ARP EC Agenda Package - FMPA Member Portal

Transcription

Florida Municipal Power Agency
Executive Committee Meeting
August 25, 2016
9:45 a.m.
Executive Committee
Howard McKinnon, Havana - Chairman
Lynne Tejeda, Key West – Vice Chairwoman
Bruce Hickle, Bushnell
Lynne Mila, Clewiston
Fred Hilliard, Fort Meade
Clay Lindstrom, Fort Pierce
Robert Page, Green Cove Springs
Allen Putnam, Jacksonville Beach
Larry Mattern, Kissimmee
Patrick Foster, Leesburg
Bill Conrad, Newberry
Mike Poucher, Ocala
Tom Ernharth, Starke
Meeting Held 9:45 a.m.
Thursday, August 25, 2016
8553 Commodity Circle
Orlando, FL 32819
407-355-7767
Page 1 of 223
TO:
FMPA Executive Committee
FROM:
Nicholas Guarriello
DATE:
August 16, 2016
RE:
Thursday, August 25, 2016 at 9:45 a.m.
(Or Immediately Following the FMPA Executive Search Committee Meeting)
PLACE:
Florida Municipal Power Agency,
8553 Commodity Circle, Orlando, FL
Board Room, Orlando, Florida
DIAL-IN INFORMATION: 866-411-8247 or 321-239-1100
ACCESS CODE 91583#
(If you have trouble connecting via phone or internet, please call 407-355-7767)
Chairman Howard McKinnon, Presiding
AGENDA
1)
Call to Order, Roll Call, Declaration of Quorum ..................................................................... 4
2)
Set Agenda (By Vote).................................................................................................................. 5
3)
Recognition of Guests .................................................................................................................. 6
4)
Public Comments (Individual Public comments to be limited to 3 minutes) ......................... 7
5)
Comments from the Chairman (Howard McKinnon) ............................................................. 8
6)
Report from the General Manager (Nick Guarriello).............................................................. 9
7)
Sunshine Law Update (Jody Finklea) ...................................................................................... 10
Page 2 of 223
FMPA Executive Committee Meeting
August 16, 2016
Page 2
8)
Consent Agenda
a) Approval of Meeting Minutes– Meeting Held July 22, 2016; ARP Telephonic Rate Workshop
Minutes – Workshops Held July 7, 2016.................................................................................. 12
b) Approval of Treasury Reports – As of June 30, 2016 .............................................................. 19
c) Approval of the Agency and All-Requirements Project Financials as of June 30, 2016 ......... 23
d) Acceptance of Fuel Position Portfolio Report June 2016 (previously known as the Hedge
Position Portfolio Update) (Rich Popp) .................................................................................... 25
9) Action Items
a) Approval of Amended and Restated Peoples Gas Contract (Joe McKinney/Frank Gaffney) .. 29
b) Approval of ARP Contract Section 29 Withdrawal Payment Calculation Protocols (Fred
Bryant/Jody Finklea/Frank Gaffney) ........................................................................................ 94
10) Information Items
a) Results of Swap Advisory RFP (Ed Nunez) ........................................................................... 110
b) Wells Fargo Credit Agreement for Line of Credit (Mark Larson) ......................................... 113
c) ARP Contract Section 29 Withdrawal Payment Estimates for All ARP Participants (Fred
Bryant/Jody Finklea/Frank Gaffney) ...................................................................................... 116
11) Other Information
a) FYI – Invoice Summary Report from Spiegel and McDiarmid ............................................. 221
12) Member Comments…………………………………………………………………………….222
13) Adjournment……………………………………………………………………………………223
One or more participants in the above referenced public meeting may participate by telephone. At the above location there will be a speaker telephone so that any interested
person can attend this public meeting and be fully informed of the discussions taking place either in person or by telephone communication. If anyone chooses to appeal any
decision that may be made at this public meeting, such person will need a record of the proceedings and should accordingly ensure that a verbatim record of the proceedings is
made, which includes the oral statements and evidence upon which such appeal is based. This public meeting may be continued to a date and time certain, which will be
announced at the meeting. Any person requiring a special accommodation to participate in this public meeting because of a disability, should contact FMPA at (407) 355-7767
or 1-(888)-774-7606, at least two (2) business days in advance to make appropriate arrangements.
Page 3 of 223
AGENDA ITEM 1 – CALL TO ORDER,
ROLL CALL, DECLARATION OF QUORUM
Executive Committee
August 25, 2016
Page 4 of 223
AGENDA ITEM 2 – SET AGENDA (By Vote)
Executive Committee
August 25, 2016
Page 5 of 223
AGENDA ITEM 3 – RECOGNITION OF
GUESTS
Executive Committee
August 25, 2016
Page 6 of 223
AGENDA ITEM 4 –PUBLIC COMMENTS
(INDIVIDUAL COMMENTS TO BE
LIMITED TO 3 MINUTES)
August 25, 2016
Page 7 of 223
VERBAL
REPORT
VERBAL REPORT
AGENDA ITEM 5 – COMMENTS FROM THE
CHAIRMAN
Executive Committee
August 25, 2016
Page 8 of 223
VERBAL
REPORT
VERBAL REPORT
AGENDA ITEM 6 – REPORT FROM THE
GENERAL MANAGER
Executive Committee
August 25, 2016
Page 9 of 223
VERBAL
REPORT
VERBAL REPORT
AGENDA ITEM 7 – SUNSHINE LAW UPDATE
Executive Committee
August 25, 2016
Page 10 of 223
AGENDA ITEM 8 – CONSENT AGENDA
a)
Approval of Meeting Minutes – Meeting Held July
22, 2016; ARP Telephonic Rate Workshop Minutes –
Workshops Held July 7, 2016
Executive Committee
August 25, 2016
Page 11 of 223
CLERKS DULY NOTIFIED……………………………………………....….July 13, 2016
AGENDA PACKAGES/CDS FEDEXED TO MEMBERS…..…………….. July 13, 2016
MINUTES
EXECUTIVE COMMITTEE
THURSDAY JULY 22, 2016
FLORIDA MUNICIPAL POWER AGENCY
8553 COMMODITY CIRCLE
ORLANDO, FL 32819
PARTICIPANTS PRESENT
Bushnell
Clewiston
Fort Pierce
Havana
Jacksonville Beach Key West
Kissimmee
Leesburg
Newberry
Ocala
Starke
-
Bruce Hickle (via telephone)
Lynne Mila
Clay Lindstrom
Howard McKinnon
Allen Putnam
Lynne Tejeda
Larry Mattern
Patrick Foster
Bill Conrad
Mike Poucher
Tom Ernharth
Fort Meade
Green Cove Springs -
Fred Hilliard
Robert Page
PARTICIPANTS ABSENT
OTHERS PRESENT
David Anderson, Ocala
Brad Hiers, Bartow
George Forbes, Jacksonville Beach
Karen Nelson, Jacksonville Beach
Terry Atchley, Wauchula
Donna Painter, nFront Consulting
Steve Stein, nFront Consulting
Paul Jakubczak, Fort Pierce
Elizabeth Columbo, Nixon Peabody
Barry Rothchild, Nixon Peabody
Thomas Geoffroy, Florida Gas Utility
Page 12 of 223
Executive Committee Meeting Minutes
July 22, 2016
Page 2 of 4
STAFF PRESENT
Nick Guarriello, General Manager and CEO
Fred Bryant, General Counsel
Jody Finklea, Deputy General Counsel and Manager of Legal
Affairs
Mark McCain, Assistant General Manager, Public Relations &
Human Resources
Mark Larson, Assistant General Manager, Finance and Information
Technology and CFO
Frank Gaffney, Assistant General Manager, Power Resources
Michelle Pisarri, Administrative Coordinator
Sue Utley, Executive Assistant to the CEO/Asst. Secy. to the BOD
Rich Popp, Contract Compliance Audit and Risk Manager
Joe McKinney, System Operations Manager
Tom Richards, Executive Consultant
Denise Fuentes, Accountant II
Edwin Nunez, Assistant Treasurer/Debt
ITEM 1 - CALL TO ORDER, ROLL CALL, AND DECLARATION OF QUORUM:
Chairman Howard McKinnon, Havana, called the FMPA Executive Committee meeting to order
at 10:04 a.m. on Friday, July 22, 2016 in the Boardroom, Florida Municipal Power Agency, 8553
Commodity Circle, Orlando, Florida. The roll was taken and a quorum was declared with 11
members present out of a possible 13.
ITEM 2 – SET AGENDA (BY VOTE):
MOTION: Mr. Putnam, Jacksonville Beach, moved to set the agenda as presented. Mr. Foster,
Leesburg, seconded the motion. Motion carried 11-0.
ITEM 3 – RECOGNITION OF GUESTS:
Chairman McKinnon recognized FMPA Board of Directors members Terry Atchley of Wauchula
and Brad Hiers of Bartow.
ITEM 4 – PUBLIC COMMENTS:
None.
Page 13 of 223
July 22, 2016
Page 3 of 4
ITEM 5 – COMMENTS FROM THE CHAIRMAN:
Chairman McKinnon expressed his appreciation of the honest conversation that the Board of
Directors had the previous meeting and he looks forward to working with Jacob Williams. He
also stated that Nick’s retirement party will be held on August 24, the night before the August
25 meetings.
ITEM 6 – REPORT FROM GENERAL MANAGER:
Nick Guarriello, General Manager and CEO, reported on ARP Contract Section 29 protocols;
recent FERC actions; and joint action solar efforts.
ITEM 7 –SUNSHINE LAW UPDATE IN A MINUTE:
Jody Finklea, Deputy General Counsel, provided a verbal report on a public records
exemptions.
ITEM 8 –CONSENT AGENDA:
Item 8a – Approval of Meeting Minutes– Meeting Held June 23, 2016;
Telephonic Rate Workshop Minutes – Workshop Held June 9, 2016
ARP
Item 8b - Approval of Treasury Reports - As of May 31, 2016
Item 8c – Approval of the Agency and All-Requirements Project Financials as of
May 31, 2016
Item 8d – Acceptance of Fuel Position Portfolio Update (previously known as the
Hedge Position Portfolio Update) – May 2016
MOTION: Mr. Putnam, Jacksonville Beach, moved approval of the consent agenda as
presented. Mr. Poucher, Ocala, seconded the motion. Motion carried 11-0.
Page 14 of 223
July 22, 2016
Page 4 of 4
ITEM 9 – ACTION ITEMS:
Item 9a— Election of Executive Committee Officers
MOTION: Mr. Mattern, Kissimmee, moved to nominate and retain the current slate of officers,
Mr. Howard McKinnon of Havana as Chairperson and Mrs. Lynne Tejeda of Key West as ViceChairperson. Mr. Conrad, Newberry, seconded the motion. There were no other nominations.
Vote was taken to accept the nominations and elect the nominees as the Executive Committee
Chairperson and Vice Chairperson. Election was approved 11-0.
ITEM 10 – INFORMATION ITEMS:
a.
b.
c.
d.
e.
f.
ARP Cost Cutting Measures Update
Amended and Restated Peoples Gas Contract
Natural Gas Update
KEYS TARP O&M Amendment
ARP Contract Section 29 Withdrawal Payment Calculation Protocols
Notice of Annual 2016 Continuing Disclosure Report for Fiscal Year Ended
September 30, 2015
Discussion with the Executive Committee as to the above items was taken in turn.
ITEM 12 – MEMBER COMMENTS:
Mr. Mattern commented on the good and healthy discussions had.
ITEM 13 – ADJOURNMENT:
There being no further business, the meeting was adjourned at 11:51 a.m.
Howard McKinnon
Chairperson, Executive Committee
Approved:
Sue Utley
Assistant Secretary
Seal
Page 15 of 223
AGENDA PACKAGES SENT TO MEMBERS ................................................. July 7, 2016
PUBLIC NOTICE SENT TO CLERKS ..........................................................June 27, 2016
MINUTES
EXECUTIVE COMMITTEE
ALL-REQUIREMENTS POWER SUPPLY PROJECT
TELEPHONIC RATE WORKSHOP
THURSDAY, JULY 7, 2016
8553 COMMODITY CIRCLE
ORLANDO, FLORIDA 32819
COMMITTEE MEMBERS PRESENT
Clewiston
Fort Pierce
Green Cove Springs Havana
Leesburg
Newberry
Starke
-
Lynne Mila (via telephone)
Clay Lindstrom (via telephone)
Robert Page (via telephone)
Howard McKinnon(via telephone)
Patrick Foster (via telephone)
Bill Conrad (via telephone)
Ricky Thompson (via telephone)
COMMITTEE MEMBERS ABSENT
Bushnell
Fort Meade
Jacksonville Beach
Key West
Kissimmee
Ocala
-
Bruce Hickle
Fred Hilliard
Allen Putnam
Lynne Tejeda
Larry Mattern
Mike Poucher
OTHERS PRESENT
David Anderson, Ocala (via telephone)
STAFF PRESENT
Nick Guarriello, General Manager and CEO
Frank Gaffney, Assistant General Manager, Power Resources
Mark Larson, Assistant General Manager, Finance and IT and CFO
Mark McCain, Assistant General Manager, Member Services, Human
Resources and Public Relations
Rich Popp, Contract Compliance Audit and Risk Manager
Jim Arntz, Senior Financial Analyst
Jason Wolfe, Financial Analyst and Power Supply Contracts
Administrator
Michelle Pisarri, Administrative Coordinator
Page 16 of 223
EC ARP Rate Telephonic Workshop Minutes
July 7, 2016
Page 2 of 2
Jody Lamar Finklea, Deputy General Counsel and Manager of
Legal Affairs (via telephone)
Item 1 – Call to Order
Chairman Howard McKinnon called the Executive Committee All-Requirements Telephonic
Rate Workshop to order at 2:00 p.m. on Thursday, July 7, 2016, via telephone. A speaker
telephone for public attendance and participation was located in the Board Room at Florida
Municipal Power Agency, 8553 Commodity Circle, Orlando, Florida.
Item 2 – Information Items
Mr. Popp gave a verbal update on the natural gas markets. Mr. Larson gave a verbal update
on ARP liquidity. Mr. McKinney provided a verbal report on Florida Municipal Power Pool
Operations for June. Mr. Arntz reviewed the loads, costs and ARP rate calculations for the
month of June and estimated rate ranges for July 2016 and August 2016.
Item 3 – Member Comments
None.
There being no further business, the meeting was adjourned at 2:15 p.m.
Approved
ML/JA/mlp
Page 17 of 223
b)
Approval of Treasury Reports - As of June 30, 2016
Executive Committee
August 25, 2016
Page 18 of 223
AGENDA PACKAGE MEMORANDUM
TO:
FROM:
Gloria Reyes
DATE:
August 14, 2016
ITEM:
EC 8(b) – Approval of the All-Requirements Project Treasury Reports as of
June 30, 2016
Strategic Relevance FMPA’s Relevant Strategic Goals
1. Be the lowest cost, sustainable wholesale power provider in Florida
2. Foster a positive communication culture
Policy Decisions/Implications
• To report operation and effectiveness of asset management
• To report on the current opportunities and risk environment affecting
FMPA
Introduction
• This report is a quick update on the Treasury Department’s functions.
• The Treasury Department reports for June are posted in the member
portal section of FMPA’s website.
Debt
Discussion
The All-Requirements Project has fixed, variable, and synthetically fixed
rate debt. The variable rate portion is 1.18%. The fixed and synthetic fixed
rate percentages of total debt are 72.56% and 26.26%, respectively. The
estimated debt interest funding for fiscal year 2016 as of
June 30, 2016 is $59,450,368.75. The total amount of debt outstanding is
$1,054,103,000.
Page 19 of 223
EC 8(b) – Approval of the All-Requirements Project Treasury Reports as of June 30, 2016
August 14, 2016
Page 2
Hedging
Discussion
The Project has 16 interest rate swap contracts. As of June 30, 2016, the
cumulative market value of the interest rate swaps in the
All-Requirements Project was (74,001,164).
The Swap Valuation Report is a snap shot of the mark-to-market values at
the end of the day on June 30, 2016. The report for June is posted in the
“Member Portal” section of FMPA’s website.
Investment
Discussion
The investments in the Project are comprised of debt from the
government-sponsored enterprises such as the Federal Farm Credit Bank,
Federal Home Loan Bank, Federal Home Loan Mortgage Corporation
(Freddie Mac), and Federal National Mortgage Association (Fannie Mae), as
well as investments in U.S. Treasuries, Municipal Bonds, Commercial Paper
and Money Market Mutual Funds.
As of June 30, 2016, the All-Requirements Project investment portfolio
earned a weighted average rate of return of 0.78%, reflecting the AllRequirements Project need for liquidity given its 60-day cash position. The
benchmarks (SBA’s Florida Prime Fund and the 10 year US Treasury Note)
and the Project’s yields are graphed below:
All-Requirement's Weighted Average Yield
5-Year History
4.00%
3.00%
2.00%
1.00%
FL Prime
10 YR Treas
Page 20 of 223
All Req
Jun-16
Mar-16
Dec-15
Sep-15
Jun-15
Mar-15
Dec-14
Sep-14
Jun-14
Mar-14
Dec-13
Sep-13
Jun-13
Mar-13
Dec-12
Sep-12
Jun-12
Mar-12
Dec-11
Sep-11
Jun-11
0.00%
EC 8(b) – Approval of the All-Requirements Project Treasury Reports as of June 30, 2016
August 14, 2016
Page 3
Below is a graph of U.S. Treasury yields for the past 5 years.
US Government Treasury Securities Interest Rates
5-Year History
3.50
3.00
2.50
2.00
1.50
1.00
0.50
2-Yr Treasury Yield
5-Yr Treasury Yield
10-Yr Treasury Yield
The Investment Report for June is posted in the “Member Portal” section of
FMPA’s website.
Recommended
Motion
Move approval of the Treasury Reports for June 30, 2016
Page 21 of 223
6/30/2016
3/31/2016
12/31/2015
9/30/2015
6/30/2015
3/31/2015
12/31/2014
9/30/2014
6/30/2014
3/31/2014
12/31/2013
9/30/2013
6/30/2013
3/31/2013
12/31/2012
9/30/2012
6/30/2012
3/31/2012
12/31/2011
9/30/2011
6/30/2011
0.00
c) Approval of the Agency and All-Requirements
Project Financials as of June 30, 2016
Executive Committee
August 25, 2016
Page 22 of 223
TO:
FROM:
Rick Minch
DATE:
August 16, 2016
ITEM:
EC 8c – Approval of the Agency and All-Requirements Project Financials
for the period ended June 30, 2016.
Discussion:
The summary and detailed financial statements of the Agency and
All-Requirements Project for the period ended June 30, 2016 are
posted on the members’ only FMPA website.
____________________________________________________________________________
Recommended Motion:
Move approval of the Agency and All-Requirements Project
Financial reports for the month of June 30, 2016.
______________________________________________________________________
RM/DF
Page 23 of 223
d) Acceptance of the Fuel Position Portfolio Report
June 2016 (previously known as the Hedge
Position Portfolio Update)
Executive Committee
August 25, 2016
Page 24 of 223
TO:
Executive Committee
FROM:
Rich Popp
DATE:
August 16, 2016
ITEM:
EC 8d-Acceptance of Fuel Portfolio Position Report June 2016
Strategic Relevance
FMPA’s relevant strategic goals
• Be the lowest cost wholesale electricity provider in Florida through strategy to identify,
understand and manage risk responsibly.
Policy decisions/implications
• The Natural Gas and Fuel Oil Risk Policy requires that specific information be reported
at each Executive Committee and Audit and Risk Oversight Committee meetings
(“AROC”).
Introduction
The Policy requires the Agency Risk Manager to report the following at each AROC and
Executive Committee meeting:
1. Current hedge position (if approved hedging program by the EC)
2. Monthly hedge position gain or loss (if approved hedging program by the EC)
3. Monthly liquidity exposure (if approved hedging program by the EC)
4. Fuel storage activity both natural gas and fuel oil
5. Physical natural gas commitments
Explanation
The following information illustrates the All-Requirements Project’s fuel positions on June
30, 2016 unless otherwise noted.
Physical Hedge Limits
The Policy allows staff though FGU to commit to physical natural gas volumes of no more
than 75% of the monthly-expected burn. ARP had physical gas commitments equal to 33%
of June 2016’s actual gas burned for Net Energy for Load.
Natural gas storage
The ARP has contracted for 1,000,000 MMBtu of natural gas storage. The Policy sets
minimum storage levels for reliability purposes at 50% of maximum available storage
during hurricane season (June through January) and 10% of maximum available storage for
all other months. The following exhibit shows actual storage inventory volume for the past
twelve months compared to the minimum levels.
Page 25 of 223
Fuel Portfolio Position report
Page 2
1,000,000
900,000
800,000
700,000
MMBtu
600,000
500,000
400,000
300,000
200,000
100,000
Gas in storage
Jun
May
Apr
Mar
Feb
Jan
Dec
Nov
Oct
Sep
Aug
Jul
0
Policy minimum
The storage volume on June 30, 2016 was 642,456 MMBtu at a weighted average cost of
$2.57/ MMBtu. The total value of gas in storage was $1,652,939.
The storage agent (Florida Gas Utility) provides an updated storage optimization report at
each AROC meeting.
Gallons
Fuel oil storage
As of June 30, 2016, fuel oil storage levels at ARP generation resource locations are
presented below:
2,200,000
2,000,000
1,800,000
1,600,000
1,400,000
1,200,000
1,000,000
800,000
600,000
400,000
200,000
-
Stock Island
Fuel Oil
Cane Island
TCEC
Oleander 5
Staff Action Plan needed
The Policy requires that fuel oil storage at each generation site strive to maintain a
minimum 50% of fuel oil capacity. When fuel is below the 50% capacity threshold, FMPA
staff will develop a plan to bring inventory levels above 50% capacity. Treasure Coast
Energy Center is 49.9% of capacity. Do to the infrequent use of oiled at TCEC, staff has no
plans on purchasing additional supply fuel oil at his time.
Page 26 of 223
Fuel Portfolio Position report
Page 3
Hedge program results
The following table shows the gains or (losses) resulting from the hedge program.
