or likely
in the site plan docket. Thus, in its 2013 Ten-Year Site Plan Review, the PSC could profitably
evaluate the several different scenarios post-retirement, including scenarios in which capacity is
replaced with more aggressive demand side measures. Other scenarios should also, of course,
explore the potential of other energy sources, including enhanced in-state renewables, including
solar, and out-of-state PPAs for renewable (and hence zero fuel cost) energy. In the FEECA
process, meanwhile, the PSC can consider the costs and benefits of such measures, especially as
compared with costly and risky new gas capacity. The two processes can and should reinforce each
other as the PSC works to find ways to minimize risks and costs to ratepayers.
III.
Conclusion
Last year, we cautioned that a significant amount of coal-fired capacity in Florida was set for
retirement. That process has continued. To manage any ratepayer risk from these retirements and
the possible over-dependence on natural gas which they may promote, the PSC should emphasize
demand-side management options as alternatives to gas-fired capacity. We look forward to working
with the Commission to ensure that Florida ratepayers secure healthier air and a more reliable and
efficient electricity system.
Sincerely,
3
Available at: http://aceee.org/energy-efficiency-sector/state-policy/aceee-state-scorecard-ranking.
6
APPENDIX A
Craig Segall
Staff Attorney
Sierra Club Environmental Law Program
50 F St NW
Washington, DC, 20001
(202)-548-4597
[email protected]
7
APPENDIX A
July 2, 2012 Phillip O. Ellis Strategic Analysis & Government Affairs Public Service Commission 2540 Shumard Oak Boulevard Tallahassee, FL 32399‐0850 [email protected] CC: Traci Matthews [email protected] Re: Comments on Gulf Power’s Ten‐Year Plan Submittal Dear Mr. Ellis and Ms Matthews: Thank you for accepting these comments on behalf of the Sierra Club and its more than 27,000 Florida members, and on behalf of Earthjustice. We look forward to participating in the Public Service Commission (PSC)’s Ten‐Year Plan review process. We are writing to help inform the Commission of serious regulatory risks which should be addressed in this Ten‐Year Plan. As you know, Ten‐Year Plans are designed to provide a broad overview of a utility’s “power‐generating needs and the general location of its proposed power plant sites;” accordingly, plans must be “suitable” for planning purposes. F.S. § 186.801; see also F.A.C. §§ 25‐22.070 & 25‐22.071. These plans are among the many tools used by the Commission as it fulfills its statutory responsibilities to maintain “sufficient, adequate, and efficient service” and “fair and reasonable rates” for all Floridians. See, e.g., F.S. § 366.03. To do so, the Commission will have to address the implications of substantial new environmental compliance obligations at several aging coal‐fired units. A recent report for state utility commissioners, primarily authored by former Colorado PSC Chair Ron Binz, puts the problem succinctly, reminding regulators that “[t]he U.S. electric utility industry, which has remained largely stable and predictable during its first century of existence now faces tremendous challenges,” including the prospect of substantial retirements of aging coal‐fired power plants. See Ron Binz & CERES, Practicing Risk‐Aware Electricity Regulation: What Every State Regulator Needs to Know (2012) at 5.1 These “retrofit or retire” decisions will lead to significant changes in the Florida coal fleet, and the PSC will be charged with managing these shifts. As Commissioner Binz writes: The question for regulators is whether to approve coal plant closures in the face of new and future EPA regulations, or to approve utility investments in costly pollution controls to keep the plants running. Regulators should treat this much like an IRP proceeding: utilities 1
Attached as Ex. 1. 1 APPENDIX A
should be required to present multiple scenarios differing in their disposition of the coal plants. The cost and risk of each scenario should be tested using sensitivities for fuel costs, environmental requirements, cost of capital, and so forth. In the end, regulators should enter a decision that addresses all of the relevant risks. Id. at 9. These comments highlight some of these important risks. The Commission should use the Ten‐Year Plan informational docket to fully investigate them. We have submitted similar comments addressing plans filed by several different utilities; this filing focuses on coal‐fired power plants operated by Gulf Power. I.
Gulf Power’s Plants Face Substantial Environmental Compliance Costs Gulf Power’s Lansing Smith, Crist, and Scholz plants are aging facilities lacking major pollution controls. These plants are an increasingly bad deal for ratepayers: In addition to posing a serious threat to public health, they are not economic to operate. As utilities and PSCs around the country are increasingly recognizing, rising pollution control and fuel costs make coal power an unattractive proposition, especially as energy efficiency, demand‐side resources, and renewable power become ever more available and as natural gas prices continue at record lows. Multi‐million dollar life‐extension projects for aging coal plants are not prudent in these circumstances. Accordingly, Gulf anticipates that it is likely to retire many of its plants in the near future. Gulf Power Ten Year Plan (“Gulf Plan”) at 3. Because Gulf’s plans have important implications for the “need … for electrical power” in its service territory, and for how that need is to be met, as well on “fuel diversity within the state,” on the “environmental impact” of any proposed replacement power, and on the state “comprehensive plan,” see F.S. § 186.801, the Commission should ensure that Gulf discloses its intentions in its Ten‐Year Plan as fully as possible. It is particularly important to do so because Gulf will face compliance obligations within the next few years that will lead to retirement decisions. The Commission can best protect Floridians by beginning the planning process for these likely retirements now. The Plan is not suitably detailed to allow for this planning to be successful, so, at the end of these comments, we respectfully urge the PSC to require Gulf to submit critical additional information. Gulf Power’s Lansing Smith and Scholz plants are the most likely retirement targets because both plants lack “scrubbers,” the flue‐gas desulfurization systems required to remove SO2, which can cause deadly respiratory damage, and other acid gases from their emissions. Scrubber systems for these plants would cost hundreds of millions of dollars. Such an investment, and the corresponding rate increase, would not be prudent when much cheaper sources of power are available. Accordingly, the Commission should work with Gulf Power to investigate retirement options for these plants. 2 APPENDIX A
In the discussion below, we explain the likely sources of scrubber liability for the Lansing Smith and Scholz plants, before briefly highlighting the many other environmental compliance costs which Gulf is likely to face. A. Likely Scrubber Liability for Gulf Power Facilities Three separate environmental and public health protection programs are likely to drive scrubber installation requirements, and hence “retire or retrofit” decisions, at the Lansing Smith and Scholz facilities: the SO2 National Ambient Air Quality Standards (“NAAQS”), 40 C.F.R. § 50.17, the Mercury and Air Toxics Standards (“MATS”), 40 C.F.R. Subpt. UUUUU, and the Regional Haze Rule, 40 C.F.R. § 51.308. i.
The SO2 NAAQS Just five minutes of exposure to SO2 can make people sick; in fact, the causal link between this pollution and asthma attacks and other respiratory problems is the “strongest” such link which the EPA’s scientific advisory board can identify. 75 Fed. Reg. 35,520, 35,525 (June 22, 2010). To protect the public from such pollutants, EPA is required to set NAAQS specifying the safe level of public exposure; states then develop state implementation plans (SIPs) to ensure that those standards are attained. See 42 U.S.C. §§ 7409 & 7410. EPA’s decision to protect public health by lowering the NAAQS for SO2 to a maximum allowable exposure of 75 ppb (a concentration equivalent to 196.2 μg/m3) over an hour, see 75 Fed. Reg. 35,520 (June 22, 2010), thus obliges Florida to update its SIP to ensure that its citizens are protected from this dangerous air pollution. States are generally required to submit updated SIPs “within 3 years” after EPA updates a NAAQS; because EPA finalized its NAAQS in 2010, Florida’s plan is due in 2013. 42 U.S.C. § 7410(a)(1). The plan must “provide[] for implementation, maintenance, and enforcement of” the standard throughout Florida. Id. Although EPA’s approval and review process may delay plan implementation for a year or two after submission, the Commission can reasonably expect Florida’s SIP to be operating by 2015 or before. This tight timeline is directly relevant to the Commission’s review of Gulf Power’s plans because the Lansing Smith plant is causing violations of the NAAQS, and so will have to install controls under any legal SIP. Sierra Club engaged an expert air modeler, Steve Klafka of Wingra Engineering, to evaluate the plant’s compliance with the NAAQS, using EPA’s models and methodology.2 We modeled both the plant’s allowable emissions – those authorized by its Title V Air Operation Permit, No. 0050014‐018‐AV – and its maximum emissions in 2011, the most recent year with complete data in EPA’s Air Pollution Markets Database. Whether measured by its permit or by its most recent maximum emissions, the plant causes the pollution in the air over Panama City to reach unsafe levels, violating the NAAQS several‐fold. 2
The methodology is described in detail in the attached report, Ex. 2. 3 APPENDIX A
The ffigure below
w shows the SSO2 pollution
n plume thee plant would
d create wheen operatingg at its permit limits. All colored areaas violate the NAAQS. W
While the NA
AAQS is set aat 196.2 μg/m3, Lansing SSmith’s perm
mit allows po
ollution levels to soar to 858.4 μg/m
m3, over 400%
% of the safee value; evven a bit furtther away fro
om the plant, pollution directly over downtown
n Panama Citty reaches llevels close tto double th
he safe value
e. 4 APPENDIX A
Importantly, Lansing Smith causes NAAQS violations even when operating below its permitted maximums. Last year, Lansing Smith’s highest operating hour emissions saw SO2 concentrations reach 346.5 μg/m3, which is nearly double the safe value. See Ex. 2 at Table 1. Indeed, Lansing Smith’s SO2 emissions are so extreme that, according to the Florida Department of Environmental Protection (“FL DEP”), they even violate the far more lenient NAAQS that the new standard replaces. See FL DEP Permit No. 0050014‐018‐AV at 5. As such, FL DEP requires Gulf Power to post no trespassing signs to “protect the general public” from crossing the plant’s fence line, within which the pollution is the most intense. See id. This is not a safe facility. To reduce this illegal pollution, Lansing Smith would have to cut total facility emissions by 77.6% from its current permit. Id. at Table 3. To do so, it is highly likely to have to install a scrubber, thereby confronting hundreds of millions in control costs, which we document more fully below. Importantly, these costs will be far outweighed by public health benefits. EPA determined that the NAAQS will produce on the order of $36 billion in net benefits once safe levels of SO2 have been attained. 75 Fed. Reg. at 35,588. Panama City residents will secure a substantial portion of these benefits – in the form of fewer asthma attacks, emergency room visits, and premature deaths – once Lansing Smith’s pollution has been controlled. We have not yet modeled the Scholz facility, but it is also an unscrubbed coal boiler, burning high‐sulfur bituminous coal, and its permitted emissions are far higher than Lansing Smith’s. While the Lansing Smith permit allows emissions of up to 4.50 lbs/MMBtu of SO2, FL DEP Permit No. 0050014‐018‐AV at 8, the Scholz permit allows the facility to emit up to an astonishingly 6.17 lbs/MMBtu, FL DEP Permit No. 0630014‐010‐AV at 6. FL DEP candidly acknowledges that this emission rate “indicates exceedances” near the facility of even the more lenient NAAQS which EPA has since replaced, and so requires Gulf Power to take “precautions… to preclude public access.” Id. Scholz is an even dirtier plant than Lansing Smith, and so is very likely to run afoul of the new NAAQS as well. In short, the SO2 NAAQS, a pollution control requirement which Gulf Power does not even acknowledge in its Ten‐Year Plan, is highly likely to require the Lansing Smith and Scholz facilities to retrofit or retire. It is not the only requirement to do so, as we next discuss. ii.