Fiscal Year
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016-YTD
Version 8
$ (3,844,385)
$
6,211,729
$ 19,254,388
$
482,038
$ (32,303,698)
$ 11,136,570
$ (140,564,807)
$ (41,347,894)
$ (17,402,281)
$ (20,474,986)
$ (16,883,175)
$ ( 2,679,175)
N/A
N/A
Version 9 (FST)
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
$ (6,236,892)
$ (1,424,568)
$ (1,554,448)
N/A
N/A
N/A
Total
$ (3,844,385)
$
6,211,729
$ 19,254,388
$
482,038
$ (32,303,698)
$ 11,136,570
$ (140,564,807)
$ (41,347,894)
$ (23,639,173)
$ (21,899,554)
$ (18,437,623)
$ ( 2,679,175)
$
0
$
0
Life-to-date
$ (238,415,676)
$ (9,215,908)
$ (247,631,584)
Blended Cost
Blended Cost represents the weighted average of hedge costs, if approved hedging program
by the EC, and market priced gas for each month, excluding transportation costs.
Projected
Blended
Natural Gas
Cost
$2.59
Actual June
Natural
Gas
Market
Price*
$1.96
%
Over/(Under)
Market
32%
Projected
Natural Gas
Transportation
Cost
$0.43
The following graphic illustrates the projected Blended Cost, actual Blended Cost, and the
natural gas market prices (NYMEX).
$6.00
$5.50
$5.00
$4.50
$4.00
$3.50
$3.00
$2.50
$2.00
Recommended
Motion
Projected Blended Cost
Actual Blended Cost
NYMEX Settlement
NYMEX-Forward Curve
Move to accept Fuel Portfolio Position Report for June 2016.
Page 27 of 223
Jun-16
May-16
Apr-16
Mar-16
Feb-16
Jan-16
Dec-15
Nov-15
Oct-15
Sep-15
Aug-15
Jul-15
Jun-15
May-15
Apr-15
Mar-15
Feb-15
Jan-15
Dec-14
$1.50
AGENDA ITEM 9 – ACTION ITEMS
a) Approval of Amended and Restated Peoples Gas
Contract
Executive Committee
August 25, 2016
Page 28 of 223
TO:
FROM:
Joe McKinney
DATE:
August 16, 2016
ITEM:
EC 9a – Approval of Amended and Restated Peoples Gas Contract
Strategic Relevance
FMPA’s Relevant Strategic Goals
1. As a wholesale power provider, become and remain competitive in the Florida
Market.
Introduction
• Staff discovered a billing discrepancy during a review of the Peoples Gas
System (PGS) Gas Transportation Agreement invoice. PGS had been
calculating the rate for gas delivery incorrectly and Staff determined this had
been ongoing since May 2008. The error had resulted in FMPA being
overcharged approximately $1,100,000.
• PGS has agreed with Staff’s calculation and has been working with Staff to
resolve the overpayment. PGS has repaid $250,000 to FMPA and Staff and
PGS have renegotiated the Gas Transportation Agreements and Pipeline
Capacity Agreements that provides FMPA almost double the value of the
remaining balance over the next four years.
The key revisions to the agreements provide for a discounted rate on gas
transportation for 4 years, an extension of the term of the agreements, and more
favorable termination provisions for FMPA.
• The PGS agreements save FMPA approximately $6 MM per year by allowing
us to avoid a fixed pipeline capacity cost. We pay for the capacity when we use
it and can buy delivered gas if delivered gas is less expensive.
• Staff is requesting approval of the Amended and Restated Gas Transportation
Agreement and the Amended and Restated Pipeline Capacity Agreement
between FMPA and PGS.
Explanation
FMPA has a Gas Transportation Agreement with PGS to deliver gas to the
Treasure Coast Energy Center. The agreement specifies the distribution charge
will be $0.102 per MMBTU for the first 10,000,000 MMBTU per year and then
change to $0.02 per MMBTU for the remainder of the year. PGS failed to
implement this reduction in their billing. Staff discovered this error during a
Page 29 of 223
August 16, 2016
Page 2
review of the invoice to the agreement terms and determined FMPA had been
overcharged $1,081,369.26.
In addition to the Gas Transportation Agreement, FMPA and PGS have a Pipeline
Capacity Agreement to provide firm gas pipeline capacity to the Treasure Coast
Energy Center. This agreement provides FMPA, through our agent Florida Gas
Utility (FGU), the opportunity on a daily basis to use this capacity or release it
back to PGS at no cost and replace it with delivered gas purchased on the daily
market. The terms of this agreement require the Gas Transportation Agreement to
remain in effect or PGS has the right to terminate the pipeline capacity agreement.
FMPA has a similar set agreements with PGS for gas transportation and pipeline
capacity to serve the Cane Island and Oleander generation facilities.
The Pipeline Capacity Agreements have been extremely beneficial to FMPA.
Staff estimates we save $6,000,000 annually under these agreements by not
incurring fixed capacity charges on the pipeline(s) and instead only pay for the
pipeline capacity when we use it, being able to purchase delivered gas in the daily
market, while still having the right to the firm capacity from PGS if needed.
Analysis
PGS has agreed with Staff’s analysis of the overcharges and has been working
with Staff to resolve the matter. PGS has repaid FMPA $250,000 of the
overcharges and has worked with FMPA to renegotiate the agreements for both
Treasure Coast Energy Center and Cane Island/Oleander.
The key revisions to the agreements are:
Legal Review
•
The two separate Gas Transportation Agreements have been combined into
one agreement and the two separate Pipeline Capacity Agreements have
been combined into one agreement.
•
The term of the agreements have been extended 10 years to better match the
expected life of our units and FMPA has an option for an additional 5 years
extension at FMPA’s sole discretion.
•
FMPA has the option to reduce service under the agreements if units are
retired or the Oleander PPA expires.
•
The distribution charges under the Gas Transportation Agreement are
reduced for a four year period. FMPA staff estimates savings from the
reduced rates to be at least $1,255,000 to FMPA over a four year period,
2017 through 2021, gaining about one and one half times the value we are
owed.
The Amended and Restated Gas Transportation Agreement and the Amended and
Restated Pipeline Capacity Agreement are complete and have been reviewed by
FMPA’s Office of General Counsel and external FERC counsel. A redline to the
Page 30 of 223
August 16, 2016
Page 3
agreements provided in the July agenda package are attached, along with the clean
final documents.
Recommended Motion
Move for approval of the Amended and Restated Gas Transportation Agreement
and the Amended and Restated Pipeline Capacity Agreement and authorize their
execution by the General Manager and CEO.
JRM
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AMENDED AND RESTATED
CAPACITY RELEASE AGREEMENT
PIPELINE CAPACITY RELEASE AGREEMENT
This Amended and Restated Pipeline Capacity Release Agreement (this “Agreement”) is
made and entered into as of this 1st day of September, 2016, by and between Peoples Gas System,
a Division of Tampa Electric Company, a Florida corporation (“PGS”), and Florida Municipal
Power Agency (All-Requirements Power Supply Project), a governmental legal entity created
and existing pursuant to Florida law (“Customer”).
W I T N E S S E T H:
WHEREAS, PGS has contracted for certain transportation capacity pursuant to agreements
with Florida Gas Transmission Company, LLC, a Delaware limited liability company (“FGT”) and
Gulfstream Natural Gas System, L.L.C. (“GS”), a Delaware limited liability company (FGT and GS,
collectively, the “Pipelines,” and each a “Pipeline,” and said agreements and any amendatory or
superseding agreements being hereinafter referred to collectively as the “Pipeline Agreements”)
granting PGS certain rights to firm receipts of Gas into and firm deliveries of Gas out of each
Pipeline’s system (“Firm Transportation Capacity Rights”);
WHEREAS, the continuing effectiveness of the Pipeline Agreements or successor
agreements thereto is a condition precedent to PGS’s obligations hereunder in the manner set forth
herein;
WHEREAS, each Pipeline’s FERC Tariff (as hereinafter defined) permits the release of rights
to firm transportation service on the Pipeline’s system;
WHEREAS, PGS desires to release temporarily to Customer a portion of PGS’s Firm
Transportation Capacity Rights under the Pipeline Agreements in order to permit Customer to ship
Gas purchased from various suppliers to Pipeline Delivery Point(s) on PGS’s distribution system;
WHEREAS, PGS and Customer desire to set forth the rights and obligations of the parties
pertaining to, and the terms and conditions of, the release of such Firm Transportation Capacity
Rights; and
WHEREAS, PGS and Customer entered into (i) that certain Pipeline Capacity Release
Agreement dated as of June 1, 2008, and (ii) that certain Pipeline Capacity Release Agreement
dated as of February 10, 2012 (collectively, the "Prior Agreements"), and desire to amend, restate
and combine the provisions of said Prior Agreements in order to reflect the additional agreements of
the parties as set forth in this Agreement.
NOW, THEREFORE, in consideration of the mutual covenants and agreements herein set
forth, the parties hereto, intending to be legally bound, hereby agree as follows:
1.
Definitions.
As used in this Agreement, the following words and phrases shall have the following
meanings:
“Adverse Order” means an order, ruling or decision (a) issued by the FERC if such order, ruling or decision
has a material adverse effect on the ability of Customer, in its sole judgment, to receive firm transportation service
on the Pipelines using the Pipeline Capacity (without regard for the rates charged for such service by the Pipelines
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Style Definition: Normal
pursuant to their respective FERC Tariffs), or is otherwise materially adverse to PGS in its sole reasonable
judgment, or (b) issued by the PSC if such order is adverse to Customer in its sole judgment or if such order, ruling
or decision (i) increases or decreases, has the same effect as an increase or decrease in, or requires PGS to
increase or decrease, the distribution charge payable by Customer to PGS under the Gas Transportation
Agreement, (ii) requires (or has the same effect as requiring) any portion of the distribution charges paid by
Customer to PGS pursuant to the Gas Transportation Agreement to be used to reduce PGS’s cost of purchased
gas or pipeline transportation, or (iii) disallows (or has the same effect as disallowing) recovery by PGS from its
ratepayers other than Customer of the difference between the distribution charge set forth in Section 6.1 of the Gas
Transportation Agreement and the distribution charge which would otherwise be payable by Customer to PGS in
the absence of the Gas Transportation Agreement, or is otherwise materially adverse to PGS in its sole judgment.
“Agent” means any person or entity designated as such by Customer by written notice to PGS and who or
which (i) meets the creditworthiness requirements of a Pipeline’s FERC Tariff and, unless otherwise provided in this
Agreement, (ii) agrees in writing to assume and be responsible for all obligations of Customer under this Agreement,
Customer’s Service Agreement, Pipeline’s FERC Tariff or any applicable FERC regulation, order or policy. As
between PGS and Customer, Customer shall remain responsible for all performance required of it by this Agreement
notwithstanding its designation of an Agent to perform any or all of its obligations hereunder; provided, however,
that performance by Customer’s designated Agent of a Customer obligation under this Agreement shall be deemed
performance by Customer of such obligation.
“Alternate Pipeline Delivery Point” has the meaning given in subsection 3.2(f).
“Business Day” means “working day” as defined by NAESB.
“Cane Island Capacity” means that portion of PGS’s Firm Transportation Capacity Rights identified as such
on Appendix A.
“Customer’s Service Agreement” means any firm transportation service agreement between Customer or
Agent and a Pipeline covering the use of the Pipeline Capacity released (i) by PGS to Customer or Customer’s
Agent pursuant to Section 3 hereof or (ii) by Customer to Agent pursuant to subsection 3.2(g) hereof, as such
agreement(s) may be amended from time to time.
“Customer’s Reservation Charge” means the effective Reservation Charge that capacity released to
Customer pursuant to this Agreement will be based upon, the same being (i) for the TCEC Capacity, the cost of the
TCEC Capacity paid to FGT under the FGT Agreement at the rate set forth in Rate Schedule FTS-1, and (ii) for the
Cane Island and Oleander Capacity, the weighted average cost of capacity paid to the Pipelines by PGS for PGS’s
existing portfolio of capacity released to Customer as of the date of this Agreement. Customer’s Reservation Charge
for the Cane Island and Oleander Capacity will be subject to change as the Reservation Charges applicable to the
PGS portfolio of capacity on the Pipelines occur from time to time in such Pipeline’s FERC Tariff.
“Customer’s Pipeline Delivery Point” means the Pipeline Delivery Point listed on Appendix B.
“Day” means “Delivery Gas Day” as defined by NAESB.
“FERC” means the Federal Energy Regulatory Commission or any successor agency.
“FGT” means Florida Gas Transmission Company, LLC, a Delaware limited liability company, its
successors and assigns.
“FGT Agreement” means, collectively, (a) the Rate Schedule FTS-1 Service Agreement for Firm
Transportation Service between FGT and PGS dated August 27, 1999, and (b) the Rate Schedule FTS-2 Service
Agreement for Firm Transportation Service between FGT and PGS dated March 8, 1994, as amended and/or
extended including (i) FGT's currently effective Rate Schedules FTS-1 and FTS-2 and (ii) General Terms and
Conditions filed with the FERC (and incorporated in said agreements by reference), as such agreements, rate
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schedules and general terms and conditions may be amended from time to time, and any successor firm
agreement(s), firm rate schedule(s) or general terms and conditions applicable thereto.
“Force Majeure” means causes or events, whether of the kind hereinafter enumerated or otherwise, not
within the control of the party claiming suspension and which by the exercise of due diligence such party is unable
to prevent or overcome, including, but not limited to, acts of God, strikes, lockouts, or other industrial disturbances,
acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, sinkholes, lightning,
earthquakes, fires, storms, floods, washouts, arrests and restraints of governments and people, civil disturbances,
and explosions; such term shall likewise include the inability of either party to acquire, or delays on the part of such
party in acquiring at reasonable cost and by the exercise of reasonable diligence, servitudes, rights of way, grants,
permits, permissions, licenses, or required governmental orders, necessary to enable such party to fulfill its
obligations hereunder.
“Gas” means natural gas meeting the quality specifications which a Pipeline requires with regard to
deliveries into its system at the Pipeline Receipt Point(s).
“Gas Transportation Agreement” means the Amended and Restated Gas Transportation Agreement dated
as of even date herewith between PGS and Customer, as the same may be amended from time to time.
“GS” means Gulfstream Natural Gas System, L.L.C., a Delaware limited liability company, its successors
and assigns.
“GS Agreement” means the Rate Schedule FTS firm transportation service agreement between GS and
PGS dated June 4, 2010, including GS’s currently effective Rate Schedule FTS and General Terms and Conditions
filed with the FERC (and incorporated in said agreement by reference), as such agreement, rate schedule and
general terms and conditions may be amended from time to time, and any successor firm agreement(s), firm rate
schedule(s) or general terms and conditions applicable thereto.
“Month” means “Delivery Month” as defined in Pipeline’s Tariff.
“NAESB” means North American Energy Standards Board, its successors and assigns.
“Oleander Capacity” means that portion of PGS’s Firm Transportation Capacity Rights identified as such
on Appendix A.
“Party” or “Parties”, as the context requires, means PGS and/or Customer (or Customer’s Agent to the
extent Customer’s Agent is responsible for the performance of Customer’s obligations hereunder).
“Pipeline Capacity” means, as appropriate, either or both of:
(a) that portion identified on Appendix A of PGS’s Firm Transportation Capacity Rights under the FGT
Agreement designated as TCEC Capacity, from the Pipeline Receipt Point(s) identified in Appendix A for the TCEC
Capacity, to the Primary Pipeline Delivery Point(s) identified in Appendix B for the TCEC Capacity, and expressed
in MMBtu (or Dth) per Day of MDTQ (as defined in the Pipeline Agreement as of the date of execution of this
Agreement), subject to modification by PGS from time to time as provided in subsection 3.2(i); and
(b) either or both of (i) that portion identified on Appendix A of PGS’s Firm Transportation Capacity Rights
under the FGT Agreement designated as Cane Island and Oleander Capacity, or (ii) that portion identified on
Appendix A of PGS’s Firm Transportation Capacity Rights under the GS Agreement designated as Cane Island
and Oleander Capacity, from the Pipeline Receipt Point(s) identified in Appendix A for the Cane Island and Oleander
Capacity, to the Primary Pipeline Delivery Point(s) identified in Appendix B for the Cane Island and Oleander
Capacity, and expressed in MMBtu (or Dth) per Day of MDTQ (as defined in the Pipeline Agreement as of the date
of execution of this Agreement), subject to modification by PGS from time to time as provided in subsection 3.2(i).
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“Pipeline Delivery Point(s)” means the point(s) identified in Appendix B. Customer understands and agrees
that such point(s) shall be identical to the point(s) listed from time to time as points of delivery in the applicable
Pipeline Agreement, and that Appendix B hereto shall be deemed to have been amended (without any further action
by the parties to this Agreement) upon the effective date of any amendment to a Pipeline Agreement which changes
the points of delivery listed therein. Immediately following any such amendment to a Pipeline Agreement, PGS
shall furnish to Customer, for attachment to this Agreement, a revised Appendix B hereto, which shall reflect the
effective date thereof.
“Pipeline Receipt Point(s)” has the meaning given in subsection 3.3.
“Pipeline’s FERC Tariff” means, as to the applicable Pipeline Capacity, either (i) FGT’s effective FERC gas
tariff applicable to firm transportation service under the FGT Agreement, or (ii) GS’s effective FERC gas tariff
applicable to firm transportation service under the GS Agreement, in each such case as such tariff may be amended
from time to time.
“PSC” means the Florida Public Service Commission or any successor entity.
“Primary Pipeline Delivery Point(s)” means the Pipeline Delivery Point(s) shown on Appendix B, subject to
modification by mutual agreement of the parties, as provided in subsection 3.2(i).
“Reservation Charge” means the amount (expressed in dollars per MMBtu) which is equal to the maximum
reservation charges chargeable by the Pipelines to Customer for firm transportation service for the Pipeline Capacity
under Customer's Service Agreement, together with all applicable surcharges and other charges, as set forth in the
Pipeline’s FERC Tariff.
“Right of First Refusal Mechanism” means the provision for the exercise of the right of first refusal of Firm
Transportation Capacity Rights on a Pipeline’s system as included in the Pipeline’s FERC Tariff.
“Summer” means the Months of May through and including October.
“TCEC Capacity” means that portion of PGS’s Firm Transportation Capacity Rights identified as such on
Appendix A.
“Winter” means the Months of November through and including April.
2.
Term and Early Termination.
2.1
Term. This Agreement shall become effective on September 1, 2016. The term of
this Agreement shall commence at the beginning of the Day commencing on said date, and continue,
unless earlier terminated pursuant to the provisions of this Agreement, through the end of the Day
commencing on December 31, 2033 (the “Initial Term”). Not less than one (1) year prior to the
expiration of the Initial Term, Customer shall have the unilateral right to extend the term of this
Agreement for a period of five (5) years by executing and tendering to PGS for execution an
amendment to this Agreement so extending its term (which amendment shall be binding on PGS
whether or not PGS executes the same). Subsequent to the expiration of any such additional fiveyear extension of the term, the parties agree to negotiate in good faith to agree on a mutually
beneficial agreement for a subsequent term, if any, as mutually agreed. In connection with any such
further extension of the term, the agreement of neither party hereto shall be unreasonably withheld.
2.2
Early Termination. This Agreement may be terminated prior to the expiration of
the Initial Term or any extended term in accordance with the provisions of this Agreement If either
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party determines an Adverse Order has been received, such Party shall have the right to terminate
this Agreement with ten (10) calendar days notice to the other party contingent upon the concurrent
release (without recall rights) to Customer of the Pipeline Capacity for the remaining term of this
Agreement and any permitted subsequent extensions thereof by Customer pursuant to Section 2.1;
provided that any such termination shall not affect the obligation of either party to pay amounts due
and owing hereunder as of and prior to the date of such termination. A party’s delay in exercising its
right to terminate pursuant to this subsection shall not be deemed to be, nor shall it constitute, a
waiver of such right as long as such right is exercised within 15 calendar days of the effective date
of the final, non-appealable Adverse Order.
2.3
Maintenance of the Gas Transportation Agreement. PGS shall have the right to
terminate this Agreement if the Gas Transportation Agreement is terminated for any reason other
than a material breach thereof by PGS, such termination to be effective as of the date specified in
the notice of termination delivered by PGS to Customer, which date shall be not less than ten (10)
Days after the date of such notice and such termination date shall coincide with the end of the
calendar month.
2.4
Options to Reduce Service. At any time after April 30, 2023, if FMPA permanently
retires either: (i) TCEC, or (ii) both of Cane Island Units 3 and 4 along with termination of the Oleander
PPA, then FMPA has the one-time option to reduce service related to the retired assets. That is, if
FMPA retires TCEC, then service to TCEC will no longer be provided under this Agreement. Or, if
FMPA retires Cane Island Units 3 and 4, and terminates the Oleander PPA, then service to Cane
Island and Oleander will no longer be provided under this Agreement If Customer exercises the
aforesaid option to reduce service to the retired assets, then PGS will recall the Pipeline Capacity
associated with the provision of service to the retired assets.
3.
Release of Pipeline Capacity.
3.1
Releases.
(a)
Subject to the provisions of this Agreement, PGS agrees to
provide to the Pipeline(s) in accordance with the applicable Pipeline’s FERC Tariff a Relinquishment
Notice (as such term is used in a Pipeline’s FERC Tariff) with respect to the Pipeline Capacity, within
a time sufficient for Customer to commence the use of the Pipeline Capacity (in the manner provided
in this Agreement) on the date on which the term of this Agreement commences. Such
Relinquishment Notice shall offer to relinquish temporarily, as a prearranged transaction, at
Customer’s Reservation Charge, and on the terms set forth in and for the term of this Agreement,
the Pipeline Capacity (hereinafter, “release”). Customer agrees to acquire the Pipeline Capacity
pursuant to the terms and conditions of the applicable Pipeline’s FERC Tariff and this Agreement.
(b)
PGS agrees to (i) temporarily recall, for each Day during the term of this Agreement,
such portion of the Pipeline Capacity as Customer, not less than thirty minutes before FGT’s and/or
GS’s timely recall notification deadline, specifies in writing to PGS, and (ii) not after 10:00 a.m.
Eastern Clock Time sell to Customer pursuant to Section 4.6 of the Gas Transportation Agreement
that quantity of Gas Customer needs up to the difference between (x) the maximum available
capacity for the applicable month under this Agreement and (y) the quantity retained by Customer
after the actions taken pursuant to paragraph (b)(i) above. Such Gas will be sold by PGS to
Customer at FGT Zone Platts Gas Daily Index for the corresponding zone for the applicable Pipeline
Receipt Point in Appendix A plus, based on the type of capacity (FTS-1, FTS-2 and/or GS) utilized,
the maximum applicable reservation, usage and fuel rates. The order of capacity made available
to Customer shall be from the least cost reservation charge to the most expensive reservation
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charge (up to maximum contract quantity).
(c)
All temporary recalls made by PGS pursuant to paragraph (b) above shall be made
in such a manner as to: (i) first recall all released FGT FTS-2 Pipeline Capacity until Customer has
none remaining, then (ii) unless and to the extent that Customer has exercised its rights pursuant
to the next sentence, begin recalling all released GS Pipeline Capacity until Customer has none
remaining, and (iii) lastly, recall all released FGT FTS-1 Pipeline Capacity. In the event Customer
or Customer’s Agent requests to retain released GS Pipeline Capacity, then PGS shall recall all
released FGT FTS-1 Pipeline Capacity prior to recalling any released GS Pipeline Capacity.
(d)
If PGS temporarily recalls the Pipeline Capacity (or any portion thereof) as permitted
by this Agreement, upon the expiration of such temporary recall, the temporarily recalled portion of
the Pipeline Capacity shall automatically revert to Customer; provided, however, that if necessary
upon the expiration of the temporary recall to enable Customer to again have the use of the
temporarily recalled portion of the Pipeline Capacity, the parties hereto shall, immediately following
the expiration of such temporary recall, comply with the provisions of paragraph (a) above.
3.2
Conditions to Release. Any release of the Pipeline Capacity by PGS provided for
in subsection 3.1 above shall be subject to the following conditions:
(a)
Customer shall, in accordance with the applicable Pipeline’s FERC Tariff, enter into
a firm transportation service agreement with Pipeline for the Pipeline Capacity acquired pursuant to
subsection 3.1 (“Customer’s Service Agreement”), and shall have sole responsibility for complying
with (i) all provisions of such agreement and (ii) all applicable provisions of Pipeline’s FERC Tariff.
(b)
PGS shall retain the sole right (i) to affirmatively exercise, at the time required by the
applicable Pipeline Agreement, Pipeline’s FERC Tariff, Customer’s Service Agreement, or any
FERC rule or order, any Right of First Refusal Mechanism (however denominated), including the
option to extinguish such right, applicable to the Pipeline Capacity, and (ii) to exercise or fail to
exercise any right to extend a Pipeline Agreement as it pertains to the Pipeline Capacity; provided,
however, that PGS may not exercise any such right in a manner which would impair Customer’s right
to use, in the manner provided herein, the Pipeline Capacity during the term of this Agreement and
all subsequent extensions pursuant to subsection 2.1 of this Agreement. Notwithstanding the
foregoing proviso, PGS shall have the right to temporarily recall the Pipeline Capacity in the event
such recall is necessary to enable PGS to exercise the rights set forth in this paragraph (b), or to
construe the release of the Pipeline Capacity to Customer pursuant to this Agreement as a
temporary, as opposed to a permanent, release. In the event that PGS would elect to turn back a
portion of or all of the Pipeline Capacity to the pipelines under the provisions of this paragraph, PGS
shall negotiate with Customer (which negotiation shall not be unreasonably conditioned, withheld or
delayed by either party) for the permanent release to Customer of the respective Pipeline Capacity
prior to such turn back.
(c)
Customer agrees to make all payments to Pipeline required by Customer’s Service
Agreement, by Pipeline’s FERC Tariff, or by any applicable FERC rule or order, within the time and
in the manner provided in such service agreement, tariff, rule or order. If Customer fails to make
such payments in such manner, PGS may make payment directly to Pipeline on behalf of Customer
(in a manner which preserves any rights which Customer may have to dispute the nature or amount
of the charges so paid), and Customer shall reimburse PGS for such amounts pursuant to the terms
of Section 4 of this Agreement.
(d)
If, subsequent to any release provided for in subsection 3.1, PGS is not released by
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Pipeline from the obligation to pay the full amount of the Reservation Charges attributable to the
Pipeline Capacity, and PGS is required to make payment of amounts payable by Customer to
Pipeline associated with Customer’s holding the right to use (or Customer’s use of) the Pipeline
Capacity, Customer shall reimburse PGS for such amounts pursuant to the terms of Section 4 of this
Agreement.
(e)
Subsequent to any release of the Pipeline Capacity by PGS to Customer as provided
for herein, Customer shall not seek or consent to (except as provided in paragraph (i) of this
subsection) any amendment or modification of Customer’s Service Agreement in a manner that is
adverse to the exercise by PGS of its rights hereunder, or under the Pipeline Agreements, which
would change the quantity or term thereof, the Pipeline Receipt Point(s), or the Primary Pipeline
Delivery Point(s), without the prior written consent of PGS (which consent shall not be unreasonably
withheld or delayed). The foregoing provisions of this paragraph (e) shall not prevent Customer from
using alternate points of receipt into or within the Pipeline system in connection with Customer’s use
of the Pipeline Capacity.
(f)
Notwithstanding the provisions of paragraph (e) above, Customer may nominate to
Pipeline a Pipeline Delivery Point other than Customer’s Pipeline Delivery Point (an “Alternate
Pipeline Delivery Point”) for use by Customer in receiving deliveries of all or any portion of the
Pipeline Capacity pursuant to Customer’s Service Agreement. Subject to the foregoing requirements
and the other provisions of this Agreement, PGS will confirm quantities so nominated by Customer
for delivery at such Alternate Pipeline Delivery Point if (i) deliveries identified in Appendix B in the
quantities nominated by Customer can be effected at such point and (ii) PGS determines, in its
reasonable judgment, that to do so will not adversely affect its ability to effectively implement
curtailment or interruption in order to maintain service to high priority customers pursuant to its tariff
and curtailment plan on file with the PSC from time to time.
(g)
for herein, Customer shall not, during the term of this Agreement, release the Pipeline Capacity (or
any portion thereof) to a third party unless the term of such release ends on or before the date on
which Customer's right to use such Pipeline Capacity hereunder expires and unless such release,
in a manner permitted by the Pipeline's FERC Tariff and/or applicable FERC regulations, prohibits
the re-release of the portion of the Pipeline Capacity so released by Customer. In addition, if
Customer desires to release all or any portion of the Pipeline Capacity released to Customer on
a temporary basis, Customer shall provide written notice to PGS (a "Release Notice") specifying
(1) the quantity of the Pipeline Capacity Customer desires to release, (2) the time period for which
such quantity is to be released, and (3) the portion of the Reservation Charge it desires to be paid
for the quantity desired to be released. Except in the case of a release by Customer to Agent,
PGS shall have, in the case of a proposed release for a period of one Month or less, not less than
one Business Day (and in no event less than 24 hours), and in the case of a proposed release for
a period of more than one Month, not less than two Business Days (and in no event less than 48
hours), from the time of its receipt of a Release Notice within which to respond thereto by offering
in writing to pay all or that requested portion of the Reservation Charge for the portion of the
Pipeline Capacity and the term specified in the Release Notice. If PGS fails to timely respond to
a Release Notice, then Customer’s offer to temporarily release the Pipeline Capacity (in the
quantity and on the terms set forth in the Release Notice) may be posted on Pipeline’s electronic
bulletin board in the manner provided by the Pipeline’s FERC Tariff. If PGS timely responds to a
Release Notice by offering to pay all or any portion of the Reservation Charge for the portion of
the Pipeline Capacity and the term specified in the Release Notice, then Customer’s offer to
temporarily release the Pipeline Capacity (in the quantity and on the terms set forth in the Release
Notice) shall be posted on Pipeline’s electronic bulletin board in the manner provided by Pipeline’s
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FERC Tariff. In either of the above cases, following the posting on Pipeline’s electronic bulletin
board of Customer’s offer, the temporary release of the Pipeline Capacity specified in the Release
Notice shall be governed by the applicable provisions of Pipeline’s FERC Tariff.
(h)
Subsequent to the release of the Pipeline Capacity by PGS to Customer as provided
for herein, and subject to the provisions of subsection 3.1(b), PGS may temporarily recall, after
providing Customer or Customer’s Agent reasonable notice, such portion of the Pipeline Capacity
as has not been (at the time of PGS’s recall) scheduled by Customer or Customer’s Agent for the
purpose of a Pipeline’s making deliveries at a Pipeline Delivery Point or an Alternate Pipeline Delivery
Point, if PGS determines in its reasonable judgment that such temporary recall is required in order
to maintain PGS’s ability to (i) maintain service to high priority customers, or (ii) effectively implement
curtailment or interruption of service pursuant to the Gas Transportation Agreement in order to
maintain service to high priority customers pursuant to its tariff and curtailment plan on file with the
PSC from time to time.
(i)
for herein, and subject to the provisions of subsection 3.1(b), PGS may temporarily recall, after
providing Customer or Customer’s Agent reasonable notice, the FGT Capacity for the purpose of
modifying the Primary Pipeline Delivery Point(s) (and the amount of firm transportation capacity at
such point(s)) in such manner as PGS deems necessary, in its reasonable discretion, for the purpose
of maintaining its ability to manage its distribution system as set forth in clauses (i) and (ii) of
paragraph (h) of this subsection 3.2. To the extent permitted by Pipeline, PGS will implement such
temporary recall rights in a manner that does not cause any lapse in Customer’s right, or if the
Pipeline Capacity or any portion thereof has been re-released by Customer to a third party, such
third party’s right, to use the Pipeline Capacity. To the extent permitted by FGT, PGS will implement
such temporary recall rights in a manner that does not cause any lapse in Customer’s right to use
20,000 MMbtuMMBtu per Day of the TCEC Capacity.
(j)
Customer shall have the right to designate an Agent to whom or which (i) Customer
may direct, in writing, PGS to release the Pipeline Capacity pursuant to subsection 3.1 of this
Agreement, or (ii) Customer may release the Pipeline Capacity pursuant to paragraph (g) above.
Customer may, on thirty (30) Days’ written notice to PGS, change the person designated as Agent
hereunder.
3.3
Pipeline Receipt Point(s). The primary point(s) of receipt on the Pipeline system
from which PGS agrees to release capacity as provided in subsection 3.1 (“Pipeline Receipt
Point(s)”), together with the maximum quantity of Gas which may be tendered by Customer (or for
its account) at each such point, are identified on Appendix A. Appendix A shall be amended through
mutual agreement to reflect any change in the quantity of the Pipeline Capacity pursuant to this
Agreement.
3.4
Refunds. If, after the effective date of any PGS release of the Pipeline Capacity to
Customer pursuant to subsection 3.1, Customer receives from a Pipeline any refund of any charges
previously paid by PGS to the Pipeline under a Pipeline Agreement, including but not limited to
Reservation Charges (or portions thereof), Customer shall, in the Month following its receipt of such
refund, pay to PGS the amount of such refund (or, where PGS owes Customer funds, PGS shall
provide Customer with a credit). If, after the termination of this Agreement, PGS receives from a
Pipeline any refund of any charges previously paid by Customer to the Pipeline pursuant to the terms
of this Agreement (or the terms of Customer’s Service Agreement), including but not limited to
Reservation Charges (or portions thereof), PGS shall pay or credit to Customer the amount of such
refund, such payment or credit to be made or effected, to the extent practicable, in the Month
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following PGS’s receipt of such refund. The obligations of each of Customer and PGS under this
subsection shall survive the termination of this Agreement.
4.
Billing and Payment. (a) In the event it is necessary that either party hereto bill the other
party for amounts payable by such other party pursuant to this Agreement, then the billing party shall,
as soon as practicable after such amounts are determined, deliver a bill to the other party for such
amounts. Such amounts shall be due on or before the tenth Business Day following the billing party’s
mailing (as signified by the postmark) or other delivery of such bill. All sums not so paid by the other
party shall be considered delinquent. If the other party fails to pay any such amounts when due,
interest shall be calculated on the overdue amount at an annual rate of interest equal to the prime
interest rate of Citibank, N.A., published in New York, New York, plus one percent (1%), calculated
from the date that such payment was due until the date that it is paid. If Customer fails to make any
payment when due and such failure is not remedied by or on behalf of Customer within five (5) Days
after written notice by PGS of such default in payment, then PGS, in addition to any other remedy it
may have, may without damage and without terminating this Agreement, suspend further deliveries
of Gas to Customer pursuant to the Gas Transportation Agreement until such amount is paid;
provided, however, that PGS shall not suspend deliveries of Gas to Customer pursuant to the Gas
Transportation Agreement if (i) Customer’s failure to pay is the result of a bona fide dispute, (ii)
Customer has paid PGS for all amounts not in dispute and (iii) the dispute is being resolved in
accordance with paragraph (b) of this Section 4.
(b)
In the event of a bona fide billing dispute, Customer or PGS, as the case may be,
shall pay (or credit) to the other party all amounts not in dispute, and the parties shall negotiate in
good faith to resolve the amount in dispute as soon as reasonably practicable. If a party has withheld
payment (or credit) of a disputed amount, and the dispute is resolved in favor of the other party, the
non-prevailing party shall pay to the other party the amount determined to be due such other party,
plus interest thereon at an annual rate equal to the prime interest rate of Citibank, N.A., New York,
New York, plus one percent (1%), calculated on a daily basis from the date due until paid (or
credited).
(c)
If an error is discovered in any bill rendered (or credit given or payment made)
hereunder, or in any of the information used in the calculation of such bill (or such credit or payment),
the billing party shall, within two years and to the extent practicable, make an adjustment to correct
such error in the next bill rendered after the date on which the error is confirmed. The provisions of
this section shall survive the termination of this Agreement.
5.
Regulatory Jurisdiction over Transactions.
5.1
PSC Jurisdiction. Customer recognizes and agrees that PGS is a public utility
subject to regulation by the PSC. Compliance by PGS with any rule or order of the PSC or any other
federal, state or local governmental authority acting under claim of jurisdiction issued before or after
the effective date of this Agreement shall not be deemed to be a breach hereof; provided, however,
that PGS will use all commercially reasonable efforts (which are consistent with its status as a public
utility) to mitigate any material adverse effect which its compliance with the terms of any such rule or
order would have on the rights of and costs to Customer as contemplated by this Agreement.
6.
Limitation of Liability and Force Majeure.
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6.1
Force Majeure. The obligations of each party under this Agreement, and the
performance thereof, other than a failure or delay in the payment of money due hereunder, shall be
excused during such times and to the extent such performance is prevented by reason of Force
Majeure.
6.2
Resumption of Performance. The party whose performance is excused by an
event of Force Majeure shall promptly notify the other party of such occurrence and its estimated
duration, and shall promptly remedy such Force Majeure if and to the extent reasonably possible
and resume such performance when possible; provided, however, that neither party shall be required
to settle any labor dispute against its will.
6.3
Limitation of Liability. Neither PGS nor Customer shall be liable to the other or to
any person claiming through the other for special, indirect or punitive damages, lost profits, or lost
opportunity costs relating to any matter covered by this Agreement.
7.
Events of Default; Remedies. (a) The occurrence of any of the following events shall
constitute an event of default (“Event of Default”) as to the non-performing party under this
Agreement:
(i) failure by (1) either party to make any payment required to be made hereunder or
(2) by Customer to comply with the requirements of subsection 3.2(g), and such failure shall
continue for five (5) Days after notice from the other party of such failure; or
(ii) failure by either party to comply in any material respect with any material term or
provision of this Agreement, other than a failure specified in clause (i) above, and such failure
shall continue for thirty (30) Days after written notice thereof has been given to the
non-performing party; or
(iii) the dissolution or liquidation of a party; or the failure of a party within sixty (60)
Days to lift any execution, garnishment or attachment of such consequence as may materially
impair its ability to carry on its operations; or the failure of a party generally to pay its debts
as such debts become due; or the making by a party of a general assignment for the benefit
of creditors; or the commencement by a party (as the debtor) of a voluntary case in
bankruptcy under the Federal Bankruptcy Code (as now or hereafter in effect) or any
proceeding under any other insolvency law; or the commencement of a case in bankruptcy
or any proceeding under any other insolvency law against a party (as the debtor); or the
appointment or authorization of a trustee, receiver, custodian, liquidator or agent, however
named, to take charge of a substantial part of the property of a party for the purpose of
general administration of such property for the benefit of creditors; or the taking of any
corporate action by a party for the purpose of effecting any of the foregoing.
(b)
Upon the occurrence and continuation of an Event of Default, the non-defaulting party
may, at its option, and in addition to and cumulatively of any other rights and remedies it may have
hereunder, at law, in equity or otherwise, terminate this Agreement upon ten (10) Days' prior written
notice to the defaulting party, or enforce, by all lawful means, its rights hereunder, including without
limitation, the collection of sums due hereunder without terminating this Agreement, and should it be
necessary for such party to take any legal action in connection with such enforcement, the defaulting
party shall pay such non-defaulting party all costs and reasonable attorneys' fees so incurred.
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8.
Notices.
(a)
All notices and other communications hereunder shall be in writing
and be deemed duly given on the date of delivery if delivered personally, by electronic mail (if
confirmed with a read receipt), by facsimile (if receipt is confirmed by telephone) or by a recognized
overnight delivery service, or on the tenth (10th) day after mailing if mailed by first class United States
mail, registered or certified, return receipt requested, postage prepaid, and properly addressed to
the party as set forth below.
PGS:
FMPA:
Administrative Matters:
Peoples Gas System
702 N. Franklin Street
P. O. Box 2562
Tampa, Florida 33601-2562
Attention: Vice President – Fuels Management
Telephone: (813) 228-4526
Facsimile: (813) 228-4643
E-mail:
Administrative Matters::
Orlando, FL 32819
Attention: AGM – Power Resources
Telephone: 407-355-7767
Facsimile: 407-355-5794
E-mail:
With a Copy To:
With a copy to:
Peoples Gas System
2061-2 Delta Way
Tallahassee, FL 32303
P. O. Box 2562
Attention: General Counsel
Telephone: (850) 297-2011
Facsimile: (850) 297-2014
Telephone: (813) 228-1556
E-mail: [email protected]
Facsimile: (813) 228- 228-4643
Invoices and Payment:
Peoples Gas System
P. O. Box 2562
Attention: Director, Accounting
Telephone: (813) 228-4191
Facsimile: (813) 228-4643
Orlando, FL 32819
Attention: Accounts Payable
Telephone: 407-355-7767
Facsimile: 407-355-5795
(b)
Each of Customer and PGS shall designate in writing an individual to act as its
“Contact Person”, which individual shall be (i) duly authorized with respect to all operational matters
arising under this Agreement and (ii) accessible to PGS or Customer (as the case may be) at all
times during each Day during the term of this Agreement. In the performance of its obligations
hereunder, PGS and Customer shall be entitled to rely, respectively, upon any instruction, consent
or acknowledgement given by such Contact Person with respect to operational matters arising
hereunder or under the applicable Pipeline Agreement.
9.
Miscellaneous.
9.1
Independent Parties. PGS and Customer shall perform hereunder as independent
parties and neither PGS nor Customer is in any way or for any purpose, by nature of this Agreement
or otherwise, a partner, joint venture, agent, employer or employee of the other. Nothing in this
Agreement shall be for the benefit of any third person for any purpose, including without limitation,
the establishing of any type of duty, standard of care or liability with respect to any third person.
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9.2
No Waiver. No waiver of any of the provisions hereof shall be deemed to be a waiver
of any other provision whether similar or not. No waiver shall constitute a continuing waiver. No
waiver shall be binding on a party unless executed in writing by that party.
9.3
Amendments. This Agreement shall not be amended except by an instrument in
writing signed by the party against which enforcement of the amendment is sought. A change in (a)
the place to which notices hereunder must be sent, or (b) the individual designated as a party's
Contact Person shall not be deemed nor require an amendment hereof provided such change is
communicated pursuant to Section 8(a).
9.4
Entire Agreement. This Agreement constitutes the entire agreement between the
parties with respect to the Pipeline Capacity and Customer’s use thereof, and supersedes all prior
negotiations, agreements and understandings between the parties with respect thereto.
9.5
Successors and Assigns. This Agreement shall be binding upon, and inure to the
benefit of, the parties hereto and their respective successors and permitted assigns; provided,
however, that neither party may assign this Agreement without the prior written consent of the other
(which shall not be unreasonably withheld) and the assignee's written assumption of the assigning
party's duties and obligations hereunder. Upon any such assignment and assumption, the assigning
party shall furnish a copy thereof to the other party.
9.6
Governing Law; Venue. This Agreement and any dispute arising hereunder shall
be governed by and interpreted in accordance with the laws of the State of Florida without giving
effect to provisions which would cause the law of another jurisdiction to apply, and shall be subject
to all applicable laws, rules and orders of any federal, state or local governmental authority having
jurisdiction over the parties, their facilities or the transactions contemplated. Venue for any action,
at law or in equity, commenced by either party against the other and arising out of or in connection
with this Agreement shall be in a court located in the State of Florida in Leon County and having
jurisdiction.
9.7
Severability. If any term or provision hereof is declared by a court of competent
jurisdiction to be, or becomes under applicable law, illegal, unenforceable or invalid, such illegality,
unenforceability or invalidity shall not affect any other term or provision of this Agreement, and this
Agreement shall continue in full force and effect without said term or provision; provided, however,
that if such severability materially changes the economic benefits of this Agreement to either party,
the parties agree to negotiate in good faith to modify this Agreement so as to effect the original intent
of the parties as closely as possible in a mutually acceptable manner (further provided, however, that
the inability of the parties to agree after good faith negotiations to a mutually acceptable modification
shall not make this Agreement voidable or terminable by a party).
9.8
Inspection. Each party hereto shall have the right during the term hereof and for a
period of three (3) years thereafter, upon reasonable prior notice and during normal business hours,
to examine the books, records and documents of the other party to the extent necessary to verify the
accuracy of any statement or charge made hereunder. Each party shall keep each such record and
document for a period of three (3) years from the date the same is created or any entry or adjustment
thereto is made.