MATS Requirements In the Clean Air Act of 1990, Congress ordered EPA to investigate hazardous air pollutants emitted by power plants, and to promulgate emissions standards for these pollutants if they threatened public health. 42 U.S.C. § 7412(n)(1). Because coal power plants are dominant sources of mercury, acid gases, and other highly toxic pollutants, EPA was obligated to issue such standards, and finally did so in 2012, 22 years later. See 77 Fed. Reg. 9,304 (Feb. 16, 2012). 5 APPENDIX A
The final MATS rule issued in response to this Congressional mandate requires operators to control mercury and acid gases. A smoke stack scrubber can be required to comply with EPA’s control requirements. In EPA’s analysis of facility compliance options, it presumed that coal plants emitting more than 2 lbs/MMBtu of SO2 would have to install scrubbers to comply with the standard. 77 Fed. Reg. at 9,412. As we note above, Lansing Smith emits more than twice this amount, and Scholz emits three times this threshold quantity. As such, scrubbers will very likely be required at these plants in order to comply with MATS. The Clean Air Act requires that existing sources comply with MATS “as expeditiously as practicable, but in no event later than 3 years after the effective date” of the standard. 42 U.S.C. § 7412(i)(3). Because MATS was promulgated and effective on February 16, 2012, plants must comply by that date in 2015. Although limited compliance extension of up to 1‐2 additional years may be available in some limited circumstances, see id., these extensions are disfavored. Accordingly, as Gulf Power recognizes, MATS “may severely restrict Gulf’s coal‐fired generation or completely eliminate the generation produced by Gulf’s coal‐fired units at Plants Smith and Scholz by as early as 2015.” Gulf Plan at 3. iii.
Regional Haze Requirements Since 1977, the Clean Air Act has required EPA and the states to make “reasonable progress” towards restoring natural visibility in Class I areas – which are essentially national parks and wildernesses. See 42 U.S.C. § 7491. EPA’s rules to address regional haze, promulgated in 1999, are now being implemented. Florida is the process of a SIP revision intended to protect Class I areas affected by sources in the state. See FL DEP, Regional Haze Plan for Florida Class I Areas (Draft as amended May 2012).3 Gulf Power has already determined that this rule, alone, may lead it to retire the Lansing Smith facility. The regional haze rule requires that Florida impose controls at all sources of visibility‐
impairing pollutants to the extent such controls will be needed to make reasonable progress towards restoring natural visibility by 2064. See 40 C.F.R. § 51.308(d)(3). The Act and the Rule also require sources which were in existence by August 7, 1977, but which had not been in operation before August 7, 1962, to install “the best available retrofit technology” (BART) to control visibility‐impairing pollutants. 42 U.S.C. § 7491(b)(2)(A) & 40 C.F.R. § 51.308(e). FL DEP has determined that the Crist facility is subject to reasonable progress analysis and that Lansing Smith is subject to BART. See FL Draft Regional Haze Plan at 98 & 102. FL DEP had planned to rely upon a separate EPA SO2 trading program, the Clean Air Interstate Rule (“CAIR”) to address these requirements, but CAIR has been replaced with a new program which does not control SO2 in Florida. See 77 Fed. Reg. 31,240, 31,248 (May 25, 2012). As such, FL DEP is reanalyzing control options and will have to consider source‐specific control 3
Available at http://www.dep.state.fl.us/air/rules/regulatory/regional_haze_imp.htm. 6 APPENDIX A
requirements for Crist and Lansing Smith. Scholz should also be implicated in this re‐analysis because FL DEP had previously excluded relatively small facilities largely because it assumed CAIR would address most SO2 emissions. Now that CAIR is no longer available, Scholz will have to be analyzed as well. Thus, as a result of these analyses, FL DEP will have to address SO2 emissions, in some fashion, from all of Gulf Power’s coal plants. These controls are likely to drive scrubber requirements (and other controls or operating restrictions at scrubbed plants like Crist) because, according to FL DEP, SO2 is the dominant source of visibility‐impairing pollution in Florida. See, e.g., FL Draft Regional Haze Plan at 91‐92. Thus, these rules, too, are highly likely to drive scrubber requirements at the Lansing Smith facility. Gulf Power has admitted as much to FL DEP. In a “BART Implementation Plan” submitted to DEP on May 21, 20124, it indicated that it will complete a BART analysis for Lansing Smith, and that it will decide, by January 1, 2015, whether to install a scrubber on the plant by 2018 (or later), “commit to retire the operation of Smith Unit 1 by January 1, 2022 and Smith Unit 2 before January 1, 2021,” or to seek permit levels by 2015 reducing plant operations below BART emissions limits. Gulf BART Plan at 2. Because BART determinations will be approved within the next year, it is not at all clear how Gulf Power expects to run its plants until the early 2020s. Retirement within the next few years is the more likely option. iv.
Scrubber Costs We have calculated the approximate cost of installing and running scrubbers (at 90% efficiency, a level which would likely be required, at a minimum, to meet the requirements of all three relevant rules) at Lansing Smith and Scholz, based upon the EPA’s Integrated Planning Model and a scrubber‐focused appendix developed by Sargent & Lundy.5 This model predicts that the capital costs for fitting Lansing Smith Units 1 and 2 with scrubbers at $234 million. The incremental costs (including running costs) of these upgrades would be $43.1/MWh annually. Gulf Power would no doubt seek to pass these costs on to rate‐payers if it opted to continue to run the plant, rather than to retire it. Scrubber costs for Scholz are also very high. Using the same government modeling, we calculated that scrubbers for Scholz units 1 & 2 would cost $106 million to install, yielding a $243.5/MWh spike in incremental costs. These figures do not include the incremental costs of effluent controls for scrubber waste. Any such additional upgrades would, of course, add to these costs, as would any additional measures required at Crist to bring that facility into compliance. The expenditures are extraordinarily high simply in order to extend the lives of these decades‐old, expensive, coal‐fired power plants. Gulf Power is unlikely to make them and, we submit, it would not be 4
5
Attached as Ex. 3. All modeling parameters can be found at http://www.epa.gov/airmarkt/progsregs/epa‐ipm/BaseCasev410.html. 7 APPENDIX A
appropriate for the Commission to authorize such costs where less expensive options are available. B. Other Environmental Liabilities As Gulf Power acknowledges, Gulf Plan at 3, scrubber costs are not the only liabilities it faces. There are also pending rules requiring upgrades to coal plant cooling water systems, see 76 Fed. Reg. 22,174 (Apr. 20, 2011), better handling and disposal practices for coal combustion waste, see 75 Fed. Reg. 35,128 (June 21, 2010), and new treatment systems for liquid effluent discharges,6 all of which are likely to be finalized in the next two years. EPA is also updating the NAAQS for particulate matter and for ozone. Moreover, EPA has recently proposed carbon controls for new electricity generating units. See 77 Fed. Reg. 22,39 (Apr. 13, 2012). Once finalized, these rules will obligate EPA to extend carbon controls to existing facilities, including Gulf Power’s fleet. See 42 U.S.C. § 7411(d). The cumulative impact of these liabilities on Gulf Power will be large. Indeed, according to Gulf, “the additional costs to comply with the final versions of EPA’s proposed water quality and coal combustion by‐product rules” alone “may result in total combined compliance costs that render controlled coal‐fired operations uneconomical in the long term.” Gulf Plan at 3. Coal ash costs will be particularly pressing for Gulf Power. According to the Toxic Release Inventory, its Lansing Smith facility discharged 520,281 pounds of ash to its impoundment in 2006, a typical year, making Lansing Smith the 57th largest source of ash in the country and the second largest sources in Florida.7 Highly troublingly, carcinogenic hexavalent chromium, which leaches from coal ash, has been found in groundwater wells near Lansing Smith at over 5,000 times safe levels (as determined by California for its drinking water goals), and above federal standards.8 Clean‐up costs for this contamination, including halting wet storage of ash, will be yet another substantial expense for the plants. C. Likely Retirements The cumulative compliance costs from all the rules which apply to Gulf Power’s fleet are very large. Upon reviewing them, and considering the wide availability of more inexpensive power sources, Gulf Power is highly likely to follow industry trends towards coal retirement. Coal use is falling quickly, in response both to the cost of pollution controls and to national economic trends, including the growth of inexpensive wind power and the boom in shale gas production. As EPA has recently documented, “all indications suggest that very few new coal‐
fired power plants will be constructed in the foreseeable future.” 77 Fed. Reg. at 22,413, and the Energy Information Administration (EIA) is documenting increasing retirements of existing plants. In particular, the EIA’s Annual Energy Outlook for 2012 forecasts no new unplanned 6
See EPA’s plans for this rule at http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm See Ex. 4, attached. 8
Lisa Evans, EPA’s Blind Spot: Hexavalent Chromium in Coal Ash (2011) at 6, attached as Ex. 5. 7
8 APPENDIX A
coal capaacity through
h 2020. RIA at 5‐5. EIA’s most rece nt Electric PPower Month
hly report confirms that this tre
end continue
es. Thus far this year, noone of the 55,627 MW off new units tto come online are coall‐fired; inste
ead, new cap
pacity additioons are largeely in renew
wable power or natural ggas. EIA, Elecctric Power M
Monthly Jun
ne 2012 at Taable ES3.9 Co
onversely, reetirements tto date have been pred
dominantly ccoal‐fired units. See id. aat Table ES4. Utilities across the cou
untry nounced thousands of m
megawatts w
worth of coal retirementss over the laast few yearss.10 have ann
In
ndustry‐wide
e levelized cost figures ccompiled by independen
nt analysts d
demonstratee why these rettirements arre occurring. The most rrecent (20111) edition of Lazard’s Levvelized Cost of Energy A
Analysis,11 a w
widely‐used reference, sshows that eenergy efficiency, wind, and natural gas combined cycle levellized costs are already b
below those of coal, as th
he figure below demonsttrates. deciding nott to impose Unde
er these circu
umstances, prudent ope
erators are inncreasingly d
additionaal costs on th
heir ratepayyers by runniing coal‐firedd units with costly new pollution technolo
ogy. Instead, they are opting to retire
e older unitss and pursuee cleaner, ch
heaper, enerrgy options. Gulf Power could, and sshould, decid
de to follow the same co
ourse. D. Recommende
R
ed Commisssion Action
Altho
ough Gulf Po
ower has ackknowledged that some rretirements may occur, iit nonetheleess “assume[s]” that Lan
nsing Smith aand Scholz “will be avail able to operrate on coal throughoutt the 2012‐202
21 planning cycle.” Gulff Plan at 3. A
As we have ddemonstrateed above, th
his assumptio
on is 9
Available at: http://205
5.254.135.7/ele
ectricity/monthly/pdf/epm.ppdf. See, e.g., Progress Energy Press Releaase, “Progress Energy Carolinnas to retire co
oal power plan
nt ahead of e retirement off four North Caarolina coal plaants), availablee at schedule” (Apr. 1, 2011) (recording the
ww.progress‐en
nergy.com/com
mpany/media‐‐room/news‐arrchive/press‐
https://ww
release.page?title=Progress+Energy+Caarolinas+to+re
etire+coal+pow
wer+plant+aheaad+of+schedule&pubdate=0
04‐01‐
2011; FirsttEnergy Press R
Release, “FirstEEnergy, Citing IImpact of Envi ronmental Reggulations, Will Retire Six Coal‐Fired Power Plan
nts” (Jan. 29, 2
2012) (announccing the retirem
ment of six coaal plants in Ohiio), available at https://ww
ww.firstenergycorp.com/conttent/fecorp/ne
ewsroom/new
ws_releases/firsstenergy_citinggimpactofenvironm
entalregulaationswillretire
esixc.html; Envvironment New
ws Service, “Doominion Virginiia to Replace C
Coal Plants with Gas, Nuclear” (SSept. 7, 2011) (documenting retirement of two Virginia cooal plants), avaailable at http:://www.ens‐
newswire.ccom/ens/sep2
2011/2011‐09‐0
07‐091.html. 11
Attached
d as Ex. 6. 10
9 APPENDIX A
arbitrary and unsupportable: The compliance periods for the scrubber‐forcing rules will run within the next two years and retirements will very likely occur within that period, and certainly will occur within the next decade. This error, and Gulf Power’s failure fully to address the impacts of retirements upon its system and upon ratepayers, renders the draft plan “unsuitable” as a planning document. See F.S. §186.801. The Commission, “may suggest alternatives to the plan,” id., however, and may classify a plan as suitable upon the submission of “additional data,” see F.A.C. § 25‐22.071(5). We respectfully request that the PSC exercise its authority to ensure that Gulf Power’s plan provides adequate data to allow the PSC and the public to address these plant retirements. Specifically, we submit that the Commission should seek the following information from Gulf Power and require resubmission of a complete plan addressing these submissions: 1. The utility should provide an analysis of all environmental compliance obligations which it will experience at all of its coal‐fired facilities. For each requirement, the utility should cite the relevant rule, explain how it is likely to apply to the plant, the likely costs of compliance to the utility and to ratepayers, and the timeline on which compliance will be required. The utility should also document any steps it has taken to address these compliance obligations, and alternative steps it might take. For instance, if the utility anticipates that it will have to install a scrubber to comply with MATS, it should report to the Commission on scrubber installation and operation costs, whether it has contracted to purchase a scrubber and on what timeline, and what other options it has considered. See F.S. § 186.801 (requiring utilities to document “[p]ossible alternatives to the proposed plan”). 2. The utility should provide a comparative analysis of compliance costs and the cost costs of replacing the plant’s power through energy efficiency, demand response, power purchase agreements, new generation facilities, or other means. See F.S. §186.801 (requiring utilities to explain the impact of their plans on fuel diversity and on the need for electric power in their regions). In light of this analysis, the utility should indicate whether it intends to retire any facility, and on what timeline, and the relative costs of retirement versus those of other options. If retirement has not been selected but is being considered, the utility should indicate when the decision will be made. 3. For any facility where retirement is possible, the utility should discuss how it intends to address any reliability issues which may be caused by the retirement. The Commission should play an active role in this regard, as it must maintain reliability of the electric grid. See F.S. § 366.05(7)‐(8) (authorizing the Commission to “require reports from all electric utilities to assure the development of adequate and reliable energy grids” and to order “installation and repair of necessary facilities” to address reliability issues”). The Commission has determined that “[r]eserve margins in Florida typically remain well above” relevant minimums through 2020, so system‐
wide resource adequacy problems are unlikely, but the Commission may still need to 10 APPENDIX A
address localized reliability issues. If such problems appear to be present, the Commission should work proactively and transparently with the Florida Reliability Coordinating Council to address them well in advance of any planned retirement. We appreciate this careful consideration of Gulf Power’s environmental compliance options, and any resulting plant retirements, and remind the Commission that such thorough analysis is required to ensure that the Ten‐Year Plan complies with legal requirements. We request that the Commission share the results of its inquiry with us and with the public, and request formal notice of the Commission’s next steps. Please contact the undersigned with any concerns or questions. Sincerely, s/ Craig Holt Segall Craig Holt Segall Sierra Club Environmental Law Program 50 F St NW, Eighth Floor Washington, DC, 20001 (202)‐548‐4597 [email protected] Alisa Coe Earthjustice 111 South Martin Luther King Jr. Blvd. Tallahassee, FL 32301 (850) 681‐0031 [email protected] 11 APPENDIX A
July 2, 2012 Mr. Phillip O. Ellis Strategic Analysis & Government Affairs Public Service Commission 2540 Shumard Oak Boulevard Tallahassee, FL 32399‐0850 [email protected] CC: Traci Matthews [email protected] Re: Comments on Progress Energy’s Ten‐Year Plan Submittal Dear Mr. Ellis and Ms Matthews: Thank you for accepting these comments on behalf of the Sierra Club and its more than 27,000 Florida members, and on behalf of Earthjustice. We look forward to participating in the Public Service Commission (PSC)’s Ten‐Year Plan review process. We are writing to help inform the Commission of serious regulatory risks which should be addressed in this Ten‐Year Plan. As you know, Ten‐Year Plans are designed to provide a broad overview of a utility’s “power‐generating needs and the general location of its proposed power plant sites;” accordingly, plans must be “suitable” for planning purposes. F.S. § 186.801; see also F.A.C. §§ 25‐22.070 & 25‐22.071. These plans are among the many tools used by the Commission as it fulfills its statutory responsibilities to maintain “sufficient, adequate, and efficient service” and “fair and reasonable rates” for all Floridians. See, e.g., F.S. § 366.03. To do so, the Commission will have to address the implications of substantial new environmental compliance obligations at several aging coal‐fired units. A recent report for state utility commissioners, primarily authored by former Colorado PSC Chair Ron Binz, puts the problem succinctly, reminding regulators that “[t]he U.S. electric utility industry, which has remained largely stable and predictable during its first century of existence now faces tremendous challenges,” including the prospect of substantial retirements of coal‐fired power plants. See Ron Binz & CERES, Practicing Risk‐Aware Electricity Regulation: What Every State Regulator Needs to Know (2012) at 5.1 These “retrofit or retire” decisions will lead to significant changes in the Florida coal fleet, and the PSC will be charged with managing these shifts. As Commissioner Binz writes: The question for regulators is whether to approve coal plant closures in the face of new and future EPA regulations, or to approve utility investments in costly pollution controls to keep the plants running. Regulators should treat this much like an IRP proceeding: utilities 1
Attached as Ex. 1. 1 APPENDIX A
should be required to present multiple scenarios differing in their disposition of the coal plants. The cost and risk of each scenario should be tested using sensitivities for fuel costs, environmental requirements, cost of capital, and so forth. In the end, regulators should enter a decision that addresses all of the relevant risks. Id. at 9. These comments highlight some of these important risks. The Commission should use the Ten‐Year Plan informational docket to fully investigate them. We have submitted similar comments addressing plans filed by several different utilities; this filing focuses on coal‐fired power plants operated by Progress Energy. I.
Progress Energy’s Crystal River Plant Face Substantial Environmental Compliance Costs Units 1 and 2 at Progress Energy’s Crystal River plant were put into service in the late 1960s, and are operating without major pollution controls, including smokestack scrubbers. See FL DEP Air Operation Permit No. 0170004‐025‐AV (2011) at 6. These units are an increasingly bad deal for ratepayers: In addition to posing a serious threat to public health, they are not economic to operate. As utilities and PSCs around the country are increasingly recognizing, rising pollution control and fuel costs make coal power an unattractive proposition, especially as energy efficiency, demand‐side resources, and renewable power become ever more available and as natural gas prices continue at record lows. Multi‐million dollar life‐extension projects for aging coal plants are not prudent in these circumstances. Progress has already told FL DEP that it will consider retiring units 1 and 2 within the next decade. See Progress Energy BART Implementation Plan for Crystal River Units 1 and 2 (June 2012) at 3.2 Yet, Progress’s Ten‐
Year Plan does not even mention these units, much less address their retirements. Because of this striking gap, Progress’s plan is not “suitable” for planning purposes. See F.S. § 186.801. The likely retirement of the Crystal River units has important implications for the “need … for electrical power” in its service territory, and for how that need is to be met, as well on “fuel diversity within the state,” the “environmental impact” of any proposed replacement power, and the state “comprehensive plan.” See F.S. § 186.801. The Commission should therefore ensure that Progress submits a corrected plan which discloses its intentions as fully as possible. It is particularly important to do so because Progress will face compliance obligations within the next few years that will lead to retirement decisions. The Commission can best protect Floridians by beginning the planning process for these likely retirements now. Crystal River Units 1 and 2 are likely retirement targets because both units lack “scrubbers,” the flue‐gas desulfurization systems required to remove SO2, which can cause deadly respiratory damage, from their emissions. Scrubber systems for these plants would cost tens of millions of dollars. Such an investment, and corresponding rate increase, would not be prudent 2
Attached as Ex. 2. 2 APPENDIX A
when much cheaper sources of power are available. Accordingly, the Commission should work with Progress Energy to investigate retirement options for these plants. In the discussion below, we explain the likely sources of scrubber liability for Crystal River, before briefly highlighting the many other environmental compliance costs which Progress is likely to face. A. Likely Scrubber Liability for Crystal River Units 1 and 2 Three separate environmental and public health protection programs are likely to drive scrubber installation requirements, and hence “retire or retrofit” decisions, at Crystal River: the SO2 National Ambient Air Quality Standards (“NAAQS”), 40 C.F.R. § 50.17, the Mercury and Air Toxics Standards (“MATS”), 40 C.F.R. Subpt. UUUUU, and the Regional Haze Rule, 40 C.F.R. § 51.308. i.