9.9
Project Agreement. This Agreement is a liability and obligation of the AllRequirements Power Supply Project only. No liability or obligation under this Agreement shall inure
to or bind any of the funds, accounts, monies, property, instruments, or rights of the Florida Municipal
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Power Agency generally or any of any other "project" of FMPA as that term is defined in the Interlocal
Agreement Creating the Florida Municipal Power Agency, as may be amended or supplemented
pursuant thereto.
9.10 Prior Agreements. This Agreement shall supersede and replace, as of the date first
written above, the Prior Agreements; provided, however, that the obligations of a party that have
accrued as of the date first written above shall survive the termination of the Prior Agreements.
9.11 Counterparts. This Agreement may be executed in one or more counterparts, each
of which shall be deemed an original, but all of which together shall constitute one and the same
instrument.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by
their respective duly authorized officers as of the date first written above.
PEOPLES GAS SYSTEM, a division of
TAMPA ELECTRIC COMPANY
(All-Requirements Power Supply Project)
By: ____________________________
Gordon L. Gillette
President
By:____________________________
Nicholas P. Guarriello
General Manager & CEO
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Formatted: Font: 11 pt, Bold
PIPELINE RECEIPT POINT(S)
FGT RECEIPT POINT(S)
FTS-1
DRN
337605
241390
314571
24229
255292
23422
32606
454599
23703
6490
50026
Description
Refugio-Crosstex
Destin
ANR St. Landry
Amoco Judge Digby
Tejas Calhoun
Sabine Pass Plant
NGPL Vermillion
Markham – Gulf Shore
NGPL Jefferson
TX Gas Eunice
Trunkline Manchester
Oct
0
5,000
0
7,453
1,226
0
3,647
5,000
3,774
0
0
Nov-Mar
0
5,000
2,955
1,650
1,120
5,000
7,045
0
0
2,000
1,880
Apr
0
5,000
3,732
3,040
0
5,000
4,878
5,000
0
0
0
May-Sep
1.992
5,000
6,550
1,236
0
0
3,314
8,008
0
0
0
DRN
179851
10034
24229
157553
11224
241390
FTS-2
Description
Oct
Nov-Mar
Columbia Layfayette
0
3,350
Gulf So St. Landry
0
0
Amoco Judge Digby
3,900
0
Trans Citronelle
0
2,500
SNG Franklinton
0
0
Destin
5,000
2,500
Apr
3,350
0
0
0
0
5,000
May-Sep
1,246
2,654
0
0
5,000
0
Apr
5,000
May-Sep
9,000
GULFSTREAM RECEIPT POINT(S)
DRN
9000126
Description
Mobile Bay/Destin
Oct
9,000
Nov-Mar
5,000
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The above point(s) may be changed by mutual agreement of the parties.
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APPENDIX B – AMENDED AND RESTATED
PIPELINE DELIVERY POINTS
All capitalized terms not otherwise defined in this Appendix B shall have the meanings given
to such terms in the Amended and Restated Pipeline Capacity Release Agreement.
FGT DELIVERY POINT(S)
FTS-1
DRN
2984
475724
127438
2988
Description
Dania
Treasure Coast 1
Lake Blue
North Miami
Oct
8,700
8,500
2,800
6,100
Nov-Mar
8,700
8,500
2,800
6,650
Apr
5,000
8,500
6,500
6,650
May-Sep
5,000
8,500
6,500
6,100
Apr
2,897
2,995
2,458
May-Sep
8,257
0
643
Apr
5,000
May-Sep
9,000
FTS-2
DRN
2988
3281
3152
Description
North Miami
Daytona
Palm Beach
Oct
8,257
0
643
Nov-Mar
2,897
2,995
2,458
GULFSTREAM DELIVERY POINT(S)
DRN
9000040
Description
So. Hillsborough
Oct
9,000
Nov-Mar
5,000
The above point(s) may be changed by mutual agreement of the parties
1
15,000 MMBtus per Day primary delivery capacity and 5,000 MMBtus per Day secondary delivery capacity. As of the date of this
Appendix B, the Treasure Coast delivery point listed above is included under PGS’s FGT Delivery Point Operator Agreement.
Customer shall have the right to remove such delivery point from PGS’s FGT Delivery Point Operator Agreement upon thirty (30)
Days’ written notice to PGS.
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GAS TRANSPORTATION AGREEMENT
This Amended and Restated Gas Transportation Agreement (the “Agreement”) is made
and entered into as of the 1st day of September, 2016, by and between Peoples Gas System, a
Division of Tampa Electric Company, a Florida corporation (“PGS”), and Florida Municipal
Power Agency (All-Requirements Power Supply Project), a governmental legal entity created
and existing pursuant to Florida Law (“FMPA” or “Customer”), who hereby agree as follows:
ARTICLE I - DEFINITIONS
As used herein, the following terms shall have the meanings set forth below. Capitalized
terms used herein, but not defined below, have the meanings given for such terms in PGS’s FPSC
Tariff.
“Actual Takes” means for a specified period of time, the quantity of Gas passing through the meter(s)
at the PGS Delivery Points(s) identified in Appendix B of this Agreement.
“Adverse Order” means any amendment to any statute or rule, or any order or rule Issued by any
regulatory authority that prevents either Party from performing its obligations under this Agreement.
“Agent” means any person or entity designated as such by FMPA by written notice to PGS, who or
which will act as FMPA’s Agent for matters concerning nominations and scheduling of volumes on the
Pipelines and, if so designated, for billing related matters of all costs due under this Agreement, or any
subsequent person or entity named by FMPA in its sole discretion. As between PGS and FMPA, FMPA shall
remain responsible for all performance required of it by this Agreement notwithstanding its designation of an
Agent to perform any or all of its obligations hereunder; provided, however, that performance by FMPA’s
designated Agent of an FMPA obligation under this Agreement shall be deemed performance by FMPA of
such obligation.
“Alert Days” means “Alert Days” as defined in the respective Pipeline’s Tariff.
“Cane Island” means the electrical generating facility located in Osceola County, Florida from which
FMPA has the right to receive all electrical capacity and energy output.
“Capacity Release Agreement” means the Amended and Restated Capacity Release Agreement
dated as of even date herewith between PGS and FMPA, as the same may be amended from time to time.
“Confirmation Quantity” has the meaning given in Section 4.5.
“Contract Year” means the period of twelve (12) consecutive Months commencing on the date first
written above, and each successive period of twelve (12) consecutive Months thereafter during the term of
this Agreement.
“Daily Imbalance Amount” has the meaning given in PGS’s FPSC Tariff.
“Distribution System” means the interstate pipeline interconnections, and the pipes (mains and
service lines), valves, regulators, meters and appurtenant facilities comprising the system used by PGS to
provide Gas Service to its customers.
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Style Definition: Normal
“FGT’s FERC Tariff” means FGT’s effective FERC gas tariff applicable to firm transportation service
under the FGT Agreement(s) as such tariff may be amended from time to time.
“FMPA Facilities” means Cane Island, TCEC and Oleander.
“FPSC” means the Florida Public Service Commission or any successor agency.
gas delivered into its system, as applicable.
“GS” means Gulfstream Natural Gas System, L.L.C., its successors and assigns.
“Imbalance Level” has the meaning given in PGS’s FPSC Tariff.
“Maximum Delivery Quantity’” or “MDQ” means the maximum amount of Gas that PGS is obligated
to cause to be delivered to FMPA or its Agent pursuant to this Agreement on any Day at the PGS Delivery
Point(s), and is stated in Appendix B.
“Maximum Transportation Quantity” or “MTQ” means the maximum amount of Gas that PGS shall
be obligated to receive pursuant to this Agreement on any Day at the PGS Receipt Point(s), and is stated in
Appendix A.
“MMBtu” means one million (1,000,000) British Thermal Units or Btus.
“Month” means “Delivery Month” as defined in the respective Pipeline’s Tariff.
“Monthly Imbalance Amount” has the meaning given in Section 5.2.
“Nominate” means to deliver a completed Nomination.
“Nomination” means a notice delivered by FMPA or its Agent to PGS in the form specified in PGS’s
FPSC Tariff, specifying (in MMBtu) the quantity of Gas FMPA desires to purchase, or to have PGS receive,
transport and redeliver, at the PGS Delivery Point(s).
“Oleander” means Unit #5 of Southern Power Company’s electrical generating station located in
Brevard County, Florida which FMPA has contractual rights to dispatch under the terms of a Power Purchase
Agreement dated February 23, 2006, as amended.
“Oleander Gate” means the interconnection between FGT and the Distribution System constructed
by FGT to enable PGS to provide deliveries of Gas to Oleander with the transportation service contemplated
by this Agreement.
“Party” or “Parties”, as the context requires, means PGS and/or FMPA (or FMPA’s Agent to the extent
such Agent is responsible for the performance of Customer’s obligations hereunder).
“PGS Delivery Point(s)” means the FMPA power generating facilities identified in Appendix B.
“PGS Receipt Point(s)” means the point(s) of physical interconnection between the Pipelines, and
PGS listed in Appendix A where PGS receives Gas for the benefit of FMPA pursuant to this Agreement.
“Pipelines” means FGT and GS, collectively.
“Pipeline’s FERC Tariff” means, as applicable, either FGT’s or GS’s effective FERC gas tariff
applicable to firm transportation service, as such tariff may be amended from time to time.
“Remaining Imbalance” has the meaning given in PGS’s FPSC Tariff.
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“Sales Quantity” has the meaning given in Section 4.2.
“Scheduled Quantities” means, for a specified period of time, the amounts of Gas confirmed by PGS
for transportation hereunder.
“Supplier(s)” means person(s) (other than PGS) from which FMPA purchases Gas transported
hereunder.
“TCEC” means FMPA’s Treasure Coast Energy Center, an electrical generating facility located in St.
Lucie County, Florida.
“Transportation Quantity” has the meaning given for such term in Section 4.3.
“Unit Price” has the meaning given in Section 5.2.
ARTICLE II - TERM
Section 2.1 Term. This Agreement shall be binding on the date it is executed on behalf of both
of the Parties hereto. The term of this Agreement shall commence at the beginning of the Day
commencing on said date, and continue, unless earlier terminated pursuant to the provisions of
this Agreement, through the end of the Day commencing on December 31, 2033 (the “Initial
Term”). Not less than one (1) year prior to the expiration of the Initial Term (or any extended term
following the Initial Term), FMPA shall have the unilateral right to extend the term of this Agreement
for up to two (2) periods of five (5) years each by executing and tendering to PGS for execution an
amendment to this Agreement so extending its term. Subsequent to the expiration of any such
additional five-year extension of the term, the parties agree to negotiate in good faith to agree on a
mutually beneficial agreement for a subsequent term, if any, as mutually agreed. In connection with
any such further extension of the term, the agreement of neither party hereto shall be unreasonably
withheld. If an Adverse Order is issued during the term of this Agreement, this Agreement shall
terminate; provided, however, that the obligation of each party to make payment of amounts due as
of the date of such termination shall survive such termination. In addition, if the Agreement is
terminated as the result of an Adverse Order affecting PGS prior to the end of the Initial Term, PGS
shall convey title to the facilities constructed pursuant to the Construction Agreement between
Customer and PGS dated June 8, 2006 to FMPA, and FMPA shall pay to PGS the actual cost of the
facilities and meter station, less all accumulated depreciation, plus a reasonable mark-up for
expected revenue through the end of this Agreement as mutually agreed.
Section 2.2 Buyout Option. At any time after February 1, 2017, FMPA by giving PGS not less
than one (1) year’s prior written notice, shall have the option to buy-out PGS’s interest in the Oleander
Gate and/or terminate this Agreement. The purchase price to be paid to PGS by FMPA for the
Oleander Gate shall be the then net present value (calculated using an interest rate equal to the
then most recent overall allowed rate of return for retail customers approved by the FPSC at the time
notice is given by FMPA) of the sum of any remaining fixed Distribution Charges described in Section
6.1 of this Agreement as of the date of termination which would have otherwise been paid by FMPA
to PGS absent FMPA’s exercise of the aforesaid buyout option and the termination of this
Agreement.
Section 2.3 Options to Reduce Service. At any time after April 30, 2023, if FMPA permanently
retires either: (i) TCEC, or (ii) both of Cane Island Units 3 and 4 along with termination of the Oleander
PPA, then FMPA has the option to reduce service related to the retired assets. That is, if FMPA
retires TCEC, then service to TCEC will no longer be provided under this Agreement, and the
charges associated with that asset under this Agreement, including those pursuant to Section 6.1(a),
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shall cease. Or, if FMPA retires Cane Island Units 3 and 4, and terminates the Oleander PPA, then
service to Cane Island and Oleander will no longer be provided under this Agreement, and the
charges associated with those assets under this Agreement, including those pursuant to Section
6.1(b), shall cease.
ARTICLE III - SALES AND TRANSPORTATION SERVICE
Section 3.1 Services. Both FMPA and its Agent, if applicable, hereby accept, and PGS hereby
agrees to provide the service to receive Gas for FMPA's or its Agent’s account, up to the MTQ,
at the PGS Receipt Point(s), and to cause an equivalent quantity to be redelivered to FMPA. PGS
also desires to sell and FMPA or its Agent desires to purchase at a negotiated price per MMBtu
from PGS, from time to time, Gas in quantities which, at FMPA’s or its Agent’s request, PGS may,
in its reasonable discretion, agree to sell Gas to FMPA or its Agent, it being understood and
agreed that PGS will not contract for Gas supply to provide the services contemplated by this
Agreement. The transportation and any such sales shall be governed by PGS’s FPSC Tariff and
this Agreement. If there is a conflict between the tariff and this Agreement, this Agreement shall
control. PGS shall have no obligation to make sales to FMPA or its Agent in lieu of the
transportation of Gas contemplated by this Agreement.
Section 3.2 PGS’s FPSC Tariff. For purposes of this Agreement, the following provisions shall
supersede those provisions of PGS’s FPSC Tariff covering the same subject matter:
(a)
Definition of “Retainage”. The definition of “Retainage” set forth in Special
Condition 1 of Rider ITS shall have no application to the service provided by PGS pursuant to this
Agreement.
(b)
Correction of Imbalances. Correction of imbalances shall be governed by Section
5.2 of this Agreement; provided, however, that FMPA shall be entitled to book out all or a portion
of the sum of Daily Imbalance Amounts for any Month among the PGS Receipt Point(s) in order
to determine the Monthly Imbalance Amount referenced in Section 5.2.
(c)
Allocations and Penalties. If PGS gives notice to FMPA or its Agent that the Alert
Day provisions of Special Condition 12 of Rider ITS are in effect for a Day as a result of an Alert
Day called by the Pipelines (as applicable) for such Day, FMPA shall be permitted a tolerance
(based on Scheduled Quantities for such Day) equal to the greater of a) the applicable tolerance
established by the Pipelines (as applicable) for such Day for the FGT Delivery Point(s) or GS
Delivery Point(s) listed on Exhibit A or B) the posted applicable PGS alert day tolerance; provided,
however, that FMPA or its Agent shall reimburse PGS for any Alert Day Charges or other penalties
provided by the aforesaid Special Condition 12 only if charges are actually imposed on PGS by
the Pipelines (as applicable) for the FGT Delivery Point(s) or GS Delivery Point(s) listed on Exhibit
A for the Day for which such charges or penalties would otherwise be imposed.
(d)
Curtailment and Interruption.
(1)
The Oleander Gate will be used by PGS solely for the purpose of providing
gas transportation service to Oleander, and no other customers of PGS will be served
using the Oleander Gate. Therefore, notwithstanding the provisions of PGS’s FPSC Tariff
and curtailment plan, PGS shall not interrupt or curtail deliveries to Oleander or TCEC
pursuant to this Agreement with FMPA or its Agent, or for the account of either, except
when a curtailment order is issued by FGT.
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(2)
In the event of a curtailment by FGT or GS, PGS shall not be required to
deliver to FMPA or its Agent more than the quantities of Gas which would otherwise be
allocated by FGT or GS to FMPA or its Agent in the absence of this Agreement.
(e)
Full Requirements. During the term hereof, all Gas used at Cane Island, TCEC
and Oleander will, at FMPA's or its Agent’s option, either be purchased from or transported by
PGS on PGS’s Distribution System, except to the extent FMPA's or its Agent’s requirements for
Cane Island, TCEC and Oleander are not delivered by PGS in accordance with this Agreement.
ARTICLE IV - NOMINATIONS
Section 4.1 General. Unless otherwise agreed, for each Day FMPA desires service hereunder,
FMPA or its Agent shall provide a Nomination to PGS pursuant to Sections 4.2 and/or 4.3 for
each PGS Delivery Point. All Nominations shall be made to PGS through its web site
(www.pgsunom.com) provided that, in an emergency, a Nomination may be delivered via
facsimile using the form set forth in PGS’s FPSC Tariff. Quantities confirmed by PGS for delivery
shall be Scheduled Quantities. If requested by FMPA or its Agent, PGS will allow increases or
decreases in Scheduled Quantities after the Nomination deadlines set forth in this article, if the
same can be confirmed by PGS, the Pipeline(s) and Suppliers, and can be accomplished without
detriment to services then scheduled on such Day for PGS and other shippers. The maximum
quantity PGS shall be obligated to make available for delivery to FMPA or its Agent on any Day
(which shall not exceed the MDQ) is the sum of (a) the Transportation Quantity and (b) the Sales
Quantity established pursuant to this article.
Section 4.2 Nomination for Purchase. Unless otherwise agreed, FMPA or its Agent shall
Nominate Gas for purchase hereunder not less than two (2) Business Days prior to the first Day
of any Month in which FMPA or its Agent desires to purchase Gas. Daily notices shall be given
to PGS at least one (1) Business Day (but not less than twenty-four (24) hours) prior to the
commencement of the Day on which FMPA or its Agent desires delivery of the Gas. If FMPA or
its Agent has timely Nominated a quantity for a particular Month, PGS shall confirm to FMPA or
its Agent the quantity PGS will tender for purchase by FMPA or its Agent (the “Sales Quantity,”
which shall also be a “Scheduled Quantity”) no later than 5:00 p.m. Eastern Prevailing Time on
the Business Day immediately preceding each Day during such Month.
Section 4.3 Nomination for Transportation. Unless otherwise agreed, FMPA or its Agent shall,
for each Month, and each Day during such Month that FMPA or its Agent seeks to change any
aspect of any prior Nomination, notify PGS by providing a completed Nomination. Daily
Nominations for Gas to be made available for delivery for FMPA’s or its Agent’s account shall be
given to PGS by the deadline for nominations set forth in the General Terms and Conditions of
the Pipeline’s FERC Tariff, except that there shall be no intra-day nominations unless the
interstate pipeline capacity used for the delivery of such intra-day quantity at the PGS Receipt
Point(s) is other than that committed to FMPA by PGS concurrently with the execution of this
Agreement under the Capacity Release Agreement. PGS shall confirm to FMPA or its Agent the
quantity PGS will make available for redelivery on such Day (the “Transportation Quantity,” which
shall also be a “Scheduled Quantity”) as soon as practicable, but not later than one hour after
receiving confirmation from the Pipeline(s).
Section 4.4 Other Responsibilities. FMPA or its Agent shall promptly notify PGS in writing of
any change in the Sales Quantity or Transportation Quantity for any Day, and PGS will use
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commercially reasonable efforts to accept any such requested change as soon as practicable,
but not later than one hour. PGS shall facilitate the addition of the points listed on Appendix A as
primary delivery points under PGS’s applicable Pipeline firm transportation service agreement,
assume all responsibilities as the delivery point operator for such points under the applicable
Pipeline’s FERC Tariff, and name FMPA or its Agent as PGS’s designee under the applicable
Pipeline’s FERC Tariff for the purpose of nominating Gas for delivery to such points.
Section 4.5 Confirmation. If Transporter asks PGS to verify a nomination for FMPA or its
Agent’s account, PGS shall confirm the lesser of such nomination or the Transportation Quantity
(“the Confirmation Quantity”). As a normal course of business, PGS shall use the Confirmation
Quantity provided by Transporter as FMPA’s or its Agent’s applicable Nomination pursuant to this
Agreement. PGS has no obligation with respect to verification or rejection of quantities not
requested by FMPA or its Agent.
Section 4.6 Mutually Beneficial Transactions. FMPA and its Agent recognizes that PGS
maintains the operation and system integrity of the PGS Distribution System on a daily basis, and
that PGS, as the delivery point operator for its points of interconnection with interstate pipelines,
is subject to the rules and regulations of such pipelines with regard to operational flow rates,
pressures and penalties. As such, PGS may from time to time need FMPA or its Agent to vary
its Nominated quantities of Gas to be delivered at the PGS Receipt Point(s). On such occasions,
PGS may in its sole discretion request, and FMPA or its Agent may agree to, a change in the
quantity of Gas to be delivered for the account of FMPA or its Agent at the PGS Receipt Point(s).
No such change in the quantity of Gas to be delivered shall be made pursuant to this section
without the consent of FMPA or its Agent. Terms and conditions of any such transaction will be
agreed upon between the parties at the time of the transaction and will be recorded and confirmed
in writing within two Business Days of the transaction.
Section 4.7 PGS Diversion Option. Notwithstanding any other provision of this Agreement,
PGS shall have the right, for up to six (6) Days of each Month during the term of this Agreement,
to direct FMPA or its Agent to nominate to FGT up to the lesser of (i) fifteen percent (15%) of
FMPA’s FGT Scheduled Quantities or (ii) 20,000 MMBtu on each such Day for delivery to a
pipeline delivery point that is not listed as a PGS Receipt Point for FGT listed on Appendix A to
this Agreement. For quantities so nominated by FMPA or its Agent, PGS shall pay to FMPA a
fee of $0.10 per MMBtu. In the event FMPA or its Agent fails to so Nominate quantities as directed
by PGS, FMPA agrees to hold PGS harmless from any documented pipeline penalties PGS incurs
as a direct result of such failure. Such documentation shall be provided by PGS to FMPA or its
Agent at the time of the PGS bill, invoice, or other notification to FMPA or its Agent for
reimbursement. Any fees payable to FMPA pursuant to this section shall be reflected as credits
on PGS’s bills rendered pursuant to Section 7.1.