The SO2 NAAQS Just five minutes of exposure to SO2 can make people sick; in fact, the causal link between this pollution and asthma attacks and other respiratory problems is the “strongest” such link which the EPA’s scientific advisory board can identify. 75 Fed. Reg. 35,520, 35,525 (June 22, 2010). To protect the public from such pollutants, EPA is required to set NAAQS specifying the safe level of public exposure; states then develop state implementation plans (SIPs) to ensure that those standards are attained. See 42 U.S.C. §§ 7409 & 7410. EPA’s decision to protect public health by lowering the NAAQS for SO2 to a maximum allowable exposure of 75 ppb (a concentration equivalent to 196.2 μg/m3) over an hour, see 75 Fed. Reg. 35,520 (June 22, 2010), thus obliges Florida to update its SIP to ensure that its citizens are protected from this dangerous air pollution. States are generally required to submit updated SIPs “within 3 years” after EPA updates a NAAQS; because EPA finalized its NAAQS in 2010, Florida’s plan is due in 2013. 42 U.S.C. § 7410(a)(1). The plan must “provide[] for implementation, maintenance, and enforcement of” the standard throughout Florida. Id. Although EPA’s approval and review process may delay plan implementation for a year or two after submission, the Commission can reasonably expect Florida’s SIP to be operating by 2015 or before. This tight timeline is directly relevant to the Commission’s review of Progress Energy’s plans because the Crystal River plant is causing violations of the NAAQS, and so will have to install controls under any legal SIP. Sierra Club engaged an expert air modeler, Steve Klafka of Wingra Engineering, to evaluate the plant’s compliance with the NAAQS, using EPA’s models and methodology.3 We modeled both the plant’s allowable emissions – those authorized by its Title V Air Operation Permit, No. 017000–025‐AV, and its maximum emissions in 2011, the most recent year with complete data in EPA’s Air Pollution Markets Database. Whether measured by 3
The methodology is described in detail in the attached report, Ex. 3. 3 APPENDIX A
its permit or by its most recent maximum emissions, the plant causes pollutants in the air near Crystal River to reach dangerous levels. The figure below shows the SO2 pollution plume the plant would create when operating at its permit limits. All colored areas violate the NAAQS. While the NAAQS is set at 196.2 μg/m3, Crystal River’s permit allows pollution levels to soar to a maximum of 921.0 μg/m3, over 460% of the safe value; even a bit further away from the plant, the pollution in the air directly over residential areas and over Crystal Bay is well above safe levels. 4 APPENDIX A
5 APPENDIX A
Importantly, Crystal River causes NAAQS violations even when operating below its permitted maximums. Last year, the plant’s highest operating hour emissions saw SO2 concentrations reach 534.6 μg/m3, which is nearly three times the safe value. See Ex. 2 at Table 1. To reduce this illegal pollution, Crystal River would have to cut total facility emissions by 79.1% from its current permit. Id. at Table 3. To do so, it is highly likely to have to install a scrubber, thereby confronting hundreds of millions in control costs, which we document more fully below. Importantly, these costs will be far outweighed by public health benefits. EPA determined that the NAAQS will produce on the order of $36 billion in net benefits once safe levels of SO2 have been attained. 75 Fed. Reg. at 35,588. Crystal River residents will secure a substantial portion of these benefits – in the form of fewer asthma attacks, emergency room visits, and premature deaths – once the plant’s pollution has been controlled. In short, the SO2 NAAQS, a pollution control requirement which Progress Energy does not even acknowledge in its Ten‐Year Plan, is highly likely to require Crystal River Units 1 and 2 to retrofit or retire. It is not the only requirement to do so, as we next discuss. ii.
MATS Requirements In the Clean Air Act of 1990, Congress ordered EPA to investigate hazardous air pollutants emitted by power plants, and to promulgate emissions standards for these pollutants if they threatened public health. 42 U.S.C. § 7412(n)(1). Because coal power plants are dominant sources of mercury, acid gases, and other highly toxic pollutants, EPA was obligated to issue such standards, and finally did so in 2012, 22 years later. See 77 Fed. Reg. 9,304 (Feb. 16, 2012). The final MATS rule issued in response to this Congressional mandate requires operators to control mercury and acid gases. A smoke stack scrubber can be required to comply with EPA’s control requirements. In EPA’s analysis of compliance options, it presumed that coal plants emitting more than 2 lbs/MMBtu of SO2 would have to install scrubbers to comply with the standard. 77 Fed. Reg. at 9,412. Crystal River’s air operation permit allows it to emit 2.1 lbs/MMBtu of SO2, meaning that the MATS rule will likely drive scrubbers installation at the facility. See FL DEP Air Operation Permit 0170003‐025‐AV at 7. Notably, Crystal River is also the single largest source of mercury in Florida, dumping more than 300 kg of mercury a year into the air around the plant.4 On both counts, MATS compliance will, accordingly, be a major focus for the facility. 4
See Laura S. Sherman et al., Investigation of Local Mercury Deposition from a Coal‐Fired Power Plant Using Mercury Isotopes, Environment Science & Technology (2012), attached as Ex. 4. 6 APPENDIX A
The Clean Air Act requires that existing sources comply with MATS “as expeditiously as practicable, but in no event later than 3 years after the effective date” of the standard. 42 U.S.C. § 7412(i)(3). Because MATS was promulgated and effective on February 16, 2012, plants must comply by that date in 2015. Although limited compliance extension of up to 1‐2 additional years may be available in some limited circumstances, see id., these extensions are disfavored. Accordingly, Progress Energy will have to scrub Crystal River by 2015, or shortly thereafter, or retire the facility, yet it entirely fails to acknowledge this major shift in its operations in its Ten‐Year Plan. iii.
Regional Haze Requirements Since 1977, the Clean Air Act has required EPA and the states to make “reasonable progress” towards restoring natural visibility in Class I areas – which are, essentially, national parks and wildernesses. See 42 U.S.C. § 7491. EPA has been very slow to implement this mandatory duty, but its rule to address regional haze, promulgated in 1999, are now being implemented, and Florida is the process of a SIP revision intended to protect Class I areas affected by sources in the state. See FL DEP, Regional Haze Plan for Florida Class I Areas (Draft as amended May 2012).5 The regional haze rule requires that Florida impose controls at all sources of visibility‐
impairing pollutants to the extent such controls will be needed to make reasonable progress towards restoring natural visibility by 2064. See 40 C.F.R. § 51.308(d)(3). The Act and the Rule also require sources which were in existence by August 7, 1977, but which had not been in operation before August 7, 1962, to install “the best available retrofit technology” (BART) to control visibility‐impairing pollutants. 42 U.S.C. § 7491(b)(2)(A) & 40 C.F.R. § 51.308(e). FL DEP has determined that the Crist facility is subject to BART. See FL Draft Regional Haze Plan at 102. FL DEP had planned to rely upon a separate EPA SO2 trading program, the Clean Air Interstate Rule (“CAIR”) to address these requirements, but CAIR has been replaced with a new program which does not control SO2 in Florida. See 77 Fed. Reg. 31,240, 31,248 (May 25, 2012). As such, FL DEP is reanalyzing control options and will have to propose source‐specific control requirements for Crystal River Units 1 and 2. These controls are likely to drive scrubber requirements because, according to FL DEP, SO2 is the dominant source of visibility‐impairing pollution in Florida. See, e.g., FL Draft Regional Haze Plan at 91‐92. Progress Energy has indicated as much to FL DEP. In a 2009 BART permit, Progress Energy agreed to retire the Crystal River units by December 31, 2020, as long as the second unit of its proposed Levy County nuclear facility was operating by that time.6 Just a few weeks ago, Progress submitted an updated BART implementation plan to FL DEP indicating that, whether or not the Levy County facility comes online, it would either install a 5
6
Available at http://www.dep.state.fl.us/air/rules/regulatory/regional_haze_imp.htm. See Air Permit No. 0170004‐017‐AC (Feb. 26, 2009) at 6, attached as Ex. 5. 7 APPENDIX A
scrubber (by 2018 or 5 years after Florida’s haze SIP is approved), retire the units by December 31, 2020, or limit operations to keep the plant’s operations below BART limits.7 Because BART determinations will be approved within the next year, it is not at all clear how Progress expects to run its plants until 2020. Retirement within the next few years is the more likely option. iv.
Scrubber Costs We have calculated the approximate cost of installing and running scrubbers (at 90% efficiency, a level which would likely be required, at a minimum, to meet the requirements of all three relevant rules) at Crystal River Units 1 and 2, based upon the EPA’s Integrated Planning Model and a scrubber‐focused appendix developed by Sargent & Lundy.8 This model predicts that the capital costs for fitting these units with scrubbers as $486 million. The result (including operational costs) would be a $36.6/MWh spike in incremental costs. Progress Energy would no doubt seek to pass these costs on to rate‐payers if it opted to continue to run the plant, rather than to retire it. These expenditures are extraordinarily high simply in order to extend the lives of these decades‐old, expensive, coal‐fired power plants. B. Other Environmental Liabilities Scrubber costs are not the only liabilities Crystal River faces. There are also pending rules requiring upgrades to coal plant cooling water systems, see 76 Fed. Reg. 22,174 (Apr. 20, 2011), better handling and disposal practices for coal combustion waste, see 75 Fed. Reg. 35,128 (June 21, 2010), and new treatment systems for liquid effluent discharges,9 all of which are likely to be finalized in the next two years. EPA is also updating the NAAQS for particulate matter and for ozone. Moreover, EPA has recently proposed carbon controls for new electricity generating units. See 77 Fed. Reg. 22,39 (Apr. 13, 2012). Once finalized, these rules will obligate EPA to extend carbon controls to existing facilities, including Crystal River. See 42 U.S.C. § 7411(d). The cumulative impact of these liabilities on Progress Energy will be large and are likely to lend further weight to retirement decisions. C. Likely Retirements The cumulative compliance costs from all the rules which apply to Progress Energy’s Crystal River units are substantial. Upon reviewing them, and considering the wide availability of more inexpensive power sources, Progress is highly likely to follow industry trends towards coal retirement. Coal use is falling quickly, in response both to the cost of pollution controls and to national economic trends, including the growth of inexpensive wind power and the boom in shale gas production. As EPA has recently documented, “all indications suggest that very few new coal‐
7
See Ex. 2, supra. All modeling parameters can be found at http://www.epa.gov/airmarkt/progsregs/epa‐ipm/BaseCasev410.html. 9
See EPA’s plans for this rule at http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm 8
8 APPENDIX A
fired pow
wer plants w
will be constrructed in the
e foreseeablee future.” 777 Fed. Reg. aat 22,413, an
nd the Energgy Informatiion Administtration (EIA) is documennting increassing retiremeents of existting plants. In
n particular, the EIA’s An
nnual Energyy Outlook foor 2012 foreccasts no new
w unplanned
d coal capaacity through
h 2020. RIA at 5‐5. EIA’s most rece nt Electric PPower Month
hly report confirms that this tre
end continue
es. Thus far this year, noone of the 55,627 MW off new units tto ead, new cap
pacity additioons are largeely in renew
wable power or come online are coall‐fired; inste
natural ggas. EIA, Elecctric Power M
Monthly Jun
ne 2012 at Taable ES3.10 C
Conversely, rretirements to date have been pred
dominantly ccoal‐fired units. See id. aat Table ES4. Utilities across the cou