ARTICLE V – DELIVERIES AND IMBALANCES
Section 5.1 Deliveries of Gas. All Gas delivered hereunder shall be delivered at rates of flow
as constant as operationally feasible throughout each Day. PGS has no obligation on any Day to
deliver on other that a uniform hourly basis in relation to the Scheduled Quantities. PGS will
provide FMPA with like service to that delivered to PGS by the Pipelines (as applicable) (e.g.,
pressure and deliverability to FMPA from PGS is contingent on service delivered to PGS by the
Pipelines, as applicable.) The point of delivery for all Gas confirmed by PGS for delivery
hereunder shall be at the outlet side of such billing meter(s) as shall be installed at the PGS
Delivery Point(s). Measurement of the Gas delivered shall be in accordance with PGS’s FPSC
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Tariff.
Section 5.2 Correction of Imbalances. All Daily Imbalance Amounts shall be resolved as of the
end of each Month. The sum of all Daily Imbalance Amounts incurred during a Month for the
FMPA Facilities (the “Monthly Imbalance Amount”) shall be resolved as set forth below.
(a) If a Monthly Imbalance Amount is Positive (i.e., Scheduled Quantities exceed Actual
Takes):
(1)
the portion of such Monthly Imbalance Amount which does not exceed
45,000 MMBtu (not to exceed 25,000 MMBtu at TCEC, and not to exceed 20,000 MMBtu
in the aggregate at Cane Island and Oleander), or a greater amount as to which PGS has
consented, will be carried by PGS as a credit toward Gas deliverable to FMPA pursuant
to this Agreement during the next succeeding Month, and the first Gas through the
meter(s) at the PGS Delivery Point(s) in such next succeeding Month shall be used to
eliminate or reduce the credit so carried by PGS, and
(2)
PGS shall purchase the Remaining Imbalance from FMPA (and FMPA
shall sell the same to PGS) at a price per MMBtu (the “Unit Price”) in accordance with
the cash out provisions in FGT’s FERC Tariff.
The total amount due FMPA or its Agent pursuant to this paragraph (b) shall be the product
of the Unit Price (calculated as set forth herein) and Remaining Imbalance. The Imbalance
Level shall be calculated by dividing the Remaining Imbalance by the Scheduled
Quantities for the Month in which the Monthly Imbalance Amount accumulated.
(b) If a Monthly Imbalance Amount is Negative (i.e., Actual Takes exceed Scheduled
Quantities):
(1)
45,000 MMBtu (not to exceed 25,000 MMBtu at TCEC, and not to exceed 20,000
MMBtu in the aggregate at Cane Island and Oleander), or a greater amount as to
which PGS has consented, will be carried by PGS as a debit toward Gas
deliverable to FPMA or its Agent pursuant to this Agreement during the next
succeeding Month, and the first Gas scheduled through the meter(s) at the PGS
Delivery Point(s) in such next succeeding Month shall be used to eliminate the
debit so carried by PGS, and
(2)
PGS shall sell the Remaining Imbalance to FMPA or its Agent (and FMPA
or its Agent shall purchase the same from PGS) at a price per MMBtu (the “Unit
Price”) in accordance with the cash out provisions of FGT’s FERC Tariff.
The total amount due PGS pursuant to this paragraph (b) shall be the product of the Unit
Price (calculated as set forth herein) and the Remaining Imbalance. The Imbalance Level
shall be calculated by dividing the Remaining Imbalance by the Scheduled Quantities for
the Month in which the Monthly Imbalance Amount accumulated.
(c) PGS shall, on PGS’s bill rendered to FMPA or its Agent pursuant to Section 7.1 for
the Month following the Month in which the amount payable by PGS to FMPA or its Agent
pursuant to subparagraph (a)(2) was incurred, credit to FMPA or its Agent such amount.
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All amounts not so credited by PGS shall be considered delinquent, and subject to the
Late Payment Charge.
(d) Within fifteen (15) Days following the end of the Month in which the amount payable
by FMPA or its Agent to PGS pursuant to paragraph (b) was incurred, PGS shall bill FMPA
for the amount payable by FMPA or its Agent, and FMPA or its Agent shall pay such bill
in accordance with Section 7.2. All amounts not so paid by FMPA or its Agent shall be
considered delinquent and subject to the Late Payment Charge.
Section 5.3 Pipeline Operator Accounts. FMPA shall have the option, by providing
PGS written notice, to have PGS Receipt Points listed on Appendix A to this Agreement added to
the PGS Pipeline Operator Account(s). While on the PGS FGT and/or GS Operator Account(s)
(if FMPA has exercised the aforesaid option), balancing of deliveries, alert days, operational flow
orders and any penalties associated therewith shall be governed by the provisions of PGS’s FPSC
Tariff and the provisions of Sections 5.1 and 5.2 of this Agreement. If the PGS Receipt Points
have been added to the PGS Pipeline Operator Account(s) pursuant to FMPA's written notice,
FMPA shall have the right to require the removal of the PGS Receipt Points from the PGS Pipeline
Operator Account(s) by giving PGS written notice of not less than three (3) months. At any time
that the PGS Receipt Points are not on the PGS Pipeline Operator Account(s), balancing of
deliveries, alert days, operational flow orders and any penalties associated therewith shall be
governed by the Pipeline FERC Tariff(s), as applicable, and Section 5.2 of this Agreement shall
not apply.
ARTICLE VI - TRANSPORTATION AND OTHER CHARGES
Section 6.1 Distribution Charge.
(a)
For Transportation Service to TCEC. FMPA or its Agent shall pay PGS each
Month for transportation service rendered by PGS to FMPA at TCEC, and/or for Gas purchased
from PGS for use by FMPA at TCEC, in accordance with Rate Schedule CIS of PGS’s FPSC
Tariff; provided, however, that the Distribution Charge for service under Rate Schedule CIS shall
be:
(1)
For the period from the date of this Agreement through and including the
end of the Day commencing on December 31, 2016, (i) $0.0102 per Therm for up to and
including 100 million Therms per year and (ii) (a) if there are up to two natural gas fired
combined cycle or other intermediate or base load generating units at TCEC that are
intermediate or base loaded (e.g., each with a 25% capacity factor or higher over a
calendar year), $0.0020 per Therm for all quantities over 100 million Therms per year or
(b) if there are more than two combined cycle or other intermediate or base load
generating units at TCEC, $0.0030 per Therm for all quantities over 100 million Therms
per year; and provided further, however, that the minimum annual aggregate of the
Distribution Charges paid by FMPA to PGS for transportation service to TCEC shall be
$750,000. If the aggregate of the Distribution Charges paid by FMPA or its Agent to PGS
during any Contract Year for transportation service to TCEC is less than $750,000, PGS
shall invoice FMPA or its Agent and FMPA or its Agent shall pay to PGS the amount of
the shortfall in accordance with the terms set out in Section 7.2 of this Agreement.
(2)
For the period from the beginning of the Day commencing on January 1,
2017, through and including December 31, 2020, (i) $0.0075 per Therm for up to and
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including 100 million Therms per year and (ii) $0.002 per Therm for quantities greater than
100 million Therms; provided that the minimum annual aggregate of the Distribution
Charges paid by FMPA to PGS for transportation service to TCEC shall be $750,000. If
the aggregate of the Distribution Charges paid by FMPA or its Agent to PGS during any
Contract Year for transportation service to TCEC is less than $750,000, PGS shall invoice
FMPA or its Agent and FMPA or its Agent shall pay to PGS the amount of the shortfall in
accordance with the terms set out in Section 7.2 of this Agreement.
(3)
2021, and continuing through the end of the Initial Term (or any extended term), the
Distribution Charge provided in subparagraph (1) above.
(b)
For Transportation Service to Cane Island and Oleander. FMPA or its Agent shall
pay PGS each Month for transportation service rendered by PGS to Cane Island and Oleander,
and/or for Gas purchased from PGS for use by FMPA at Cane Island and Oleander, in accordance
with Rate Schedule CIS of PGS’s FPSC Tariff; provided, however, that the Distribution Charge
for service under Rate Schedule CIS shall be:
(1)
For the period from the date of this Agreement through and
including the end of the Day commencing on December 31, 2016, (i) $750,000 per year
plus (ii) $0.01000 per Therm for all quantities over 50 million Therms per Contract Year
delivered to any FMPA Delivery Point (other than TCEC) listed on PGS’s FGT Delivery
Point Operator Agreement.
(2)
2017, through and including December 31, 2020, (i) $750,000.00 per year plus (ii) $0.0075
per Therm for all quantities over 50 million Therms per Contract Year delivered to any
FMPA Delivery Point (other than TCEC) listed on PGS’s FGT Delivery Point Operator
Agreement.
(3)
This Section 6.1 shall apply during the entire term of this Agreement whether or not the PGS
Receipt Points have been removed from the PGS Pipeline Operator Account(s).
ARTICLE VII - BILLING AND PAYMENT
Section 7.1 Billing. PGS will bill FMPA or its Agent each Month for all Actual Takes during the
preceding Month, and for any other amounts due hereunder. If, during the preceding Month, PGS
has purchased Gas from FMPA or its Agent pursuant to a curtailment order, such bill shall show
a credit for the estimated amount, based upon information provided by the Pipelines, due FMPA
or its Agent for such purchase(s). If the estimated amount owed by PGS to FMPA or its Agent
exceeds the amount FMPA or its Agent owes PGS, PGS shall pay FMPA or its Agent the net
amount estimated to be due FMPA or its Agent at the time PGS bills FMPA or its Agent.
Section 7.2 Payment. FMPA or its Agent shall pay such bills, minus any disputed amounts, at
the address specified in the invoice by the 20th Day following the date of FMPA’s or its Agent’s
receipt of the bill. All sums not so paid by FMPA or its Agent (or credited or paid by PGS) shall
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be considered delinquent.
Section 7.3 Billing Disputes. In the event of a billing dispute, FMPA, FMPA’s Agent or PGS,
as the case may be, shall pay (or credit) to the other party all amounts not in dispute, and the
parties shall negotiate in good faith to resolve the amount in dispute as soon as reasonably
practicable. If a party has withheld payment (or credit) of a disputed amount, and the dispute is
resolved, the non-prevailing party shall pay to the other party the amount determined to be due
such other party, plus interest thereon at an annual rate equal to the prime interest rate of Citibank,
N.A., New York, New York, plus one percent (1%), calculated on a daily basis from the date due
until paid (or credited).
Section 7.4 Errors or Estimates. If an estimate is used to determine the amount due FMPA or
its Agent for purchases by PGS pursuant to a curtailment order, PGS shall make any adjustment
necessary to reflect the actual amount due FMPA or its Agent on account of such purchases in
the next bill rendered to FMPA or its Agent after determination of the actual amount due. An error
in any bill, credit or payment shall be corrected in the next bill rendered after the error is confirmed
by both PGS and FMPA or its Agent.
ARTICLE VIII - FAILURE TO MAKE PAYMENT
Section 8.1 Late Payment Charge. Charges for services due and rendered which are unpaid
as of the past due date are subject to a Late Payment Charge at an annual rate equal to the prime
interest rate of Citibank, N.A., New York, New York, plus one percent (1%), calculated on a daily
basis from the date due.
Section 8.2 Other Remedies. If FMPA or its Agent fails to remedy a delinquency in any payment
within ten (10) Days after written notice thereof by PGS, PGS may, in addition to any other
remedy, without incurring any liability to FMPA or its Agent and without terminating this
Agreement, suspend further deliveries to FMPA or its Agent until the delinquent amount is paid,
but PGS shall not do so if the failure to pay is the result of a billing dispute, and all undisputed
amounts have been paid. If PGS fails to remedy a delinquency in providing a credit (or making
payment) to FMPA or its Agent for PGS purchases pursuant to an interruption or curtailment order
within ten (10) Days after FMPA or its Agent’s written notice thereof, FMPA or its Agent may, in
addition to any other remedy, without incurring liability to PGS and without terminating this
Agreement, suspend PGS’s right to retain and purchase FMPA or its Agent’s Gas pursuant to a
curtailment order, but FMPA or its Agent shall not do so if PGS’s failure to provide a credit (or
make payment) is the result of a billing dispute, and all undisputed amounts have been credited
or paid by PGS.
ARTICLE IX - MISCELLANEOUS
Section 9.1 Assignment and Transfer. Neither party may assign this Agreement without the
prior written consent of the other party (which shall not be unreasonably withheld) and the
assignee’s written assumption of the assigning party’s obligations hereunder. Upon any such
assignment and assumption, the assigning party shall furnish a copy thereof to the other party.
Section 9.2 Governing Law. This Agreement and any dispute arising hereunder shall be
governed by and interpreted in accordance with the laws of Florida and shall be subject to all
applicable laws, rules and orders of any Federal, state or local governmental authority having
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with this Agreement shall be in a court having jurisdiction, located within Leon County, Florida.
Section 9.3 Severability. If any term or provision hereof is declared by a court of competent
jurisdiction to be, or becomes under applicable law, illegal, unenforceable or invalid, such
illegality, unenforceability or invalidity shall not affect any other term or provision of this
Agreement, and this Agreement shall continue in full force and effect without said term or
provision; provided, however, that if such severability materially changes the economic benefits
of this Agreement to either party, the parties agree to negotiate in good faith to modify this
Agreement so as to effect the original intent of the parties as closely as possible in a mutually
acceptable manner (further provided, however, that the inability of the parties to agree after good
faith negotiations to a mutually acceptable modification shall not make this Agreement voidable
or terminable by a party).
Section 9.4 Entire Agreement; Appendices. This Agreement sets forth the complete
understanding of the parties as of the date first written above, and supersedes any and all prior
negotiations, agreements and understandings with respect to the subject matter hereof. The
appendices attached hereto are an integral part hereof. All capitalized terms used and not
otherwise defined in the appendices shall have the meanings given to such terms herein.
Section 9.5 Waiver. No waiver of any of the provisions hereof shall be deemed to be a waiver
Section 9.6 Notices. (a) All notices and other communications hereunder shall be in writing
confirmed with a read receipt), by facsimile (if receipt is confirmed by telephone) or by a
recognized overnight delivery service, or on the tenth (10th) day after mailing if mailed by first
class United States mail, registered or certified, return receipt requested, postage prepaid, and
properly addressed to the party as set forth below.
PGS:
FMPA:
Peoples Gas System
P. O. Box 2562
Telephone: (813) 228-4526
Facsimile: (813) 228-4643
E-mail:
Orlando, FL 32819
Telephone: 407-355-7767
Facsimile: 407-355-5794
E-mail:
With a Copy To:
With a copy to:
Peoples Gas System
P. O. Box 2562
2061-2 Delta Way
Telephone: (850) 297-2011
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Telephone: (813) 228-1556
Facsimile: (813) 228- 228-4643
Facsimile: (850) 297-2014
Payment:
Peoples Gas System
P. O. Box 2562
Telephone: (813) 228-4191
Facsimile: (813) 228-4643
Invoices:
Orlando, FL 32819
Telephone: 407-355-7767
Facsimile: 407-355-5795
Section 9.7 Amendments. This Agreement may not be amended except by an instrument in
writing signed by both PGS and FMPA. A change in (a) the place to which notices hereunder
must be sent or (b) the individual designated as Contact Person shall not be deemed nor require
an amendment hereof provided such change is communicated pursuant to Section 9.6.
Section 9.8 Project Agreement. This Agreement is a liability and obligation of the AllRequirements Power Supply Project only. No liability or obligation under this Agreement shall
inure to or bind any of the funds, accounts, monies, property, instruments, or rights of the Florida
Municipal Power Agency generally or any of any other "project" of FMPA as that term is defined
in the Interlocal Agreement Creating the Florida Municipal Power Agency, as may be amended
or supplemented pursuant thereto.
Section 9.9 Prior Agreements. PGS and FMPA entered into (i) that certain Gas Transportation
Agreement dated as of June 8, 2006, and (ii) that certain Gas Transportation Agreement dated
as of February 10, 2012 (the “TCEC Gas Transportation Agreement”) (collectively, the “Prior
Agreements”), and desire by this Agreement to amend, restate and combine the provisions of
said Prior Agreements in order to reimburse FMPA for PGS overbillings between May 2008 and
April 2014 under the TCEC Gas Transportation Agreement through extensions of the terms of the
Prior Agreements and of the Pipeline Capacity Release Agreement dated as of June 1, 2008,
between PGS and FMPA, and the Pipeline Capacity Release Agreement dated as of February
10, 2012, between PGS and FMPA, and modification of the rates set forth in the Prior
Agreements, and to reflect the additional agreements of the parties as set forth in this Agreement.
This Agreement shall supersede and replace, as of the date first written above, the Prior
Agreements; provided, however, that the obligations of a party that have accrued as of the date
first written above shall survive the termination of the Prior Agreements.
Section 9.10 Counterparts. This Agreement may be executed in one or more counterparts,
each of which shall be deemed an original, but all of which together shall constitute one and the
same instrument.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed
by their respective duly authorized officers as of the date first above written.
FLORIDA MUNICIPAL POWER
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AGENCY (All-Requirements
Power Supply Project)
By: ____________________________
Gordon L. Gillette
President
By:__________________________
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APPENDIX A – AMENDED AND RESTATED GAS TRANSPORTATION AGREEMENT
PGS RECEIPT POINT(S)
Maximum Transportation Quantity:
PGS Ft. Pierce Meter Station
154,000 MMBtu per Day
FGT or PGS Meter at Oleander
FGT Meter at Cane Island:
GS Meter at Cane Island:
Page 61 of 223
APPENDIX B – AMENDED AND RESTATED GAS TRANSPORTATION AGREEMENT
PGS DELIVERY POINT(S)
Maximum Delivery Quantity*
TCEC
Up to 9,000 MMBtu per Hour @ 475 psig
Oleander
Cane Island (FGT):
Cane Island (GS):
* PGS will provide FMPA with like service to that delivered to PGS by FGT or GS, as applicable (e.g., pressure
and deliverability (including hourly tolerance) to FMPA from PGS is contingent on service delivered to PGS by
FGT or GS, as applicable)
Page 62 of 223
This Amended and Restated Pipeline Capacity Release Agreement (this “Agreement”) is
made and entered into as of this 1st day of September, 2016, by and between Peoples Gas
System, a Division of Tampa Electric Company, a Florida corporation (“PGS”), and Florida
Municipal Power Agency (All-Requirements Power Supply Project), a governmental legal
entity created and existing pursuant to Florida law (“Customer”).
W I T N E S S E T H:
WHEREAS, PGS has contracted for certain transportation capacity pursuant to
agreements with Florida Gas Transmission Company, LLC, a Delaware limited liability company
(“FGT”) and Gulfstream Natural Gas System, L.L.C. (“GS”), a Delaware limited liability company
(FGT and GS, collectively, the “Pipelines,” and each a “Pipeline,” and said agreements and any
amendatory or superseding agreements being hereinafter referred to collectively as the “Pipeline
Agreements”) granting PGS certain rights to firm receipts of Gas into and firm deliveries of Gas out
of each Pipeline’s system (“Firm Transportation Capacity Rights”);
WHEREAS, the continuing effectiveness of the Pipeline Agreements or successor
agreements thereto is a condition precedent to PGS’s obligations hereunder in the manner set
forth herein;
WHEREAS, each Pipeline’s FERC Tariff (as hereinafter defined) permits the release of
rights to firm transportation service on the Pipeline’s system;
WHEREAS, PGS desires to release temporarily to Customer a portion of PGS’s Firm
Transportation Capacity Rights under the Pipeline Agreements in order to permit Customer to ship
Gas purchased from various suppliers to Pipeline Delivery Point(s) on PGS’s distribution system;
WHEREAS, PGS and Customer desire to set forth the rights and obligations of the parties
pertaining to, and the terms and conditions of, the release of such Firm Transportation Capacity
Rights; and
WHEREAS, PGS and Customer entered into (i) that certain Pipeline Capacity Release
Agreement dated as of June 1, 2008, and (ii) that certain Pipeline Capacity Release Agreement
dated as of February 10, 2012 (collectively, the "Prior Agreements"), and desire to amend, restate
and combine the provisions of said Prior Agreements in order to reflect the additional agreements
of the parties as set forth in this Agreement.
NOW, THEREFORE, in consideration of the mutual covenants and agreements herein set
forth, the parties hereto, intending to be legally bound, hereby agree as follows:
1.
Definitions.
As used in this Agreement, the following words and phrases shall have the following
meanings:
“Adverse Order” means an order, ruling or decision (a) issued by the FERC if such order, ruling or
decision has a material adverse effect on the ability of Customer, in its sole judgment, to receive firm
transportation service on the Pipelines using the Pipeline Capacity (without regard for the rates charged for such
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service by the Pipelines pursuant to their respective FERC Tariffs), or is otherwise materially adverse to PGS in its
sole reasonable judgment, or (b) issued by the PSC if such order is adverse to Customer in its sole judgment or if
such order, ruling or decision (i) increases or decreases, has the same effect as an increase or decrease in, or
requires PGS to increase or decrease, the distribution charge payable by Customer to PGS under the Gas
Transportation Agreement, (ii) requires (or has the same effect as requiring) any portion of the distribution charges
paid by Customer to PGS pursuant to the Gas Transportation Agreement to be used to reduce PGS’s cost of
purchased gas or pipeline transportation, or (iii) disallows (or has the same effect as disallowing) recovery by PGS
from its ratepayers other than Customer of the difference between the distribution charge set forth in Section 6.1
of the Gas Transportation Agreement and the distribution charge which would otherwise be payable by Customer
to PGS in the absence of the Gas Transportation Agreement, or is otherwise materially adverse to PGS in its sole
judgment.
“Agent” means any person or entity designated as such by Customer by written notice to PGS and who
or which (i) meets the creditworthiness requirements of a Pipeline’s FERC Tariff and, unless otherwise provided in
this Agreement, (ii) agrees in writing to assume and be responsible for all obligations of Customer under this
Agreement, Customer’s Service Agreement, Pipeline’s FERC Tariff or any applicable FERC regulation, order or
policy. As between PGS and Customer, Customer shall remain responsible for all performance required of it by
this Agreement notwithstanding its designation of an Agent to perform any or all of its obligations hereunder;
provided, however, that performance by Customer’s designated Agent of a Customer obligation under this
Agreement shall be deemed performance by Customer of such obligation.