untry have ann
nounced thousands of m
megawatts w
worth of coal retirementss over the laast few yearss.11 In
ndustry‐wide
e levelized cost figures ccompiled by independen
nt analysts d
demonstratee why these rettirements arre occurring. The most rrecent (20111) edition of Lazard’s Levvelized Cost of Energy A
Analysis,12 a w
widely‐used reference, sshows that eenergy efficiency, wind, and natural gas combined cycle levellized costs are already b
below those of coal, as th
he figure below demonsttrates. Unde
er these circu
umstances, prudent ope
erators are inncreasingly d
deciding nott to impose additionaal costs on th
heir ratepayyers by runniing coal‐firedd units with costly new pollution technolo
ogy. Instead, they are opting to retire
e older unitss and pursuee cleaner, ch
heaper, enerrgy options. Progress Energy could, aand should, decide to foollow the sam
me course. D. Recommende
R
ed Commisssion Action
10
Available
e at: http://205
5.254.135.7/ellectricity/montthly/pdf/epm. pdf. See, e.g., Progress Energy Press Releaase, “Progress Energy Carolinnas to retire co
oal power plan
nt ahead of e retirement off four North Caarolina coal plaants), availablee at schedule” (Apr. 1, 2011) (recording the
ww.progress‐en
nergy.com/com
mpany/media‐‐room/news‐arrchive/press‐
https://ww
release.page?title=Progress+Energy+Caarolinas+to+re
etire+coal+pow
wer+plant+aheaad+of+schedule&pubdate=0
04‐01‐
2011; FirsttEnergy Press R
Release, “FirstEEnergy, Citing IImpact of Envi ronmental Reggulations, Will Retire Six Coal‐Fired Power Plan
nts” (Jan. 29, 2
2012) (announccing the retirem
ment of six coaal plants in Ohiio), available at https://ww
ww.firstenergycorp.com/conttent/fecorp/ne
ewsroom/new
ws_releases/firsstenergy_citinggimpactofenvironm
entalregulaationswillretire
esixc.html; Envvironment New
ws Service, “Doominion Virginiia to Replace C
Coal Plants with Gas, Nuclear” (SSept. 7, 2011) (documenting retirement of two Virginia cooal plants), avaailable at http:://www.ens‐
newswire.ccom/ens/sep2
2011/2011‐09‐0
07‐091.html. 12
Attached
d as Ex. 6. 11
9 APPENDIX A
Progress Energy has entirely failed to address these environmental compliance issues, and the impacts of retirements at Crystal River upon its system and upon ratepayers. The failure renders the draft plan “unsuitable” as a planning document. See F.S. §186.801. The Commission, “may suggest alternatives to the plan,” id., however, and may classify a plan as suitable upon the submission of “additional data,” see F.A.C. § 25‐22.071(5). We respectfully request that the PSC exercise its authority to ensure that Progress’s plan provides adequate data to allow the PSC and the public to address these plant retirements. Specifically, we submit that the Commission should seek the following information from Progress and require resubmission of a complete plan addressing these submissions: 1. The utility should provide an analysis of all environmental compliance obligations which it will experience at the Crystal River plant. For each requirement, the utility should cite the relevant rule, explain how it is likely to apply to the plant, the likely costs of compliance to the utility and to ratepayers, and the timeline on which compliance will be required. The utility should also document any steps it has taken to address these compliance obligations, and alternative steps it might take. For instance, if the utility anticipates that it will have to install a scrubber to comply with MATS, it should report to the Commission on scrubber installation and operation costs, whether it has contracted to purchase a scrubber and on what timeline, and what other options it has considered. See F.S. § 186.801 (requiring utilities to document “[p]ossible alternatives to the proposed plan”). 2. The utility should provide a comparative analysis of compliance costs and the cost costs of replacing the plant’s power through energy efficiency, demand response, power purchase agreements, new generation facilities, or other means. See F.S. §186.801 (requiring utilities to explain the impact of their plans on fuel diversity and on the need for electric power in their regions). In light of this analysis, the utility should indicate whether it intends to retire any facility, and on what timeline, and the relative costs of retirement versus those of other options. If retirement has not been selected but is being considered, the utility should indicate when the decision will be made. 3. For any facility where retirement is possible, the utility should discuss how it intends to address any reliability issues which may be caused by the retirement. The Commission should play an active role in this regard, as it must maintain reliability of the electric grid. See F.S. § 366.05(7)‐(8) (authorizing the Commission to “require reports from all electric utilities to assure the development of adequate and reliable energy grids” and to order “installation and repair of necessary facilities” to address reliability issues”). The Commission has determined that “[r]eserve margins in Florida typically remain well above” relevant minimums through 2020, so system‐
wide resource adequacy problems are unlikely, but the Commission may still need to address localized reliability issues. If such problems appear to be present, the 10 APPENDIX A
Commission should work proactively and transparently with the Florida Reliability Coordinating Council to address them well in advance of any planned retirement. We appreciate this careful consideration of Progress Energy’s environmental compliance options, and any resulting plant retirements, and remind the Commission that such thorough analysis is required to ensure that the Ten‐Year Plan complies with legal requirements. We request that the Commission share the results of its inquiry with us and with the public, and request formal notice of the Commission’s next steps. Please contact the undersigned with any concerns or questions. Sincerely, s/ Craig Holt Segall Craig Holt Segall Sierra Club Environmental Law Program 50 F St NW, Eighth Floor Washington, DC, 20001 (202)‐548‐4597 [email protected] Alisa Coe Earthjustice 111 South Martin Luther King Jr. Blvd. Tallahassee, FL 32301 (850) 681‐0031 [email protected] 11 II. Outside Persons
Who Wish to
Address the
Commission at
Internal Affairs
OUTSIDE PERSONS WHO WISH
TO ADDRESS THE COMMISSION AT
INTERNAL AFFAIRS
October 24, 2013
Speaker
Representing
Susan Masterton
Greg Follensbee
De O’Roarke
J.R. Kelly
CenturyLink
AT&T
Verizon
OPC
Item #
1
1
1
1
III. Supplemental
Materials for
Internal Affairs
NOTE: The following material pertains to Item 2
of this agenda.
State of Florida
ffirhlta$rlrfin6.ffi
Clpnll
Ctncln OFFIcE CnNrrn o 2540 SuuuaRo Olr Bouluvnru
TALLAHASSEE, FLoRIDA 32399-0850
.M-E.M-O.R-A.N.D-U-MDATE:
October 23.2013
TO:
Braulio L. Baez, Executive Director
FROM:
Thomas E. Ballinger, Director, Division of Engineering "
RE:
Proposed revisions to Review of 2013 Ten-Year Site Plans. This item is scheduled
for discussion as Item # 2 on the 10124 Intemal Affairs conference
4-\/)
I
/ ,V
Yesterday afternoon, I was made aware of some typographical errors in the above
mentioned report. I have attached a document showing the suggested corrections in type and
strike format. Please let me know if you approve of this request.
n
1
$,' \
Attachment
Cc'. wlattachment
Lisa Harvey
O^JQJA
Proposed Modifications to Review of 2013 TYSP
Page 3. second paragraph
Traditional Generation
Natural gas is anticipated to remain the dominant fuel over the planning horizon, with
in2012 increasing to 64.8 percent of the state's net energy for load (NEL), up from 57.7
percent of NEL in 2011. Figure 2 below illustrates the increasing use of natural gas as a
generating fuel for the electricity production during the last ten years, and the projected use
during the next decade. State-wide, natural gas usage is expected to decline slightly,_sn_g
percentage basis. from its current peak, to 58.8 percent in 2022. This is due to projected
increases in nuclear generation, and a limited impact of new environmental compliance
usage
requirements.
Page 16. second
full paragraph
The last annual demand and energy goal-setting proceeding was completed in December
of 2009, providing annual goals for the period of 2010 through M 2019. To meet the
requirement to set goals at least once every five years, the Commission must establish annual
goals for the 2015 through *25 2024 period by the end of 2014. The Commission already
established dockets for each of the seven FEECA Utilities in July 2013, with hearing dates set
for July 2014, and a final decision by the Commission expected by October 2014.
Page 17, second
full paragraph
For each category the impacts of conservation (including some self-service generators),
and for seasonal peak demand, load management programs, and intemrptible/curtailable load is
shown. The total demand or total energy for load represents what otherwise would be served if
not for the impact of demand response and conservation programs. The net firm demand of-net
is used as a planning
generating
reserves.
of
number for the calculation
Pase 23,
third full paragraph
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.
Page 30, revised Table 12
Utility
Generating Unit
Name
Generator
Type
Summer
Capacity
Retirement
(MW)
Date
Planned
Notes
Nuclear Units
DEF**
Crvstal fuver
3
Nuclear Steam
850
0t/2013
Oil-Fired Units
Oil Steam
FPL
PortEverslades3&4
FPL
Turkev Point
DEF
DEF
Various
Oil Turbine
CrvstalRiverl&2
Scholz I & 2
Coal Steam
Coal Steam
Municipal Plant2 & 5
Municipal Plant 1,3,4
Gas CC
Gas Steam
44
94
Gas Turbine
t29
t2
| &2
SuwanneeRiverl-3
o
o
Steam
Steam
761
788
01t2013
Modernization
0112013
Svnch. Condenser
129
06t2018
04t2016
56
Coal-Fired Units
DEF
GPC
869
92
04/2016
04/20r5
EPA Rules Related
EPA Rules Related
Gas-Fired Units
FPL
FPL
DEF
GPC
GRU
GRU
TAL
TAL
Various
Pea Ridee 1-3
Various
JR Kellv GTOl-03
Various
Various
Total
Gas Turbine
Gas Steam
Gas Turbine
Gas Turbine
Gas Steam
0U20
01t20 4
06t20 6
12120 8
98
10t20 5*
42
56
02120 8*
r24
12120 3*
03t20 5:"
4.tu
*Planned Retirement Date is for earliest unit retirement. Other units may retire later than indicated here
** Multiple Joint Owners for Crystal River 3. Primary owner listed here.
Source: 2013 TYSPs,2013 FRCC Regional Load & Resource Plan
Page 31, last paragraph
Role of Demand Side Management in Reserve Margin
be noted that the reserve margin figures above are calculated using the net ftrm system
demand for the diagonal shaded value, which assumes full use of interruptible load and load
It should
managementdevicestoreducepeakdemand,[email protected]
which only includes generation and conservatiory is the solid value. Participation in intemrptible
rates and load management programs are voluntary, for which incentives are provided in the
form of lower rates or credits paid to the participant. As shown in Figure 11 above, the state as a
whole has sufficient generation capacity planned throughout a majority of the period to meet the
minimum reserve margin of 15 percent without relying on demand response. As noted
previously, these customers have not typically been activated during periods of peak demand.
Page 32.
first full paragraph
New Generation Resources
Current demand and energy forecasts continue to indicate that in spite of increased levels
generation
resources, the need for tradi,tienal additional generating capacity still exists. While reductions in
demand have been significant, the total demand for electricity and the per-capita consumption is
expected to increase, making the addition of traditional generating units necessary to satisfy
reliability requirements and provide suffrcient 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,
of conservation, energy efficiency, renewable generation, and existing traditional
Florida's utilities must carefully weigh the factors involved in selecting a supply-side resource
for future traditional generation projects.
flexibility in their generation fuel source mix. Although the Commission has cited the growing
lack of fuel diversity within the State of Florida as a major strategic concern for the past several
years, natural gas is anticipated to remain the dominant fuel over the planning horizon.
Excluding renewables and one nuclear unit, all new generation facilities planned within the State
of Florida over the ten-year period are natural gas-fired units.
Page 38. revised Table 15
Utility
Generating Unit Name
Summer
Capacity
Certification Dates
Need Approved
(MW)
(Commission)
Combined Cycle Units
FPL
FPL
FPL
09/2008
09/2008
1012009
06t2013
1U2009
| )11
0412012
0312013
0612014
0612016
1,210
DEF
DEF
TECO
SEC
SEC
|
Port Everelades
Unnamed CC I
Unnamed CC 2
Polk 2-5 CC Conversion
Unnamed CC I
Unnamed CC 2
Date
Certified
1217t.2t2
Cane Canaveral
Riviera Beach
In-Service
PPSA
11"'
1.189
1.189
*
*
459
192
192
12/2012
*
06/2018
0612020
*
0t/2017
,k
12/2020
t2/2020
Combustion Turbine Units
Unnamed CT I
Future CT
198
190
TAL
Hookins
46
SEC
SEC
Unnamed CT 2
SEC
TECO
5
&3
:*+
**
396
UnnamedCT4-7
t2/2019
05t2020
0s/2020
**
**
12/2020
:f+
792
t2/2021
**
0612022
187
Unnamed CT
8.683
Total Natural Gas Additions
* These units have not yet received a Determination of Need andJor a PPSA Certification.
** These units are not regulated under the PPSA, and do not require a Determination of Need.
Source: TYSP Utilities Data Response
DEF
Summer
Capacity (MW)
Natural Gas Units
Generator Type
Generating Unit Name
Cape Canaveral Energy Center
Riviera Beach Enersv Center
Port Everglades Energy Center
Combined Cycle
Combined Cycle
Combined Cvcle
In-Service
Date
PPSA
1.210
06t2013
wI-T1
06/2014
06t2016
Approved
Approved
Approved
t "t111)t)
Nuclear Units
Turkey Point Unit 4 Uprate
Turkev Point Unit 6
Turkey Peint Unit 7
Steam Turbine
Steam Turbine
20*
0312013
Approved
1.100
06/2022
S+eam+urbine
+00
Pending
Pendine
1
w]
*This capacity represents the uprate only, not the full capacity of the generating unit
Source:2013 TYSP Schedule
8
for Figure 20
Page 44. Source Reference
Qllote, this change applies to other individual figures on pages 48, 52, 56, 60, 64, 68,72,76,80, and 84)
Source: Based on 2013 TYSP Schedules 3
&
7
Page 51. top of page
Fuel Diversity
Figure 1 shows TECO's historic fuel mix for 2003 and2012, and the projected fuel mix
for 2022. TECO's primary generation fuel is coal, one of only two utilities in the state that relied
upon the solid fuel over natural gas in 2072, with 50.3 percent of system energy generated by
coal. Coal usage has declined however, primarily with the increase of natural gas, which is the
next highest fuel for TECO's system energy. Natural gas has risen to 39.2 percent of system
energy in2012, up from only 2418.0 percent in 2003. Coal is anticipated to remain the main
system fuel throughout the planning period, making up 49.4 percent rn 2022, although natural
gas is projected to replace purchased power and increase its share of system energy to 43.9
percent in2022.
Figure 1: TECO - Fuel Diversity (History & Forecast)
1003
(Achral)
2012
(Achnl)
2022 @ojected)
709/o
:L
E
60%
5O-3o,/o
1).!,1t6
43.9Yo
5oolo
&
i
10o/o
7 zou,
z
| 2oo/o
3
23'79',o
18.0%
10%
,r.t*
0.09'0
0.0%
0.0%
1.0e6 0.1%
u.ro,,o
0.Oc,o
u,.'o
Natural Gas
Nuclear
Oil
Interhange. \1,-G.
Renenvable. Other
Source: 2013 TYSP Schedule 6
Page 52,
first paragraph
Reserve Margin
TECO maintains a minimum 20 percent reserve margin for planning purposes based on a
stipulation approved by the Commission. Figure 30 displays the forecast planning reserve
margin for TECO through the planning period for both seasons including the effects of projected
conseruation activities. The impact of demand response programs on reserve margin is also
included. As shown in the figure, TECO is generally a winter-peaking utility, during certain
periods surnmer peak demand can be of greater concern. TECO also maintains a minimum
supply-side contribution to its reserve margin, set at 7 percent, which it exceeds b1.mere-than
+Og-peree* in all years of the planning period.
Page 56,
first paragraph
Reserve Margin
GPC is not within the FRCC region, and therefore not subject to its minimum reserve margin
requirements. GPC operates within SERC, and as part of the Southem Power Pool has a
planning reserve margin of 15 percent after 2015. Figure 35 displays the forecasted planning
reserve margin for GPC through the planning period for both seasons, including the effects of
projectedconservationactivities.Asshowninthefigure,GPC
[email protected]h
seasons throughout the planning period
Page 84.
first paragraph
Reserve Margin
TAL is within the FRCC region and is required to meet a 15 percent reserve margin
requirement. However, TAL has adopted an l8 17 percent planning reserve margin requirement.
Figure 70 displays the forecast planning reserve margin for TAL through the planning period for
both seasons including the effects of projected conservation activities. The impact of the utility's
demand response programs, which are focused on sunmer demand only, is also included in the
summer reserve margin. As shown in the figure, TAL is a summer peaking utility and has
sufficient reserve margin to meet projected customer demands throughout the period when
including demand response.
IV. Transcript
000001
1
BEFORE THE
FLORIDA PUBLIC SERVICE COMMISSION
2
3
4
5
6
7
8
9
10
11
12
13
PROCEEDINGS:
14
COMMISSIONERS
PARTICIPATING:
15
16
17
18
19
20
23
24
CHAIRMAN RONALD A. BRISÉ
COMMISSIONER LISA POLAK EDGAR
COMMISSIONER ART GRAHAM
COMMISSIONER EDUARDO E. BALBIS
COMMISSIONER JULIE I. BROWN
DATE:
Thursday, October 24, 2013
TIME:
Commenced at 2:02 p.m.
Concluded at 2:29 p.m.
PLACE:
Gerald L. Gunter Building
Room 105
2540 Shumard Oak Boulevard
Tallahassee, Florida
REPORTED BY:
JANE FAUROT, RPR
Official FPSC Reporter
(850) 413-6732
21
22
INTERNAL AFFAIRS
25
FLORIDA PUBLIC SERVICE COMMISSION
000002
1
P R O C E E D I N G S
2
CHAIRMAN BRISÉ:
Good afternoon.
(Echo.)
I
3
can hear myself.
It is Thursday, the 24th of October,
4
and we will call to order our Internal Affairs meeting
5
for today.
And we will take up Item 1.
6
MR. CASEY:
7
Bob Casey on behalf of staff.
8
9
Good afternoon, Commissioners.
Item Number 1 addresses staff's draft petition
to the FCC requesting a permanent waiver of a
10
requirement contained in four new FCC rules to provide
11
hard-copy Lifeline certification forms to eligible
12
telecommunications carriers.
13
Association filed for and received three consecutive
14
temporary waivers of this requirement on behalf of
15
states which included Florida through February 1st,
16
2014.
17
18
19
20
CHAIRMAN BRISÉ:
The United States Telecom
Bob, just wait one second.
Can you all hear?
MR. KELLY:
We can hear him, but it's not on
the speaker.
21
CHAIRMAN BRISÉ:
22
(Off-the-record discussion.)
23
CHAIRMAN BRISÉ:
24
MR. CASEY:
25
Okay.
Go ahead.
The current waiver order states
that no later than November 1st, 2013, each state still
FLORIDA PUBLIC SERVICE COMMISSION
000003
1
subject to this waiver must file a status update with
2
the FCC.
3
to come into compliance and seeks a permanent waiver
4
from the rules, it must provide in its request for
5
permanent relief an explanation for why such relief is
6
appropriate.
7
And if a state believes that it will be unable
The Florida Lifeline, the electronic
8
coordinated enrollment process does not have the
9
capability of printing out a hard-copy Lifeline
10
application, but does allow eligible telecommunications
11
carriers to adhere to the requirements of the Lifeline
12
reform order without the need to require or maintain
13
hard-copy Lifeline certification applications.
14
Staff believes the FCC requirement to provide
15
hard-copy certifications is unnecessary, not
16
cost-effective, and would penalize Florida for having an
17
efficient, verifiable, and streamlined Lifeline
18
electronic coordinated enrollment process.
19
seeking Commission approval to file the status update
20
and permanent waiver request by November 1.
21
Staff is available for questions.
22
CHAIRMAN BRISÉ:
23
Before we get into questions, I know that
Staff is
Thank you very much.
24
there are several speakers that are interested in this
25
matter, so I'll give them an opportunity to address us,
FLORIDA PUBLIC SERVICE COMMISSION
1
000004
if they so wish.
2
Ms. Khazraee from CenturyLink --
3
MS. MASTERSON:
4
CHAIRMAN BRISÉ:
5
MS. MASTERSON:
6
CHAIRMAN BRISÉ:
8
MS. MASTERTON:
10
Yes, ma'am.
Did you want me to go ahead
or --
7
9
I'm sorry.
You can go ahead.
This is Susan Masterton,
Counsel for CenturyLink, and we are just here in support
of the staff's waiver proposal.
11
CHAIRMAN BRISÉ:
Okay, thank you.
12
Greg Follensbee from AT&T.
13
MR. FOLLENSBEE:
Yes.
Greg Follensbee with
14
AT&T.
15
support, but, yes -- (audience laughter) -- we are in
16
support of the permanent waiver.
17
the trials and tribulations of having to deal with what
18
happens when a temporary waiver ends.
19
that we prefer to not to have to do in the future.
20
21
22
If I was at the Legislature I would say waive and
CHAIRMAN BRISÉ:
We have gone through
Thank you.
It is a catch-up
We have Dee
O'Roark from Verizon.
MR. O'ROARK:
Thank you, Mr. Chairman.
23
Verizon also supports the petition.
24
CHAIRMAN BRISÉ:
25
We have Lisa Steffens from OPC.
All right.
Thank you.
FLORIDA PUBLIC SERVICE COMMISSION
1
MR. KELLY:
2
CHAIRMAN BRISÉ:
3
All right.
4
000005
We support.
All right.
Thank you.
Commissioners, any comments or
questions?
5
COMMISSIONER BROWN:
6
is the likelihood of a permanent waiver?
7
you hear me in the back?
8
What's the likelihood of having a permanent waiver?
9
MR. CASEY:
I have a question.
What
I'm sorry, can
I'm trying to speak loud.
I would be hesitant to predict
10
what the FCC would do.
But in phone conversations with
11
our staff, they are treating this like an administrative
12
thing.
13
than any other state, they said just file a permanent
14
waiver and we'll take care of it.
Because they know the Florida process better
15
COMMISSIONER BROWN:
16
contact with the FCC continuously so --
17
MR. CASEY:
18
COMMISSIONER BROWN:
19
For a year and a half.
MR. CASEY:
21
COMMISSIONER BROWN:
recommendation order?