“Alternate Pipeline Delivery Point” has the meaning given in subsection 3.2(f).
“Cane Island Capacity” means that portion of PGS’s Firm Transportation Capacity Rights identified as
such on Appendix A.
“Customer’s Service Agreement” means any firm transportation service agreement between Customer or
Agent and a Pipeline covering the use of the Pipeline Capacity released (i) by PGS to Customer or Customer’s
Agent pursuant to Section 3 hereof or (ii) by Customer to Agent pursuant to subsection 3.2(g) hereof, as such
agreement(s) may be amended from time to time.
“Customer’s Reservation Charge” means the effective Reservation Charge that capacity released to
Customer pursuant to this Agreement will be based upon, the same being (i) for the TCEC Capacity, the cost of
the TCEC Capacity paid to FGT under the FGT Agreement at the rate set forth in Rate Schedule FTS-1, and (ii)
for the Cane Island and Oleander Capacity, the weighted average cost of capacity paid to the Pipelines by PGS
for PGS’s existing portfolio of capacity released to Customer as of the date of this Agreement. Customer’s
Reservation Charge for the Cane Island and Oleander Capacity will be subject to change as the Reservation
Charges applicable to the PGS portfolio of capacity on the Pipelines occur from time to time in such Pipeline’s
FERC Tariff.
“Customer’s Pipeline Delivery Point” means the Pipeline Delivery Point listed on Appendix B.
“FERC” means the Federal Energy Regulatory Commission or any successor agency.
“FGT Agreement” means, collectively, (a) the Rate Schedule FTS-1 Service Agreement for Firm
Transportation Service between FGT and PGS dated August 27, 1999, and (b) the Rate Schedule FTS-2 Service
Agreement for Firm Transportation Service between FGT and PGS dated March 8, 1994, as amended and/or
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extended including (i) FGT's currently effective Rate Schedules FTS-1 and FTS-2 and (ii) General Terms and
Conditions filed with the FERC (and incorporated in said agreements by reference), as such agreements, rate
schedules and general terms and conditions may be amended from time to time, and any successor firm
“Force Majeure” means causes or events, whether of the kind hereinafter enumerated or otherwise, not
within the control of the party claiming suspension and which by the exercise of due diligence such party is unable
to prevent or overcome, including, but not limited to, acts of God, strikes, lockouts, or other industrial disturbances,
acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, sinkholes, lightning,
earthquakes, fires, storms, floods, washouts, arrests and restraints of governments and people, civil disturbances,
and explosions; such term shall likewise include the inability of either party to acquire, or delays on the part of
such party in acquiring at reasonable cost and by the exercise of reasonable diligence, servitudes, rights of way,
grants, permits, permissions, licenses, or required governmental orders, necessary to enable such party to fulfill
its obligations hereunder.
deliveries into its system at the Pipeline Receipt Point(s).
“Gas Transportation Agreement” means the Amended and Restated Gas Transportation Agreement
dated as of even date herewith between PGS and Customer, as the same may be amended from time to time.
“GS” means Gulfstream Natural Gas System, L.L.C., a Delaware limited liability company, its successors
and assigns.
“GS Agreement” means the Rate Schedule FTS firm transportation service agreement between GS and
PGS dated June 4, 2010, including GS’s currently effective Rate Schedule FTS and General Terms and
Conditions filed with the FERC (and incorporated in said agreement by reference), as such agreement, rate
schedule and general terms and conditions may be amended from time to time, and any successor firm
“Month” means “Delivery Month” as defined in Pipeline’s Tariff.
“Oleander Capacity” means that portion of PGS’s Firm Transportation Capacity Rights identified as such
on Appendix A.
“Party” or “Parties”, as the context requires, means PGS and/or Customer (or Customer’s Agent to the
extent Customer’s Agent is responsible for the performance of Customer’s obligations hereunder).
“Pipeline Capacity” means, as appropriate, either or both of:
(a) that portion identified on Appendix A of PGS’s Firm Transportation Capacity Rights under the FGT
Agreement designated as TCEC Capacity, from the Pipeline Receipt Point(s) identified in Appendix A for the
TCEC Capacity, to the Primary Pipeline Delivery Point(s) identified in Appendix B for the TCEC Capacity, and
expressed in MMBtu (or Dth) per Day of MDTQ (as defined in the Pipeline Agreement as of the date of execution
of this Agreement), subject to modification by PGS from time to time as provided in subsection 3.2(i); and
(b) either or both of (i) that portion identified on Appendix A of PGS’s Firm Transportation Capacity
Rights under the FGT Agreement designated as Cane Island and Oleander Capacity, or (ii) that portion identified
on Appendix A of PGS’s Firm Transportation Capacity Rights under the GS Agreement designated as Cane
Island and Oleander Capacity, from the Pipeline Receipt Point(s) identified in Appendix A for the Cane Island and
Oleander Capacity, to the Primary Pipeline Delivery Point(s) identified in Appendix B for the Cane Island and
Oleander Capacity, and expressed in MMBtu (or Dth) per Day of MDTQ (as defined in the Pipeline Agreement as
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of the date of execution of this Agreement), subject to modification by PGS from time to time as provided in
subsection 3.2(i).
“Pipeline Delivery Point(s)” means the point(s) identified in Appendix B. Customer understands and
agrees that such point(s) shall be identical to the point(s) listed from time to time as points of delivery in the
applicable Pipeline Agreement, and that Appendix B hereto shall be deemed to have been amended (without any
further action by the parties to this Agreement) upon the effective date of any amendment to a Pipeline
Agreement which changes the points of delivery listed therein. Immediately following any such amendment to a
Pipeline Agreement, PGS shall furnish to Customer, for attachment to this Agreement, a revised Appendix B
hereto, which shall reflect the effective date thereof.
“Pipeline Receipt Point(s)” has the meaning given in subsection 3.3.
“Pipeline’s FERC Tariff” means, as to the applicable Pipeline Capacity, either (i) FGT’s effective FERC
gas tariff applicable to firm transportation service under the FGT Agreement, or (ii) GS’s effective FERC gas tariff
applicable to firm transportation service under the GS Agreement, in each such case as such tariff may be
amended from time to time.
“PSC” means the Florida Public Service Commission or any successor entity.
“Primary Pipeline Delivery Point(s)” means the Pipeline Delivery Point(s) shown on Appendix B, subject
to modification by mutual agreement of the parties, as provided in subsection 3.2(i).
“Reservation Charge” means the amount (expressed in dollars per MMBtu) which is equal to the
maximum reservation charges chargeable by the Pipelines to Customer for firm transportation service for the
Pipeline Capacity under Customer's Service Agreement, together with all applicable surcharges and other
charges, as set forth in the Pipeline’s FERC Tariff.
“Right of First Refusal Mechanism” means the provision for the exercise of the right of first refusal of Firm
Transportation Capacity Rights on a Pipeline’s system as included in the Pipeline’s FERC Tariff.
“Summer” means the Months of May through and including October.
“TCEC Capacity” means that portion of PGS’s Firm Transportation Capacity Rights identified as such on
Appendix A.
“Winter” means the Months of November through and including April.
2.
Term and Early Termination.
2.1
Term. This Agreement shall become effective on September 1, 2016. The term of
this Agreement shall commence at the beginning of the Day commencing on said date, and
continue, unless earlier terminated pursuant to the provisions of this Agreement, through the end of
the Day commencing on December 31, 2033 (the “Initial Term”). Not less than one (1) year prior to
the expiration of the Initial Term, Customer shall have the unilateral right to extend the term of this
Agreement for a period of five (5) years by executing and tendering to PGS for execution an
amendment to this Agreement so extending its term (which amendment shall be binding on PGS
whether or not PGS executes the same). Subsequent to the expiration of any such additional fiveyear extension of the term, the parties agree to negotiate in good faith to agree on a mutually
beneficial agreement for a subsequent term, if any, as mutually agreed. In connection with any
such further extension of the term, the agreement of neither party hereto shall be unreasonably
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withheld.
2.2
Early Termination. This Agreement may be terminated prior to the expiration of
the Initial Term or any extended term in accordance with the provisions of this Agreement If either
party determines an Adverse Order has been received, such Party shall have the right to terminate
this Agreement with ten (10) calendar days notice to the other party contingent upon the concurrent
release (without recall rights) to Customer of the Pipeline Capacity for the remaining term of this
Agreement and any permitted subsequent extensions thereof by Customer pursuant to Section
2.1; provided that any such termination shall not affect the obligation of either party to pay amounts
due and owing hereunder as of and prior to the date of such termination. A party’s delay in
exercising its right to terminate pursuant to this subsection shall not be deemed to be, nor shall it
constitute, a waiver of such right as long as such right is exercised within 15 calendar days of the
effective date of the final, non-appealable Adverse Order.
2.3
Maintenance of the Gas Transportation Agreement. PGS shall have the right to
terminate this Agreement if the Gas Transportation Agreement is terminated for any reason other
than a material breach thereof by PGS, such termination to be effective as of the date specified in
the notice of termination delivered by PGS to Customer, which date shall be not less than ten (10)
Days after the date of such notice and such termination date shall coincide with the end of the
calendar month.
2.4
Options to Reduce Service. At any time after April 30, 2023, if FMPA
permanently retires either: (i) TCEC, or (ii) both of Cane Island Units 3 and 4 along with termination
of the Oleander PPA, then FMPA has the one-time option to reduce service related to the retired
assets. That is, if FMPA retires TCEC, then service to TCEC will no longer be provided under this
Agreement. Or, if FMPA retires Cane Island Units 3 and 4, and terminates the Oleander PPA, then
service to Cane Island and Oleander will no longer be provided under this Agreement If Customer
exercises the aforesaid option to reduce service to the retired assets, then PGS will recall the
Pipeline Capacity associated with the provision of service to the retired assets.
3.
Release of Pipeline Capacity.
3.1
Releases.
(a)
Subject to the provisions of this Agreement, PGS agrees to
provide to the Pipeline(s) in accordance with the applicable Pipeline’s FERC Tariff a
Relinquishment Notice (as such term is used in a Pipeline’s FERC Tariff) with respect to the
Pipeline Capacity, within a time sufficient for Customer to commence the use of the Pipeline
Capacity (in the manner provided in this Agreement) on the date on which the term of this
Agreement commences. Such Relinquishment Notice shall offer to relinquish temporarily, as a
prearranged transaction, at Customer’s Reservation Charge, and on the terms set forth in and for
the term of this Agreement, the Pipeline Capacity (hereinafter, “release”). Customer agrees to
acquire the Pipeline Capacity pursuant to the terms and conditions of the applicable Pipeline’s
FERC Tariff and this Agreement.
(b)
PGS agrees to (i) temporarily recall, for each Day during the term of this
Agreement, such portion of the Pipeline Capacity as Customer, not less than thirty minutes before
FGT’s and/or GS’s timely recall notification deadline, specifies in writing to PGS, and (ii) not after
10:00 a.m. Eastern Clock Time sell to Customer pursuant to Section 4.6 of the Gas Transportation
Agreement that quantity of Gas Customer needs up to the difference between (x) the maximum
available capacity for the applicable month under this Agreement and (y) the quantity retained by
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Customer after the actions taken pursuant to paragraph (b)(i) above. Such Gas will be sold by
PGS to Customer at FGT Zone Platts Gas Daily Index for the corresponding zone for the
applicable Pipeline Receipt Point in Appendix A plus, based on the type of capacity (FTS-1, FTS-2
and/or GS) utilized, the maximum applicable reservation, usage and fuel rates. The order of
capacity made available to Customer shall be from the least cost reservation charge to the most
expensive reservation charge (up to maximum contract quantity).
(c)
All temporary recalls made by PGS pursuant to paragraph (b) above shall be made
in such a manner as to: (i) first recall all released FGT FTS-2 Pipeline Capacity until Customer
has none remaining, then (ii) unless and to the extent that Customer has exercised its rights
pursuant to the next sentence, begin recalling all released GS Pipeline Capacity until Customer
has none remaining, and (iii) lastly, recall all released FGT FTS-1 Pipeline Capacity. In the event
Customer or Customer’s Agent requests to retain released GS Pipeline Capacity, then PGS shall
recall all released FGT FTS-1 Pipeline Capacity prior to recalling any released GS Pipeline
Capacity.
(d)
If PGS temporarily recalls the Pipeline Capacity (or any portion thereof) as
permitted by this Agreement, upon the expiration of such temporary recall, the temporarily recalled
portion of the Pipeline Capacity shall automatically revert to Customer; provided, however, that if
necessary upon the expiration of the temporary recall to enable Customer to again have the use of
the temporarily recalled portion of the Pipeline Capacity, the parties hereto shall, immediately
following the expiration of such temporary recall, comply with the provisions of paragraph (a)
above.
3.2
Conditions to Release. Any release of the Pipeline Capacity by PGS provided for
in subsection 3.1 above shall be subject to the following conditions:
(a)
Customer shall, in accordance with the applicable Pipeline’s FERC Tariff, enter into
a firm transportation service agreement with Pipeline for the Pipeline Capacity acquired pursuant to
subsection 3.1 (“Customer’s Service Agreement”), and shall have sole responsibility for complying
with (i) all provisions of such agreement and (ii) all applicable provisions of Pipeline’s FERC Tariff.
(b)
PGS shall retain the sole right (i) to affirmatively exercise, at the time required by
the applicable Pipeline Agreement, Pipeline’s FERC Tariff, Customer’s Service Agreement, or any
FERC rule or order, any Right of First Refusal Mechanism (however denominated), including the
option to extinguish such right, applicable to the Pipeline Capacity, and (ii) to exercise or fail to
exercise any right to extend a Pipeline Agreement as it pertains to the Pipeline Capacity; provided,
however, that PGS may not exercise any such right in a manner which would impair Customer’s
right to use, in the manner provided herein, the Pipeline Capacity during the term of this Agreement
and all subsequent extensions pursuant to subsection 2.1 of this Agreement. Notwithstanding the
foregoing proviso, PGS shall have the right to temporarily recall the Pipeline Capacity in the event
such recall is necessary to enable PGS to exercise the rights set forth in this paragraph (b), or to
construe the release of the Pipeline Capacity to Customer pursuant to this Agreement as a
temporary, as opposed to a permanent, release. In the event that PGS would elect to turn back a
portion of or all of the Pipeline Capacity to the pipelines under the provisions of this paragraph,
PGS shall negotiate with Customer (which negotiation shall not be unreasonably conditioned,
withheld or delayed by either party) for the permanent release to Customer of the respective
Pipeline Capacity prior to such turn back.
(c)
Customer agrees to make all payments to Pipeline required by Customer’s Service
Agreement, by Pipeline’s FERC Tariff, or by any applicable FERC rule or order, within the time and
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in the manner provided in such service agreement, tariff, rule or order. If Customer fails to make
such payments in such manner, PGS may make payment directly to Pipeline on behalf of
Customer (in a manner which preserves any rights which Customer may have to dispute the nature
or amount of the charges so paid), and Customer shall reimburse PGS for such amounts pursuant
to the terms of Section 4 of this Agreement.
(d)
If, subsequent to any release provided for in subsection 3.1, PGS is not released by
Pipeline from the obligation to pay the full amount of the Reservation Charges attributable to the
Pipeline Capacity, and PGS is required to make payment of amounts payable by Customer to
Pipeline associated with Customer’s holding the right to use (or Customer’s use of) the Pipeline
Capacity, Customer shall reimburse PGS for such amounts pursuant to the terms of Section 4 of
this Agreement.
(e)
Subsequent to any release of the Pipeline Capacity by PGS to Customer as
provided for herein, Customer shall not seek or consent to (except as provided in paragraph (i) of
this subsection) any amendment or modification of Customer’s Service Agreement in a manner
that is adverse to the exercise by PGS of its rights hereunder, or under the Pipeline Agreements,
which would change the quantity or term thereof, the Pipeline Receipt Point(s), or the Primary
Pipeline Delivery Point(s), without the prior written consent of PGS (which consent shall not be
unreasonably withheld or delayed). The foregoing provisions of this paragraph (e) shall not
prevent Customer from using alternate points of receipt into or within the Pipeline system in
connection with Customer’s use of the Pipeline Capacity.
(f)
Notwithstanding the provisions of paragraph (e) above, Customer may nominate to
Pipeline a Pipeline Delivery Point other than Customer’s Pipeline Delivery Point (an “Alternate
Pipeline Delivery Point”) for use by Customer in receiving deliveries of all or any portion of the
Pipeline Capacity pursuant to Customer’s Service Agreement. Subject to the foregoing
requirements and the other provisions of this Agreement, PGS will confirm quantities so nominated
by Customer for delivery at such Alternate Pipeline Delivery Point if (i) deliveries identified in
Appendix B in the quantities nominated by Customer can be effected at such point and (ii) PGS
determines, in its reasonable judgment, that to do so will not adversely affect its ability to effectively
implement curtailment or interruption in order to maintain service to high priority customers
pursuant to its tariff and curtailment plan on file with the PSC from time to time.
(g)
provided for herein, Customer shall not, during the term of this Agreement, release the Pipeline
Capacity (or any portion thereof) to a third party unless the term of such release ends on or
before the date on which Customer's right to use such Pipeline Capacity hereunder expires and
unless such release, in a manner permitted by the Pipeline's FERC Tariff and/or applicable
FERC regulations, prohibits the re-release of the portion of the Pipeline Capacity so released by
Customer. In addition, if Customer desires to release all or any portion of the Pipeline Capacity
released to Customer on a temporary basis, Customer shall provide written notice to PGS (a
"Release Notice") specifying (1) the quantity of the Pipeline Capacity Customer desires to
release, (2) the time period for which such quantity is to be released, and (3) the portion of the
Reservation Charge it desires to be paid for the quantity desired to be released. Except in the
case of a release by Customer to Agent, PGS shall have, in the case of a proposed release for
a period of one Month or less, not less than one Business Day (and in no event less than 24
hours), and in the case of a proposed release for a period of more than one Month, not less
than two Business Days (and in no event less than 48 hours), from the time of its receipt of a
Release Notice within which to respond thereto by offering in writing to pay all or that requested
portion of the Reservation Charge for the portion of the Pipeline Capacity and the term specified
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in the Release Notice. If PGS fails to timely respond to a Release Notice, then Customer’s offer
to temporarily release the Pipeline Capacity (in the quantity and on the terms set forth in the
Release Notice) may be posted on Pipeline’s electronic bulletin board in the manner provided
by the Pipeline’s FERC Tariff. If PGS timely responds to a Release Notice by offering to pay all
or any portion of the Reservation Charge for the portion of the Pipeline Capacity and the term
specified in the Release Notice, then Customer’s offer to temporarily release the Pipeline
Capacity (in the quantity and on the terms set forth in the Release Notice) shall be posted on
Pipeline’s electronic bulletin board in the manner provided by Pipeline’s FERC Tariff. In either
of the above cases, following the posting on Pipeline’s electronic bulletin board of Customer’s
offer, the temporary release of the Pipeline Capacity specified in the Release Notice shall be
governed by the applicable provisions of Pipeline’s FERC Tariff.
(h)
Subsequent to the release of the Pipeline Capacity by PGS to Customer as
provided for herein, and subject to the provisions of subsection 3.1(b), PGS may temporarily recall,
after providing Customer or Customer’s Agent reasonable notice, such portion of the Pipeline
Capacity as has not been (at the time of PGS’s recall) scheduled by Customer or Customer’s
Agent for the purpose of a Pipeline’s making deliveries at a Pipeline Delivery Point or an Alternate
Pipeline Delivery Point, if PGS determines in its reasonable judgment that such temporary recall is
required in order to maintain PGS’s ability to (i) maintain service to high priority customers, or (ii)
effectively implement curtailment or interruption of service pursuant to the Gas Transportation
Agreement in order to maintain service to high priority customers pursuant to its tariff and
curtailment plan on file with the PSC from time to time.
(i)
provided for herein, and subject to the provisions of subsection 3.1(b), PGS may temporarily recall,
after providing Customer or Customer’s Agent reasonable notice, the FGT Capacity for the
purpose of modifying the Primary Pipeline Delivery Point(s) (and the amount of firm transportation
capacity at such point(s)) in such manner as PGS deems necessary, in its reasonable discretion,
for the purpose of maintaining its ability to manage its distribution system as set forth in clauses (i)
and (ii) of paragraph (h) of this subsection 3.2. To the extent permitted by Pipeline, PGS will
implement such temporary recall rights in a manner that does not cause any lapse in Customer’s
right, or if the Pipeline Capacity or any portion thereof has been re-released by Customer to a
third party, such third party’s right, to use the Pipeline Capacity. To the extent permitted by FGT,
PGS will implement such temporary recall rights in a manner that does not cause any lapse in
Customer’s right to use 20,000 MMBtu per Day of the TCEC Capacity.
(j)
Customer shall have the right to designate an Agent to whom or which (i) Customer
may direct, in writing, PGS to release the Pipeline Capacity pursuant to subsection 3.1 of this
Agreement, or (ii) Customer may release the Pipeline Capacity pursuant to paragraph (g) above.
Customer may, on thirty (30) Days’ written notice to PGS, change the person designated as Agent
hereunder.
3.3
Pipeline Receipt Point(s). The primary point(s) of receipt on the Pipeline system
from which PGS agrees to release capacity as provided in subsection 3.1 (“Pipeline Receipt
Point(s)”), together with the maximum quantity of Gas which may be tendered by Customer (or for
its account) at each such point, are identified on Appendix A. Appendix A shall be amended
through mutual agreement to reflect any change in the quantity of the Pipeline Capacity pursuant to
this Agreement.