Yes, Commissioner.
MR. CASEY:
24
COMMISSIONER BROWN:
and summary.
-- on the proposed
On Page 6 --
23
25
Can I make a
suggestion --
20
22
And you have been in
Okay.
-- it's the introduction
And I think right at the top of that
FLORIDA PUBLIC SERVICE COMMISSION
000006
1
paragraph, that's not in full, but it's right at the top
2
where it says the Florida Lifeline Electronic
3
Coordinated Enrollment Process does not have the
4
capability of printing out a hard copy of the Lifeline
5
application as required.
6
you have some great language throughout towards the
7
latter part of the recommendation, if you summarize why
8
so they have that in the intro.
9
says that we don't have the capabilities, but if you
I think it would be helpful --
In the summary it just
10
could provide -- on Page 17 it says, three-quarters of
11
the way down it says it would be extremely difficult, if
12
not impossible to isolate -- that area, that paragraph
13
there, you have got some good language there, maybe you
14
want to incorporate there, that summarizes.
15
MR. CASEY:
16
COMMISSIONER BROWN:
17
18
19
Sure, I'd be glad to.
Thanks for your work on
it.
CHAIRMAN BRISÉ:
Okay.
Commissioners, on this item?
Anything else,
Okay.
20
If not, we are ready to entertain a motion.
21
COMMISSIONER EDGAR:
22
23
suggestion.
I think that's a good
Thank you, Commissioner Brown.
I think this is all good, good staff work.
24
And I move that we approve it, and ask our staff to do
25
whatever they need to follow through.
FLORIDA PUBLIC SERVICE COMMISSION
1
COMMISSIONER GRAHAM:
2
CHAIRMAN BRISÉ:
3
It has been moved and
Seeing none, all in favor
say aye.
(Vote taken.)
7
CHAIRMAN BRISÉ:
Thank you very much.
And,
staff, thank you very much for your work on this.
9
MR. CASEY:
10
Thank you, Commissioners.
* * * * * * *
11
12
Okay.
Further comments?
6
8
Second.
seconded.
4
5
000007
CHAIRMAN BRISÉ:
Moving on to Item Number 2,
which is review of the Ten-Year Site Plan for 2013.
13
MR. ELLIS:
Phillip Ellis with Commission
14
staff.
15
Site Plans for the Florida electric utilities.
16
the report is similar in format and content to last
17
year's review.
18
statewide review; a utility-specific review; and then a
19
collection of comments we've received.
20
oral modification to several components I have just
21
handed out.
22
Item 2 is the draft review of the 2013 Ten-Year
Overall,
We broke it into three sections:
A
We also have an
Would you like me to go over each item?
CHAIRMAN BRISÉ:
No.
23
about them, we'll address them.
24
MR. ELLIS:
25
corrections and clarifications.
If we have questions
Overall they are just minor
For the statewide
FLORIDA PUBLIC SERVICE COMMISSION
000008
1
review, staff noticed three trends, a decline in retail
2
energy sales.
3
ten years, sales have only increased .6 percent from
4
2003 levels, but a total customer growth of 11 percent
5
during that period.
6
As of last year compared to the previous
A second trend we noticed was EPA rules having
7
an impact.
Overall, these rules are still in the
8
proposed stage or being addressed in courts, but overall
9
their impact will be to increase the cost of coal-fired
10
generation as well as increase the likelihood of
11
retirements, which leads to the third trend, which is a
12
higher natural gas usage.
13
64 percent natural gas being fuel for electricity last
14
year.
15
FPL's units and those units being off-line during that
16
period in time.
17
approximately 60 percent, but stay at that level for
18
most of the rest of the period.
19
We hit a record of about
Partly that was due to the uprates of some of
We expect it to come back down to
For the utility-specific section, the main one
20
we looked at was Duke, which is going to be relying
21
heavily on purchased power agreements, especially in
22
2016 and 2017, due to some coal retirements potentially
23
related to EPA rules.
24
capacity within the state for reserve margin purposes,
25
and the company is already pursuing RFPs for capacity
It looks to be sufficient
FLORIDA PUBLIC SERVICE COMMISSION
1
000009
within and outside of the state.
2
For comments, we had, I believe, one group
3
suggest FPL's Ten-Year Site Plan was unsuitable, it was
4
Treasure Coast Regional Planning Council.
5
concerns were associated with FPL's high dependence on
6
natural gas and a lack of renewables and energy
7
efficiency.
8
9
Their
We also had comments from Sierra Club, Earth
Justice, and SACE.
We also have additional comments
10
that were not included in the initial draft, about
11
160 pages, and we would ask for authority to add those
12
comments to Appendix A for forwarding to the Department
13
of Environmental Protection and Department of
14
Agriculture.
15
CHAIRMAN BRISÉ:
All right.
Thank you very
16
much.
Before we go to questions, I think we have Diana
17
Schenk from the Sierra Club that wants to speak.
18
Okay, she's not here.
19
So, Commissioners, the floor is open for
20
questions or comments.
21
COMMISSIONER BALBIS:
22
CHAIRMAN BRISÉ:
23
COMMISSIONER BALBIS:
24
Page 2, Figure 1.
25
May I comment?
Sure.
Commissioner Balbis.
Thank you.
And we talked about this in
our briefing, but you have an interesting graphic that
FLORIDA PUBLIC SERVICE COMMISSION
1
shows that the gap is spreading between the number of
2
customers and retail energy sales.
3
attribute that to?
000010
What do you
4
MR. ELLIS:
It's a combination of factors.
5
It's energy efficiency partly.
6
sales is probably associated with the recession, but you
7
have increased appliance standards, increased building
8
codes, a variety of conservation efforts, and things of
9
that manner are generally decreasing the per capita
The decline in energy
10
usage, so that is probably one of the major associations
11
there.
12
COMMISSIONER BALBIS:
Okay.
And then as far
13
as the number of customers, I mean, that has increased,
14
and how does that reflect on the individual customer
15
classes from residential, commercial, and industrial?
16
MR. ELLIS:
Compared to ten years ago, I
17
believe industrial is still slightly negative and will
18
probably remain negative throughout the period compared
19
to 2003.
20
recovered from their decline.
21
expected to increase throughout the period, though.
I believe residential and commercial have
Overall, those rates are
22
COMMISSIONER BALBIS:
23
to last year, do you have data on that?
24
MR. ELLIS:
25
.8 percent across all groups.
Okay.
And as compared
I believe growth was approximately
I don't have that broken
FLORIDA PUBLIC SERVICE COMMISSION
1
down by individual group, though.
2
3
COMMISSIONER BALBIS:
Okay.
That's all I
have.
4
5
000011
CHAIRMAN BRISÉ:
All right.
Any further
questions or comments?
6
Commissioner Brown.
7
COMMISSIONER BROWN:
I have a question on Page
8
31, the reserve margin.
Figure 11, the summer, the
9
summer reserve margin.
In 2020 and 2021, without the
10
demand response it goes beneath the 15 percent.
11
explain how it dips and how it fluctuates over that
12
ten-year period, highlighting those two years?
13
MR. ELLIS:
Can you
Overall, during this entire period
14
all of them are assuming the addition of incremental
15
conservation which goes into the baseline which effects
16
both the without demand response portion and with demand
17
response portion.
18
no change in generation capacity, reserve margin will
19
decrease.
20
anticipating adding in the Ten-Year Site Plans, so the
21
decline further on is mostly due to the final impacts of
22
any and all retirements of units, as well as additions
23
as they go through.
24
any specific reason why that would drop as low, compared
25
to the others.
As customer load increases, assuming
This includes all the units they are
For those two years, I can't recall
I do know in 2022 the main unit being
FLORIDA PUBLIC SERVICE COMMISSION
1
added that year is Turkey Point 6.
2
3
000012
COMMISSIONER BROWN:
And this includes the 11
utilities that filed their Ten-Year Site Plans?
4
MR. ELLIS:
This is actually the State of
5
Florida as a whole, so it's all Florida utilities,
6
including not just the Ten-Year Site Plan utilities, but
7
others that are included from the FRCC data.
8
9
COMMISSIONER BROWN:
Okay, thank you.
And
then I want to talk about the electric vehicles section.
10
You have a summary section, I think, on Page 13.
Go
11
back.
12
they measured growth in this chart.
13
current -- in 2013, the current is .025, and then in
14
2022 it jumps to 2 percent, and I'm just curious how you
15
measured that growth in the chart, those estimates.
But I just want to look at that for a second, how
16
MR. ELLIS:
It goes from the
With the electric vehicles, I
17
believe it was just on various forecasts of -- I'm
18
trying to recall specifically.
19
question?
20
Could you ask the
I think I got myself confused; I apologize.
COMMISSIONER BROWN:
Well, the estimated
21
number of plug-ins here, the plug-in EVs by service
22
territory, I was curious how they measured it in terms
23
of the estimated growth by this chart, acknowledging the
24
fact that currently in 2013 the percentage is
25
.025 percent, and then it jumps to 2 percent.
FLORIDA PUBLIC SERVICE COMMISSION
And I
000013
1
know that these are estimates, but I'm curious how they
2
actually measured it.
3
MR. ELLIS:
I think each individual utility
4
had a different method of calculating.
We asked the
5
individual utilities what their estimate within their
6
service territory would be.
7
of different industry reports, and they usually took a
8
statewide or national model and then looked at their
9
portion of that to determine the estimate of growth.
They relied upon a variety
10
Some of them were more optimistic than others, and some
11
of the scenarios were more optimistic than others.
12
COMMISSIONER BROWN:
But even that jump to 2
13
percent, that doesn't have a tremendous impact on the
14
overall grid.
15
MR. ELLIS:
No.
There's a relatively small
16
impact from electric vehicles, but it is something that
17
we noted and we are keeping track of.
18
have a greater impact on the distribution system.
19
there are several electric vehicles added to a single
20
street, it could have distribution impacts there, but I
21
don't believe we're looking at any major impacts on the
22
grid as a whole at this point.
23
24
25
COMMISSIONER BROWN:
It probably will
Thank you.
Thanks for
your work on it.
CHAIRMAN BRISÉ:
If
Any further questions?
FLORIDA PUBLIC SERVICE COMMISSION
1
Commissioner Balbis.
2
COMMISSIONER BALBIS:
000014
Yes, a follow-up on
3
Commissioner Brown's comment on Figure 11.
4
utilities forecast the additional demand-side management
5
programs as we are going through the goal-setting
6
process next year?
7
MR. ELLIS:
How do the
At this point, there are currently
8
FEECA goals established through 2019.
And for the last
9
few years for most of the utilities, I believe, they
10
just assumed a continuation of the existing plans.
Not
11
all of the utilities that are under this are under
12
FEECA.
13
not cover, so they have their own energy efficiency
14
demand response plans.
15
believe the City of Tallahassee has a summer-only one,
16
but not a winter demand response program.
17
that nature that aren't covered under FEECA.
We have several municipal utilities that we do
18
I know some of them have -- I
COMMISSIONER BALBIS:
Okay.
Things of
And the last
19
question.
20
missed this last year, but does Mr. Kelly have a plant
21
named after him, the J.R. Kelly plant?
22
23
24
25
On Table 12 on Page 30, and I don't know if I
MR. KELLY:
It ain't me.
(Audience laughter.)
It's definitely not a -- (inaudible; laughter)
MR. ELLIS:
I believe that is actually a
historic figure associated with Gainesville.
FLORIDA PUBLIC SERVICE COMMISSION
I will
1
admit to not knowing.
2
3
COMMISSIONER BALBIS:
CHAIRMAN BRISÉ:
comments?
All right.
7
posture to entertain a motion.
8
If not, we are in an appropriate
COMMISSIONER BROWN:
I move that we forward
this along to DEP and consider these plans as suitable.
10
COMMISSIONER GRAHAM:
11
CHAIRMAN BRISÉ:
12
Just curious.
Any further questions or
6
9
Okay.
That's all I had.
4
5
000015
Second.
Okay.
It has been moved and
seconded.
13
Any further discussion?
14
Seeing none, all in favor say aye.
15
(Vote taken.)
16
CHAIRMAN BRISÉ:
17
* * * * * * *
18
19
Thank you very much.
CHAIRMAN BRISÉ:
Now we move to Item Number 3,
which is our legislative update.
20
MS. PENNINGTON:
Hi, everyone.
I just have a
21
couple of things.
We had a couple of weeks off between
22
committee meetings.
23
will begin the week of -- will be the week of November
24
4th.
25
doing at that time.
The next set of committee meetings
We really haven't heard yet what committees may be
FLORIDA PUBLIC SERVICE COMMISSION
000016
1
I will tell you that the bills are starting to
2
come in.
3
couple that were filed last year, the bills relating to
4
fracturing have been filed again.
5
One thing that, you know, we have seen a
The only one I wanted to bring to your
6
attention today, and we have -- a bill analysis request
7
has been made of us, and that's Senate Bill 272 by
8
Senator Simpson.
9
there are some similarities in that bill and the bill
10
It's a water and wastewater bill, and
that Senator Hays filed last year.
11
Senator Simpson's bill seems to focus on two
12
areas.
13
committee recommendations, and to my memory was not
14
discussed, is that it would basically say that the rates
15
of investor-owned water and wastewater utilities could
16
not be higher than the rates of the government-owned
17
municipal utility, if there is one located in the same
18
county.
19
must adjust those rates to no more than the municipal or
20
government-owned water or wastewater utility back to the
21
rates at the last rate hearing, and that the utility
22
must refund all monies within 12 months.
23
not part of the recommendations of the study committee.
24
25
The first one, which is not one of the study
It further, basically, says that the Commission
So that was
He does seem to have picked up the secondary
water standard language that was part of the study
FLORIDA PUBLIC SERVICE COMMISSION
000017
1
committee's recommendations that the Commission would
2
take that into account using information from the
3
Department of Environmental Regulation, water management
4
districts, local governments, consumer complaints,
5
et cetera, that they would use that same information to
6
take -- into considering secondary water standards.
7
We have not finished our analysis yet.
We may
8
have a draft by tomorrow.
9
just responding to a lot of inquiries and requests and
10
And other than that, we are
getting ready for committee meetings again.
11
CHAIRMAN BRISÉ:
All right.
Thank you.
12
Questions?
13
Commissioner Graham.
14
COMMISSIONER GRAHAM:
15
To Senator Simpson's bill, does it say
Thank you, Mr. Chairman.
16
anything or allude to anything as far as property tax
17
and taxable value, because municipals don't have to pay
18
property tax.
19
MS. PENNINGTON:
It does not.
20
COMMISSIONER GRAHAM:
Okay.
And you said that
21
staff is in the process of making sure that we put
22
together an analysis?
23
24
25
MS. PENNINGTON:
Yes, sir.
We are working on
an analysis now.
COMMISSIONER GRAHAM:
Okay.
That's all I
FLORIDA PUBLIC SERVICE COMMISSION
1
000018
have.
2
CHAIRMAN BRISÉ:
3
COMMISSIONER EDGAR:
4
Commissioner Edgar.
Thank you.
Just a
calendar question.
5
MS. PENNINGTON:
Yes, ma'am.
6
COMMISSIONER EDGAR:
Katherine, if you know,
7
and if not, that's okay.
8
November 4th, how many more dates do they have scheduled
9
for committee meetings prior to the end of the year?
10
11
MS. PENNINGTON:
After the week of
Let me not misspeak, and I
will -- (inaudible; simultaneous conversation)
12
COMMISSIONER EDGAR:
13
MS. PENNINGTON:
Yes, I will.
14
just don't want to misspeak.
15
but I want to be sure.
16
All of us.
Absolutely.
I think I could tell you,
The other thing, I did want to mention that
17
Commissioner Brown did a great job in front of the
18
Senate --
19
COMMISSIONER BROWN:
20
MS. PENNINGTON:
21
and Public Utilities Committee a couple of weeks ago.
COMMISSIONER BROWN:
23
MS. PENNINGTON:
24
25
No, I didn't.
-- Communications, Energy,
22
I
Thank you.
I don't know what they are
going to do with the information yet, but she did.
Yes, you did.
FLORIDA PUBLIC SERVICE COMMISSION
1
2
COMMISSIONER BROWN:
I spoke faster than
Speedy Gonzalez.
3
Thank you for your comments.
4
MS. PENNINGTON:
And Senator Hays is still
5
intending to file the bill that he filed last year
6
regarding the recommendation for the water and
7
wastewater study committee.
8
9
CHAIRMAN BRISÉ:
All right.
Anything else?
Seeing none, thank you very much.
10
MS. PENNINGTON:
11
Thank you.
* * * * * * *
12
CHAIRMAN BRISÉ:
13
MR. BAEZ:
14
Two items.
15
000019
Executive Director, Mr. Baez.
Thank you, Mr. Chairman.
One brief one, just following up
on the legislative update.
16
We are presenting our LBR and our Schedule AB
17
Budget before the House Subcommittee on November 6th, I
18
believe.
19
the afternoon for those of you that are interested,
20
that's November 6th.
21
It's a short time slot, and I believe it's in
And my final item is a bittersweet one.
As
22
many of you may know, Ann Cole, our Commission Clerk, is
23
leaving us.
24
had probably in the, I think, relatively short time that
25
she has been here -- she joined the Commission in '07, I
November 14th is her last day.
FLORIDA PUBLIC SERVICE COMMISSION
And she has
000020
1
believe -- in that relatively short time that she has
2
been here, she has had as much to do with this agency
3
being dragged kicking and screaming into the late 20th
4
Century as anyone in the building, and we are going to
5
miss her.
6
That's the bitter part.
The sweet part is that I'd like to propose her
7
successor.
Many of you know Carlotta Stauffer.
She has
8
been working with Ann these last several months, and
9
actually had occasion to work with her for a long time
10
at DOAH, which is where they both originated.
11
has had good opportunity to learn Ann's brain and to
12
understand her vision and her way of doing things and
13
the good things that she has done for us, as well.
14
I'd like to nominate her or appoint her as the next
15
Commission Clerk.
16
So she
And
I can think of nobody better to take Ann's
17
place, in part not just because of their experience
18
together, but because, you know, Carlotta and I worked
19
together for some time, and I think she has as much as
20
anyone a terrific understanding both of the steps that
21
Ann has put into place and the efforts that Ann has
22
started us off on for the long-term.
23
Carlotta understands as well as anyone what we're
24
trying -- what executive management has been trying to
25
do along those lines.
And, also,
So if there's anyone better to
FLORIDA PUBLIC SERVICE COMMISSION
000021
1
bring all of these good things in for a landing and to a
2
successful completion, I can't think of a one.
3
your consent, I would like to name Carlotta Stauffer as
4
our next Commission Clerk.
5
CHAIRMAN BRISÉ:
6
Any comments, Commissioners?
7
COMMISSIONER EDGAR:
8
CHAIRMAN BRISÉ:
9
does this require a vote?
Thank you.
MR. BAEZ:
11
COMMISSIONER BROWN:
12
CHAIRMAN BRISÉ:
13
COMMISSIONER BROWN:
14
MR. BAEZ:
15
COMMISSIONER BROWN:
you.
17
together.
I know.
I'm going to miss you a
lot.
21
25
Ann, we are going to miss
You and I have gotten really close being so close
COMMISSIONER BROWN:
24
Yes, good choice.
Thank you, Commissioner.
19
23
If I may?
Sure.
MS. COLE:
22
I can't recall,
A simple nod would do.
18
20
Great choice.
All right.
10
16
So with
And, Carlotta, I'm looking forward to working
with you.
And best wishes to you in your future
endeavors.
CHAIRMAN BRISÉ:
All right.
FLORIDA PUBLIC SERVICE COMMISSION
1
MR. BAEZ:
2
CHAIRMAN BRISÉ:
3
MR. BAEZ:
4
CHAIRMAN BRISÉ:
5
Thank you, Commissioners.
Thank you.
Excellent choice.
I think so, too.
And, Ann, we will stack up
some more work before the 14th.
6
(Audience laughter.)
7
CHAIRMAN BRISÉ:
But, in all seriousness, we
8
definitely want to thank you for your service to the
9
Commission.
10
MS. COLE:
11
CHAIRMAN BRISÉ:
12
It's been fun.
MS. STAUFFER:
14
CHAIRMAN BRISÉ:
Thank you.
MR. BAEZ:
17
CHAIRMAN BRISÉ:
18
MR. BAEZ:
19
21
22
23
24
25
All right.
Anything else,
Mr. Baez?
16
20
And, Carlotta, we expect
great things from you going forward, as well.
13
15
000022
Nothing else today.
Okay.
Thank you, Chairman.
* * * * * * *
CHAIRMAN BRISÉ:
other matters today?
Other matters; anything on
Okay.
Seeing none.
All right.
With that,
Commissioner Graham moves we rise.
(Internal Affairs meeting concluded at
2:29 p.m.)
FLORIDA PUBLIC SERVICE COMMISSION
000023
1
2
STATE OF FLORIDA
CERTIFICATE OF REPORTER
3
4
COUNTY OF LEON
5
6
7
8
9
10
11
12
13
14
I, JANE FAUROT, RPR, Chief, Hearing Reporter
Services Section, FPSC Division of Commission Clerk, do
hereby certify that the foregoing proceeding was heard
at the time and place herein stated.
IT IS FURTHER CERTIFIED that I
stenographically reported the said proceedings; that the
same has been transcribed under my direct supervision;
and that this transcript constitutes a true
transcription of my notes of said proceedings.
I FURTHER CERTIFY that I am not a relative,
employee, attorney or counsel of any of the parties, nor
am I a relative or employee of any of the parties'
attorney or counsel connected with the action, nor am I
financially interested in the action.
DATED THIS 1st day of November,
2013.
15
16
17
18
ANE FAUROT, RPR
1 FPSC Hearings Reporter
(850)
413-6732
19
20
21
22
23
24
25
FLORIDA PUBLIC SERVICE COMMISSION

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