3.4
Refunds. If, after the effective date of any PGS release of the Pipeline Capacity to
Customer pursuant to subsection 3.1, Customer receives from a Pipeline any refund of any
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charges previously paid by PGS to the Pipeline under a Pipeline Agreement, including but not
limited to Reservation Charges (or portions thereof), Customer shall, in the Month following its
receipt of such refund, pay to PGS the amount of such refund (or, where PGS owes Customer
funds, PGS shall provide Customer with a credit). If, after the termination of this Agreement, PGS
receives from a Pipeline any refund of any charges previously paid by Customer to the Pipeline
pursuant to the terms of this Agreement (or the terms of Customer’s Service Agreement), including
but not limited to Reservation Charges (or portions thereof), PGS shall pay or credit to Customer
the amount of such refund, such payment or credit to be made or effected, to the extent
practicable, in the Month following PGS’s receipt of such refund. The obligations of each of
Customer and PGS under this subsection shall survive the termination of this Agreement.
4.
Billing and Payment. (a) In the event it is necessary that either party hereto bill the other
party for amounts payable by such other party pursuant to this Agreement, then the billing party
shall, as soon as practicable after such amounts are determined, deliver a bill to the other party for
such amounts. Such amounts shall be due on or before the tenth Business Day following the
billing party’s mailing (as signified by the postmark) or other delivery of such bill. All sums not so
paid by the other party shall be considered delinquent. If the other party fails to pay any such
amounts when due, interest shall be calculated on the overdue amount at an annual rate of interest
equal to the prime interest rate of Citibank, N.A., published in New York, New York, plus one
percent (1%), calculated from the date that such payment was due until the date that it is paid. If
Customer fails to make any payment when due and such failure is not remedied by or on behalf of
Customer within five (5) Days after written notice by PGS of such default in payment, then PGS, in
addition to any other remedy it may have, may without damage and without terminating this
Agreement, suspend further deliveries of Gas to Customer pursuant to the Gas Transportation
Agreement until such amount is paid; provided, however, that PGS shall not suspend deliveries of
Gas to Customer pursuant to the Gas Transportation Agreement if (i) Customer’s failure to pay is
the result of a bona fide dispute, (ii) Customer has paid PGS for all amounts not in dispute and (iii)
the dispute is being resolved in accordance with paragraph (b) of this Section 4.
(b)
In the event of a bona fide billing dispute, Customer or PGS, as the case may be,
shall pay (or credit) to the other party all amounts not in dispute, and the parties shall negotiate in
good faith to resolve the amount in dispute as soon as reasonably practicable. If a party has
withheld payment (or credit) of a disputed amount, and the dispute is resolved in favor of the other
party, the non-prevailing party shall pay to the other party the amount determined to be due such
other party, plus interest thereon at an annual rate equal to the prime interest rate of Citibank, N.A.,
New York, New York, plus one percent (1%), calculated on a daily basis from the date due until
paid (or credited).
(c)
If an error is discovered in any bill rendered (or credit given or payment made)
hereunder, or in any of the information used in the calculation of such bill (or such credit or
payment), the billing party shall, within two years and to the extent practicable, make an adjustment
to correct such error in the next bill rendered after the date on which the error is confirmed. The
provisions of this section shall survive the termination of this Agreement.
5.
Regulatory Jurisdiction over Transactions.
5.1
PSC Jurisdiction. Customer recognizes and agrees that PGS is a public utility
subject to regulation by the PSC. Compliance by PGS with any rule or order of the PSC or any
other federal, state or local governmental authority acting under claim of jurisdiction issued before
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or after the effective date of this Agreement shall not be deemed to be a breach hereof; provided,
however, that PGS will use all commercially reasonable efforts (which are consistent with its status
as a public utility) to mitigate any material adverse effect which its compliance with the terms of any
such rule or order would have on the rights of and costs to Customer as contemplated by this
Agreement.
6.
Limitation of Liability and Force Majeure.
6.1
Force Majeure. The obligations of each party under this Agreement, and the
performance thereof, other than a failure or delay in the payment of money due hereunder, shall be
excused during such times and to the extent such performance is prevented by reason of Force
Majeure.
6.2
Resumption of Performance. The party whose performance is excused by an
event of Force Majeure shall promptly notify the other party of such occurrence and its estimated
duration, and shall promptly remedy such Force Majeure if and to the extent reasonably possible
and resume such performance when possible; provided, however, that neither party shall be
required to settle any labor dispute against its will.
6.3
Limitation of Liability. Neither PGS nor Customer shall be liable to the other or to
any person claiming through the other for special, indirect or punitive damages, lost profits, or lost
opportunity costs relating to any matter covered by this Agreement.
7.
Events of Default; Remedies. (a) The occurrence of any of the following events shall
constitute an event of default (“Event of Default”) as to the non-performing party under this
Agreement:
(i) failure by (1) either party to make any payment required to be made hereunder
or (2) by Customer to comply with the requirements of subsection 3.2(g), and such failure
shall continue for five (5) Days after notice from the other party of such failure; or
(ii) failure by either party to comply in any material respect with any material term or
provision of this Agreement, other than a failure specified in clause (i) above, and such
failure shall continue for thirty (30) Days after written notice thereof has been given to the
non-performing party; or
(iii) the dissolution or liquidation of a party; or the failure of a party within sixty (60)
Days to lift any execution, garnishment or attachment of such consequence as may
materially impair its ability to carry on its operations; or the failure of a party generally to pay
its debts as such debts become due; or the making by a party of a general assignment for
the benefit of creditors; or the commencement by a party (as the debtor) of a voluntary case
in bankruptcy under the Federal Bankruptcy Code (as now or hereafter in effect) or any
proceeding under any other insolvency law; or the commencement of a case in bankruptcy
or any proceeding under any other insolvency law against a party (as the debtor); or the
appointment or authorization of a trustee, receiver, custodian, liquidator or agent, however
named, to take charge of a substantial part of the property of a party for the purpose of
general administration of such property for the benefit of creditors; or the taking of any
corporate action by a party for the purpose of effecting any of the foregoing.
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(b)
Upon the occurrence and continuation of an Event of Default, the non-defaulting
party may, at its option, and in addition to and cumulatively of any other rights and remedies it may
have hereunder, at law, in equity or otherwise, terminate this Agreement upon ten (10) Days' prior
written notice to the defaulting party, or enforce, by all lawful means, its rights hereunder, including
without limitation, the collection of sums due hereunder without terminating this Agreement, and
should it be necessary for such party to take any legal action in connection with such enforcement,
the defaulting party shall pay such non-defaulting party all costs and reasonable attorneys' fees so
incurred.
8.
Notices.
(a)
All notices and other communications hereunder shall be in writing
confirmed with a read receipt), by facsimile (if receipt is confirmed by telephone) or by a recognized
overnight delivery service, or on the tenth (10th) day after mailing if mailed by first class United
States mail, registered or certified, return receipt requested, postage prepaid, and properly
addressed to the party as set forth below.
PGS:
FMPA:
Peoples Gas System
P. O. Box 2562
Telephone: (813) 228-4526
Facsimile: (813) 228-4643
E-mail:
Orlando, FL 32819
Telephone: 407-355-7767
Facsimile: 407-355-5794
E-mail:
With a Copy To:
2061-2 Delta Way
Telephone: (850) 297-2011
Facsimile: (850) 297-2014
With a copy to:
Peoples Gas System
P. O. Box 2562
Telephone: (813) 228-1556
Facsimile: (813) 228- 228-4643
Peoples Gas System
P. O. Box 2562
Telephone: (813) 228-4191
Facsimile: (813) 228-4643
Orlando, FL 32819
Telephone: 407-355-7767
Facsimile: 407-355-5795
(b)
Each of Customer and PGS shall designate in writing an individual to act as its
“Contact Person”, which individual shall be (i) duly authorized with respect to all operational matters
arising under this Agreement and (ii) accessible to PGS or Customer (as the case may be) at all
times during each Day during the term of this Agreement. In the performance of its obligations
hereunder, PGS and Customer shall be entitled to rely, respectively, upon any instruction, consent
or acknowledgement given by such Contact Person with respect to operational matters arising
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hereunder or under the applicable Pipeline Agreement.
9.
Miscellaneous.
9.1
Independent Parties.
PGS and Customer shall perform hereunder as
independent parties and neither PGS nor Customer is in any way or for any purpose, by nature of
this Agreement or otherwise, a partner, joint venture, agent, employer or employee of the other.
Nothing in this Agreement shall be for the benefit of any third person for any purpose, including
without limitation, the establishing of any type of duty, standard of care or liability with respect to
any third person.
9.2
No Waiver. No waiver of any of the provisions hereof shall be deemed to be a
waiver of any other provision whether similar or not. No waiver shall constitute a continuing waiver.
No waiver shall be binding on a party unless executed in writing by that party.
9.3
Amendments. This Agreement shall not be amended except by an instrument in
writing signed by the party against which enforcement of the amendment is sought. A change in
(a) the place to which notices hereunder must be sent, or (b) the individual designated as a party's
Contact Person shall not be deemed nor require an amendment hereof provided such change is
communicated pursuant to Section 8(a).
9.4
Entire Agreement. This Agreement constitutes the entire agreement between the
parties with respect to the Pipeline Capacity and Customer’s use thereof, and supersedes all prior
negotiations, agreements and understandings between the parties with respect thereto.
9.5
Successors and Assigns. This Agreement shall be binding upon, and inure to the
benefit of, the parties hereto and their respective successors and permitted assigns; provided,
however, that neither party may assign this Agreement without the prior written consent of the
other (which shall not be unreasonably withheld) and the assignee's written assumption of the
assigning party's duties and obligations hereunder. Upon any such assignment and assumption,
the assigning party shall furnish a copy thereof to the other party.
9.6
Governing Law; Venue. This Agreement and any dispute arising hereunder shall
be governed by and interpreted in accordance with the laws of the State of Florida without giving
effect to provisions which would cause the law of another jurisdiction to apply, and shall be subject
to all applicable laws, rules and orders of any federal, state or local governmental authority having
with this Agreement shall be in a court located in the State of Florida in Leon County and having
jurisdiction.
9.7
Severability. If any term or provision hereof is declared by a court of competent
jurisdiction to be, or becomes under applicable law, illegal, unenforceable or invalid, such illegality,
unenforceability or invalidity shall not affect any other term or provision of this Agreement, and this
Agreement shall continue in full force and effect without said term or provision; provided, however,
that if such severability materially changes the economic benefits of this Agreement to either party,
the parties agree to negotiate in good faith to modify this Agreement so as to effect the original
intent of the parties as closely as possible in a mutually acceptable manner (further provided,
however, that the inability of the parties to agree after good faith negotiations to a mutually
acceptable modification shall not make this Agreement voidable or terminable by a party).
12
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9.8
Inspection. Each party hereto shall have the right during the term hereof and for a
period of three (3) years thereafter, upon reasonable prior notice and during normal business
hours, to examine the books, records and documents of the other party to the extent necessary to
verify the accuracy of any statement or charge made hereunder. Each party shall keep each such
record and document for a period of three (3) years from the date the same is created or any entry
or adjustment thereto is made.
9.9
Project Agreement. This Agreement is a liability and obligation of the AllRequirements Power Supply Project only. No liability or obligation under this Agreement shall
inure to or bind any of the funds, accounts, monies, property, instruments, or rights of the Florida
Municipal Power Agency generally or any of any other "project" of FMPA as that term is defined in
the Interlocal Agreement Creating the Florida Municipal Power Agency, as may be amended or
supplemented pursuant thereto.
9.10 Prior Agreements. This Agreement shall supersede and replace, as of the date
first written above, the Prior Agreements; provided, however, that the obligations of a party that
have accrued as of the date first written above shall survive the termination of the Prior
Agreements.
9.11 Counterparts. This Agreement may be executed in one or more counterparts,
same instrument.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed
by their respective duly authorized officers as of the date first written above.
(All-Requirements Power Supply Project)
By: ____________________________
Gordon L. Gillette
President
By:____________________________
13
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PIPELINE RECEIPT POINT(S)
FTS-1
DRN
337605
241390
314571
24229
255292
23422
32606
454599
23703
6490
50026
Description
Refugio-Crosstex
Destin
ANR St. Landry
Amoco Judge Digby
Tejas Calhoun
Sabine Pass Plant
NGPL Vermillion
Markham – Gulf Shore
NGPL Jefferson
TX Gas Eunice
Trunkline Manchester
Oct
0
5,000
0
7,453
1,226
0
3,647
5,000
3,774
0
0
Nov-Mar
0
5,000
2,955
1,650
1,120
5,000
7,045
0
0
2,000
1,880
Apr
0
5,000
3,732
3,040
0
5,000
4,878
5,000
0
0
0
May-Sep
1.992
5,000
6,550
1,236
0
0
3,314
8,008
0
0
0
DRN
179851
10034
24229
157553
11224
241390
FTS-2
Description
Oct
Nov-Mar
Columbia Layfayette
0
3,350
Gulf So St. Landry
0
0
Amoco Judge Digby
3,900
0
Trans Citronelle
0
2,500
SNG Franklinton
0
0
Destin
5,000
2,500
Apr
3,350
0
0
0
0
5,000
May-Sep
1,246
2,654
0
0
5,000
0
Apr
5,000
May-Sep
9,000
GULFSTREAM RECEIPT POINT(S)
DRN
9000126
Description
Mobile Bay/Destin
Oct
9,000
Nov-Mar
5,000
The above point(s) may be changed by mutual agreement of the parties.
14
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APPENDIX B – AMENDED AND RESTATED
PIPELINE DELIVERY POINTS
All capitalized terms not otherwise defined in this Appendix B shall have the meanings
given to such terms in the Amended and Restated Pipeline Capacity Release Agreement.
FTS-1
DRN
2984
475724
127438
2988
Description
Dania
Treasure Coast1
Lake Blue
North Miami
Oct
8,700
8,500
2,800
6,100
Nov-Mar
8,700
8,500
2,800
6,650
Apr
5,000
8,500
6,500
6,650
May-Sep
5,000
8,500
6,500
6,100
Apr
2,897
2,995
2,458
May-Sep
8,257
0
643
Apr
5,000
May-Sep
9,000
FTS-2
DRN
2988
3281
3152
Description
North Miami
Daytona
Palm Beach
Oct
8,257
0
643
Nov-Mar
2,897
2,995
2,458
GULFSTREAM DELIVERY POINT(S)
DRN
9000040
Description
So. Hillsborough
Oct
9,000
Nov-Mar
5,000
The above point(s) may be changed by mutual agreement of the parties
1
15,000 MMBtus per Day primary delivery capacity and 5,000 MMBtus per Day secondary delivery capacity. As of the date of this
Appendix B, the Treasure Coast delivery point listed above is included under PGS’s FGT Delivery Point Operator Agreement.
Customer shall have the right to remove such delivery point from PGS’s FGT Delivery Point Operator Agreement upon thirty (30)
Days’ written notice to PGS.
15
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This Amended and Restated Gas Transportation Agreement (the “Agreement”) is made
and entered into as of the 1st day of September, 2016, by and between Peoples Gas System,
a Division of Tampa Electric Company, a Florida corporation (“PGS”), and Florida Municipal
Power Agency (All-Requirements Power Supply Project), a governmental legal entity
created and existing pursuant to Florida Law (“FMPA” or “Customer”), who hereby agree as
follows:
ARTICLE I - DEFINITIONS
As used herein, the following terms shall have the meanings set forth below. Capitalized
terms used herein, but not defined below, have the meanings given for such terms in PGS’s
FPSC Tariff.
“Actual Takes” means for a specified period of time, the quantity of Gas passing through the
meter(s) at the PGS Delivery Points(s) identified in Appendix B of this Agreement.
“Adverse Order” means any amendment to any statute or rule, or any order or rule Issued by any
regulatory authority that prevents either Party from performing its obligations under this Agreement.
“Agent” means any person or entity designated as such by FMPA by written notice to PGS, who or
which will act as FMPA’s Agent for matters concerning nominations and scheduling of volumes on the
Pipelines and, if so designated, for billing related matters of all costs due under this Agreement, or any
subsequent person or entity named by FMPA in its sole discretion. As between PGS and FMPA, FMPA
shall remain responsible for all performance required of it by this Agreement notwithstanding its designation
of an Agent to perform any or all of its obligations hereunder; provided, however, that performance by
FMPA’s designated Agent of an FMPA obligation under this Agreement shall be deemed performance by
FMPA of such obligation.
“Alert Days” means “Alert Days” as defined in the respective Pipeline’s Tariff.
“Cane Island” means the electrical generating facility located in Osceola County, Florida from which
FMPA has the right to receive all electrical capacity and energy output.
“Capacity Release Agreement” means the Amended and Restated Capacity Release Agreement
dated as of even date herewith between PGS and FMPA, as the same may be amended from time to time.
“Confirmation Quantity” has the meaning given in Section 4.5.
“Contract Year” means the period of twelve (12) consecutive Months commencing on the date first
written above, and each successive period of twelve (12) consecutive Months thereafter during the term of
this Agreement.
“Daily Imbalance Amount” has the meaning given in PGS’s FPSC Tariff.
“Distribution System” means the interstate pipeline interconnections, and the pipes (mains and
service lines), valves, regulators, meters and appurtenant facilities comprising the system used by PGS to
provide Gas Service to its customers.
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1
“FGT’s FERC Tariff” means FGT’s effective FERC gas tariff applicable to firm transportation
service under the FGT Agreement(s) as such tariff may be amended from time to time.
“FMPA Facilities” means Cane Island, TCEC and Oleander.
“FPSC” means the Florida Public Service Commission or any successor agency.
gas delivered into its system, as applicable.
“GS” means Gulfstream Natural Gas System, L.L.C., its successors and assigns.
“Imbalance Level” has the meaning given in PGS’s FPSC Tariff.
“Maximum Delivery Quantity’” or “MDQ” means the maximum amount of Gas that PGS is obligated
to cause to be delivered to FMPA or its Agent pursuant to this Agreement on any Day at the PGS Delivery
Point(s), and is stated in Appendix B.
“Maximum Transportation Quantity” or “MTQ” means the maximum amount of Gas that PGS shall
be obligated to receive pursuant to this Agreement on any Day at the PGS Receipt Point(s), and is stated in
Appendix A.
“MMBtu” means one million (1,000,000) British Thermal Units or Btus.
“Month” means “Delivery Month” as defined in the respective Pipeline’s Tariff.
“Monthly Imbalance Amount” has the meaning given in Section 5.2.
“Nominate” means to deliver a completed Nomination.
“Nomination” means a notice delivered by FMPA or its Agent to PGS in the form specified in PGS’s
FPSC Tariff, specifying (in MMBtu) the quantity of Gas FMPA desires to purchase, or to have PGS receive,
transport and redeliver, at the PGS Delivery Point(s).
“Oleander” means Unit #5 of Southern Power Company’s electrical generating station located in
Brevard County, Florida which FMPA has contractual rights to dispatch under the terms of a Power
Purchase Agreement dated February 23, 2006, as amended.
“Oleander Gate” means the interconnection between FGT and the Distribution System constructed
by FGT to enable PGS to provide deliveries of Gas to Oleander with the transportation service contemplated
by this Agreement.
“Party” or “Parties”, as the context requires, means PGS and/or FMPA (or FMPA’s Agent to the extent
such Agent is responsible for the performance of Customer’s obligations hereunder).
“PGS Delivery Point(s)” means the FMPA power generating facilities identified in Appendix B.
“PGS Receipt Point(s)” means the point(s) of physical interconnection between the Pipelines, and
PGS listed in Appendix A where PGS receives Gas for the benefit of FMPA pursuant to this Agreement.
“Pipelines” means FGT and GS, collectively.
“Pipeline’s FERC Tariff” means, as applicable, either FGT’s or GS’s effective FERC gas tariff
applicable to firm transportation service, as such tariff may be amended from time to time.
“Remaining Imbalance” has the meaning given in PGS’s FPSC Tariff.
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2
“Sales Quantity” has the meaning given in Section 4.2.
“Scheduled Quantities” means, for a specified period of time, the amounts of Gas confirmed by
PGS for transportation hereunder.
“Supplier(s)” means person(s) (other than PGS) from which FMPA purchases Gas transported
hereunder.
“TCEC” means FMPA’s Treasure Coast Energy Center, an electrical generating facility located in
St. Lucie County, Florida.
“Transportation Quantity” has the meaning given for such term in Section 4.3.
“Unit Price” has the meaning given in Section 5.2.
ARTICLE II - TERM
Section 2.1 Term. This Agreement shall be binding on the date it is executed on behalf of both
of the Parties hereto. The term of this Agreement shall commence at the beginning of the Day
commencing on said date, and continue, unless earlier terminated pursuant to the provisions of
this Agreement, through the end of the Day commencing on December 31, 2033 (the “Initial
Term”). Not less than one (1) year prior to the expiration of the Initial Term (or any extended term
following the Initial Term), FMPA shall have the unilateral right to extend the term of this Agreement
for up to two (2) periods of five (5) years each by executing and tendering to PGS for execution an
amendment to this Agreement so extending its term. Subsequent to the expiration of any such
additional five-year extension of the term, the parties agree to negotiate in good faith to agree on a
mutually beneficial agreement for a subsequent term, if any, as mutually agreed. In connection
with any such further extension of the term, the agreement of neither party hereto shall be
unreasonably withheld. If an Adverse Order is issued during the term of this Agreement, this
Agreement shall terminate; provided, however, that the obligation of each party to make payment
of amounts due as of the date of such termination shall survive such termination. In addition, if the
Agreement is terminated as the result of an Adverse Order affecting PGS prior to the end of the
Initial Term, PGS shall convey title to the facilities constructed pursuant to the Construction
Agreement between Customer and PGS dated June 8, 2006 to FMPA, and FMPA shall pay to
PGS the actual cost of the facilities and meter station, less all accumulated depreciation, plus a
reasonable mark-up for expected revenue through the end of this Agreement as mutually agreed.
Section 2.2 Buyout Option. At any time after February 1, 2017, FMPA by giving PGS not less
than one (1) year’s prior written notice, shall have the option to buy-out PGS’s interest in the
Oleander Gate and/or terminate this Agreement. The purchase price to be paid to PGS by FMPA
for the Oleander Gate shall be the then net present value (calculated using an interest rate equal
to the then most recent overall allowed rate of return for retail customers approved by the FPSC at
the time notice is given by FMPA) of the sum of any remaining fixed Distribution Charges described
in Section 6.1 of this Agreement as of the date of termination which would have otherwise been
paid by FMPA to PGS absent FMPA’s exercise of the aforesaid buyout option and the termination
of this Agreement.
Section 2.3 Options to Reduce Service. At any time after April 30, 2023, if FMPA permanently
retires either: (i) TCEC, or (ii) both of Cane Island Units 3 and 4 along with termination of the
Oleander PPA, then FMPA has the option to reduce service related to the retired assets. That is, if
FMPA retires TCEC, then service to TCEC will no longer be provided under this Agreement, and
Page 80 of 223
3
the charges associated with that asset under this Agreement, including those pursuant to Section
6.1(a), shall cease. Or, if FMPA retires Cane Island Units 3 and 4, and terminates the Oleander
PPA, then service to Cane Island and Oleander will no longer be provided under this Agreement,
and the charges associated with those assets under this Agreement, including those pursuant to
Section 6.1(b), shall cease.
ARTICLE III - SALES AND TRANSPORTATION SERVICE
Section 3.1 Services. Both FMPA and its Agent, if applicable, hereby accept, and PGS hereby
agrees to provide the service to receive Gas for FMPA's or its Agent’s account, up to the MTQ,
at the PGS Receipt Point(s), and to cause an equivalent quantity to be redelivered to FMPA.
PGS also desires to sell and FMPA or its Agent desires to purchase at a negotiated price per
MMBtu from PGS, from time to time, Gas in quantities which, at FMPA’s or its Agent’s request,
PGS may, in its reasonable discretion, agree to sell Gas to FMPA or its Agent, it being
understood and agreed that PGS will not contract for Gas supply to provide the services
contemplated by this Agreement. The transportation and any such sales shall be governed by
PGS’s FPSC Tariff and this Agreement. If there is a conflict between the tariff and this
Agreement, this Agreement shall control. PGS shall have no obligation to make sales to FMPA
or its Agent in lieu of the transportation of Gas contemplated by this Agreement.
Section 3.2 PGS’s FPSC Tariff. For purposes of this Agreement, the following provisions
shall supersede those provisions of PGS’s FPSC Tariff covering the same subject matter:
(a)
Definition of “Retainage”. The definition of “Retainage” set forth in Special
Condition 1 of Rider ITS shall have no application to the service provided by PGS pursuant to
this Agreement.
(b)
Correction of Imbalances. Correction of imbalances shall be governed by
Section 5.2 of this Agreement; provided, however, that FMPA shall be entitled to book out all or
a portion of the sum of Daily Imbalance Amounts for any Month among the PGS Receipt
Point(s) in order to determine the Monthly Imbalance Amount referenced in Section 5.2.
(c)
Allocations and Penalties. If PGS gives notice to FMPA or its Agent that the Alert
Day provisions of Special Condition 12 of Rider ITS are in effect for a Day as a result of an Alert
Day called by the Pipelines (as applicable) for such Day, FMPA shall be permitted a tolerance
(based on Scheduled Quantities for such Day) equal to the greater of a) the applicable tolerance
established by the Pipelines (as applicable) for such Day for the FGT Delivery Point(s) or GS
Delivery Point(s) listed on Exhibit A or B) the posted applicable PGS alert day tolerance;
provided, however, that FMPA or its Agent shall reimburse PGS for any Alert Day Charges or
other penalties provided by the aforesaid Special Condition 12 only if charges are actually
imposed on PGS by the Pipelines (as applicable) for the FGT Delivery Point(s) or GS Delivery
Point(s) listed on Exhibit A for the Day for which such charges or penalties would otherwise be
imposed.
(d)
Curtailment and Interruption.
(1)
The Oleander Gate will be used by PGS solely for the purpose of
providing gas transportation service to Oleander, and no other customers of PGS will be
served using the Oleander Gate. Therefore, notwithstanding the provisions of PGS’s
FPSC Tariff and curtailment plan, PGS shall not interrupt or curtail deliveries to Oleander
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4
or TCEC pursuant to this Agreement with FMPA or its Agent, or for the account of either,
except when a curtailment order is issued by FGT.
(2)
In the event of a curtailment by FGT or GS, PGS shall not be required to
deliver to FMPA or its Agent more than the quantities of Gas which would otherwise be
allocated by FGT or GS to FMPA or its Agent in the absence of this Agreement.
(e)
Full Requirements. During the term hereof, all Gas used at Cane Island, TCEC
and Oleander will, at FMPA's or its Agent’s option, either be purchased from or transported by
PGS on PGS’s Distribution System, except to the extent FMPA's or its Agent’s requirements for
Cane Island, TCEC and Oleander are not delivered by PGS in accordance with this Agreement.
ARTICLE IV - NOMINATIONS
Section 4.1 General. Unless otherwise agreed, for each Day FMPA desires service
hereunder, FMPA or its Agent shall provide a Nomination to PGS pursuant to Sections 4.2
and/or 4.3 for each PGS Delivery Point. All Nominations shall be made to PGS through its web
site (www.pgsunom.com) provided that, in an emergency, a Nomination may be delivered via
facsimile using the form set forth in PGS’s FPSC Tariff. Quantities confirmed by PGS for
delivery shall be Scheduled Quantities. If requested by FMPA or its Agent, PGS will allow
increases or decreases in Scheduled Quantities after the Nomination deadlines set forth in this
article, if the same can be confirmed by PGS, the Pipeline(s) and Suppliers, and can be
accomplished without detriment to services then scheduled on such Day for PGS and other
shippers. The maximum quantity PGS shall be obligated to make available for delivery to
FMPA or its Agent on any Day (which shall not exceed the MDQ) is the sum of (a) the
Transportation Quantity and (b) the Sales Quantity established pursuant to this article.
Section 4.2 Nomination for Purchase. Unless otherwise agreed, FMPA or its Agent shall
Nominate Gas for purchase hereunder not less than two (2) Business Days prior to the first Day
of any Month in which FMPA or its Agent desires to purchase Gas. Daily notices shall be given
to PGS at least one (1) Business Day (but not less than twenty-four (24) hours) prior to the
commencement of the Day on which FMPA or its Agent desires delivery of the Gas. If FMPA or
its Agent has timely Nominated a quantity for a particular Month, PGS shall confirm to FMPA or
its Agent the quantity PGS will tender for purchase by FMPA or its Agent (the “Sales Quantity,”
which shall also be a “Scheduled Quantity”) no later than 5:00 p.m. Eastern Prevailing Time on
the Business Day immediately preceding each Day during such Month.
Section 4.3 Nomination for Transportation. Unless otherwise agreed, FMPA or its Agent
shall, for each Month, and each Day during such Month that FMPA or its Agent seeks to change
any aspect of any prior Nomination, notify PGS by providing a completed Nomination. Daily
Nominations for Gas to be made available for delivery for FMPA’s or its Agent’s account shall
be given to PGS by the deadline for nominations set forth in the General Terms and Conditions
of the Pipeline’s FERC Tariff, except that there shall be no intra-day nominations unless the
interstate pipeline capacity used for the delivery of such intra-day quantity at the PGS Receipt
Point(s) is other than that committed to FMPA by PGS concurrently with the execution of this
Agreement under the Capacity Release Agreement. PGS shall confirm to FMPA or its Agent
the quantity PGS will make available for redelivery on such Day (the “Transportation Quantity,”
which shall also be a “Scheduled Quantity”) as soon as practicable, but not later than one hour
after receiving confirmation from the Pipeline(s).
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Section 4.4 Other Responsibilities. FMPA or its Agent shall promptly notify PGS in writing of
any change in the Sales Quantity or Transportation Quantity for any Day, and PGS will use
commercially reasonable efforts to accept any such requested change as soon as practicable,
but not later than one hour. PGS shall facilitate the addition of the points listed on Appendix A
as primary delivery points under PGS’s applicable Pipeline firm transportation service
agreement, assume all responsibilities as the delivery point operator for such points under the
applicable Pipeline’s FERC Tariff, and name FMPA or its Agent as PGS’s designee under the
applicable Pipeline’s FERC Tariff for the purpose of nominating Gas for delivery to such points.
Section 4.5 Confirmation. If Transporter asks PGS to verify a nomination for FMPA or its
Agent’s account, PGS shall confirm the lesser of such nomination or the Transportation Quantity
(“the Confirmation Quantity”). As a normal course of business, PGS shall use the Confirmation
Quantity provided by Transporter as FMPA’s or its Agent’s applicable Nomination pursuant to
this Agreement. PGS has no obligation with respect to verification or rejection of quantities not
requested by FMPA or its Agent.
Section 4.6 Mutually Beneficial Transactions. FMPA and its Agent recognizes that PGS
maintains the operation and system integrity of the PGS Distribution System on a daily basis,
and that PGS, as the delivery point operator for its points of interconnection with interstate
pipelines, is subject to the rules and regulations of such pipelines with regard to operational flow
rates, pressures and penalties. As such, PGS may from time to time need FMPA or its Agent to
vary its Nominated quantities of Gas to be delivered at the PGS Receipt Point(s). On such
occasions, PGS may in its sole discretion request, and FMPA or its Agent may agree to, a
change in the quantity of Gas to be delivered for the account of FMPA or its Agent at the PGS
Receipt Point(s). No such change in the quantity of Gas to be delivered shall be made pursuant
to this section without the consent of FMPA or its Agent. Terms and conditions of any such
transaction will be agreed upon between the parties at the time of the transaction and will be
recorded and confirmed in writing within two Business Days of the transaction.
Section 4.7 PGS Diversion Option. Notwithstanding any other provision of this Agreement,
PGS shall have the right, for up to six (6) Days of each Month during the term of this
Agreement, to direct FMPA or its Agent to nominate to FGT up to the lesser of (i) fifteen percent
(15%) of FMPA’s FGT Scheduled Quantities or (ii) 20,000 MMBtu on each such Day for delivery
to a pipeline delivery point that is not listed as a PGS Receipt Point for FGT listed on Appendix
A to this Agreement. For quantities so nominated by FMPA or its Agent, PGS shall pay to
FMPA a fee of $0.10 per MMBtu. In the event FMPA or its Agent fails to so Nominate quantities
as directed by PGS, FMPA agrees to hold PGS harmless from any documented pipeline
penalties PGS incurs as a direct result of such failure. Such documentation shall be provided
by PGS to FMPA or its Agent at the time of the PGS bill, invoice, or other notification to FMPA
or its Agent for reimbursement. Any fees payable to FMPA pursuant to this section shall be
reflected as credits on PGS’s bills rendered pursuant to Section 7.1.
ARTICLE V – DELIVERIES AND IMBALANCES
Section 5.1 Deliveries of Gas. All Gas delivered hereunder shall be delivered at rates of flow
as constant as operationally feasible throughout each Day. PGS has no obligation on any Day
to deliver on other that a uniform hourly basis in relation to the Scheduled Quantities. PGS will
provide FMPA with like service to that delivered to PGS by the Pipelines (as applicable) (e.g.,
pressure and deliverability to FMPA from PGS is contingent on service delivered to PGS by the
Pipelines, as applicable.) The point of delivery for all Gas confirmed by PGS for delivery
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6
hereunder shall be at the outlet side of such billing meter(s) as shall be installed at the PGS
Delivery Point(s). Measurement of the Gas delivered shall be in accordance with PGS’s FPSC
Tariff.
Section 5.2 Correction of Imbalances. All Daily Imbalance Amounts shall be resolved as of
the end of each Month. The sum of all Daily Imbalance Amounts incurred during a Month for
the FMPA Facilities (the “Monthly Imbalance Amount”) shall be resolved as set forth below.
(a) If a Monthly Imbalance Amount is Positive (i.e., Scheduled Quantities exceed Actual
Takes):
(1)
MMBtu in the aggregate at Cane Island and Oleander), or a greater amount as to which
PGS has consented, will be carried by PGS as a credit toward Gas deliverable to FMPA
pursuant to this Agreement during the next succeeding Month, and the first Gas through
the meter(s) at the PGS Delivery Point(s) in such next succeeding Month shall be used
to eliminate or reduce the credit so carried by PGS, and
(2)
PGS shall purchase the Remaining Imbalance from FMPA (and FMPA
shall sell the same to PGS) at a price per MMBtu (the “Unit Price”) in accordance with
the cash out provisions in FGT’s FERC Tariff.
The total amount due FMPA or its Agent pursuant to this paragraph (b) shall be the
product of the Unit Price (calculated as set forth herein) and Remaining Imbalance. The
Imbalance Level shall be calculated by dividing the Remaining Imbalance by the
Scheduled Quantities for the Month in which the Monthly Imbalance Amount
accumulated.
(b) If a Monthly Imbalance Amount is Negative (i.e., Actual Takes exceed Scheduled
Quantities):
(1)
MMBtu in the aggregate at Cane Island and Oleander), or a greater amount as to
which PGS has consented, will be carried by PGS as a debit toward Gas
deliverable to FPMA or its Agent pursuant to this Agreement during the next
succeeding Month, and the first Gas scheduled through the meter(s) at the PGS
Delivery Point(s) in such next succeeding Month shall be used to eliminate the
debit so carried by PGS, and
(2)
PGS shall sell the Remaining Imbalance to FMPA or its Agent (and
FMPA or its Agent shall purchase the same from PGS) at a price per MMBtu (the
“Unit Price”) in accordance with the cash out provisions of FGT’s FERC Tariff.
The total amount due PGS pursuant to this paragraph (b) shall be the product of the Unit
Price (calculated as set forth herein) and the Remaining Imbalance. The Imbalance
Level shall be calculated by dividing the Remaining Imbalance by the Scheduled
Quantities for the Month in which the Monthly Imbalance Amount accumulated.
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(c) PGS shall, on PGS’s bill rendered to FMPA or its Agent pursuant to Section 7.1 for
the Month following the Month in which the amount payable by PGS to FMPA or its
Agent pursuant to subparagraph (a)(2) was incurred, credit to FMPA or its Agent such
amount. All amounts not so credited by PGS shall be considered delinquent, and
subject to the Late Payment Charge.
(d) Within fifteen (15) Days following the end of the Month in which the amount payable
by FMPA or its Agent to PGS pursuant to paragraph (b) was incurred, PGS shall bill
FMPA for the amount payable by FMPA or its Agent, and FMPA or its Agent shall pay
such bill in accordance with Section 7.2. All amounts not so paid by FMPA or its Agent
shall be considered delinquent and subject to the Late Payment Charge.
Section 5.3 Pipeline Operator Accounts. FMPA shall have the option, by providing
PGS written notice, to have PGS Receipt Points listed on Appendix A to this Agreement added
to the PGS Pipeline Operator Account(s). While on the PGS FGT and/or GS Operator
Account(s) (if FMPA has exercised the aforesaid option), balancing of deliveries, alert days,
operational flow orders and any penalties associated therewith shall be governed by the
provisions of PGS’s FPSC Tariff and the provisions of Sections 5.1 and 5.2 of this Agreement.
If the PGS Receipt Points have been added to the PGS Pipeline Operator Account(s) pursuant
to FMPA's written notice, FMPA shall have the right to require the removal of the PGS Receipt
Points from the PGS Pipeline Operator Account(s) by giving PGS written notice of not less than
three (3) months. At any time that the PGS Receipt Points are not on the PGS Pipeline
Operator Account(s), balancing of deliveries, alert days, operational flow orders and any
penalties associated therewith shall be governed by the Pipeline FERC Tariff(s), as applicable,
and Section 5.2 of this Agreement shall not apply.
ARTICLE VI - TRANSPORTATION AND OTHER CHARGES
Section 6.1 Distribution Charge.
(a)
For Transportation Service to TCEC. FMPA or its Agent shall pay PGS each
Month for transportation service rendered by PGS to FMPA at TCEC, and/or for Gas purchased
from PGS for use by FMPA at TCEC, in accordance with Rate Schedule CIS of PGS’s FPSC
Tariff; provided, however, that the Distribution Charge for service under Rate Schedule CIS
shall be:
(1)
For the period from the date of this Agreement through and including the
end of the Day commencing on December 31, 2016, (i) $0.0102 per Therm for up to and
including 100 million Therms per year and (ii) (a) if there are up to two natural gas fired
combined cycle or other intermediate or base load generating units at TCEC that are
intermediate or base loaded (e.g., each with a 25% capacity factor or higher over a
calendar year), $0.0020 per Therm for all quantities over 100 million Therms per year or
(b) if there are more than two combined cycle or other intermediate or base load
generating units at TCEC, $0.0030 per Therm for all quantities over 100 million Therms
per year; and provided further, however, that the minimum annual aggregate of the
Distribution Charges paid by FMPA to PGS for transportation service to TCEC shall be
$750,000. If the aggregate of the Distribution Charges paid by FMPA or its Agent to
PGS during any Contract Year for transportation service to TCEC is less than $750,000,
PGS shall invoice FMPA or its Agent and FMPA or its Agent shall pay to PGS the
amount of the shortfall in accordance with the terms set out in Section 7.2 of this
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8
Agreement.
(2)
2017, through and including December 31, 2020, (i) $0.0075 per Therm for up to and
including 100 million Therms per year and (ii) $0.002 per Therm for quantities greater
than 100 million Therms; provided that the minimum annual aggregate of the Distribution
Charges paid by FMPA to PGS for transportation service to TCEC shall be $750,000. If
the aggregate of the Distribution Charges paid by FMPA or its Agent to PGS during any
Contract Year for transportation service to TCEC is less than $750,000, PGS shall
invoice FMPA or its Agent and FMPA or its Agent shall pay to PGS the amount of the
shortfall in accordance with the terms set out in Section 7.2 of this Agreement.
(3)
(b)
For Transportation Service to Cane Island and Oleander. FMPA or its Agent
shall pay PGS each Month for transportation service rendered by PGS to Cane Island and
Oleander, and/or for Gas purchased from PGS for use by FMPA at Cane Island and Oleander,
in accordance with Rate Schedule CIS of PGS’s FPSC Tariff; provided, however, that the
Distribution Charge for service under Rate Schedule CIS shall be:
(1)
For the period from the date of this Agreement through and
including the end of the Day commencing on December 31, 2016, (i) $750,000 per year
plus (ii) $0.01000 per Therm for all quantities over 50 million Therms per Contract Year
delivered to any FMPA Delivery Point (other than TCEC) listed on PGS’s FGT Delivery
Point Operator Agreement.
(2)
2017, through and including December 31, 2020, (i) $750,000.00 per year plus (ii)
$0.0075 per Therm for all quantities over 50 million Therms per Contract Year delivered
to any FMPA Delivery Point (other than TCEC) listed on PGS’s FGT Delivery Point
Operator Agreement.
(3)
This Section 6.1 shall apply during the entire term of this Agreement whether or not the PGS
Receipt Points have been removed from the PGS Pipeline Operator Account(s).
ARTICLE VII - BILLING AND PAYMENT
Section 7.1 Billing. PGS will bill FMPA or its Agent each Month for all Actual Takes during the
preceding Month, and for any other amounts due hereunder. If, during the preceding Month,
PGS has purchased Gas from FMPA or its Agent pursuant to a curtailment order, such bill shall
show a credit for the estimated amount, based upon information provided by the Pipelines, due
FMPA or its Agent for such purchase(s). If the estimated amount owed by PGS to FMPA or its
Agent exceeds the amount FMPA or its Agent owes PGS, PGS shall pay FMPA or its Agent the
net amount estimated to be due FMPA or its Agent at the time PGS bills FMPA or its Agent.
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Section 7.2 Payment. FMPA or its Agent shall pay such bills, minus any disputed amounts, at
the address specified in the invoice by the 20th Day following the date of FMPA’s or its Agent’s
receipt of the bill. All sums not so paid by FMPA or its Agent (or credited or paid by PGS) shall
be considered delinquent.
Section 7.3 Billing Disputes. In the event of a billing dispute, FMPA, FMPA’s Agent or PGS,
as the case may be, shall pay (or credit) to the other party all amounts not in dispute, and the
parties shall negotiate in good faith to resolve the amount in dispute as soon as reasonably
practicable. If a party has withheld payment (or credit) of a disputed amount, and the dispute is
resolved, the non-prevailing party shall pay to the other party the amount determined to be due
such other party, plus interest thereon at an annual rate equal to the prime interest rate of
Citibank, N.A., New York, New York, plus one percent (1%), calculated on a daily basis from the
date due until paid (or credited).
Section 7.4 Errors or Estimates. If an estimate is used to determine the amount due FMPA
or its Agent for purchases by PGS pursuant to a curtailment order, PGS shall make any
adjustment necessary to reflect the actual amount due FMPA or its Agent on account of such
purchases in the next bill rendered to FMPA or its Agent after determination of the actual
amount due. An error in any bill, credit or payment shall be corrected in the next bill rendered
after the error is confirmed by both PGS and FMPA or its Agent.
ARTICLE VIII - FAILURE TO MAKE PAYMENT
Section 8.1 Late Payment Charge. Charges for services due and rendered which are unpaid
as of the past due date are subject to a Late Payment Charge at an annual rate equal to the
prime interest rate of Citibank, N.A., New York, New York, plus one percent (1%), calculated on
a daily basis from the date due.
Section 8.2 Other Remedies. If FMPA or its Agent fails to remedy a delinquency in any
payment within ten (10) Days after written notice thereof by PGS, PGS may, in addition to any
other remedy, without incurring any liability to FMPA or its Agent and without terminating this
Agreement, suspend further deliveries to FMPA or its Agent until the delinquent amount is paid,
but PGS shall not do so if the failure to pay is the result of a billing dispute, and all undisputed
amounts have been paid. If PGS fails to remedy a delinquency in providing a credit (or making
payment) to FMPA or its Agent for PGS purchases pursuant to an interruption or curtailment
order within ten (10) Days after FMPA or its Agent’s written notice thereof, FMPA or its Agent
may, in addition to any other remedy, without incurring liability to PGS and without terminating
this Agreement, suspend PGS’s right to retain and purchase FMPA or its Agent’s Gas pursuant
to a curtailment order, but FMPA or its Agent shall not do so if PGS’s failure to provide a credit
(or make payment) is the result of a billing dispute, and all undisputed amounts have been
credited or paid by PGS.
ARTICLE IX - MISCELLANEOUS
Section 9.1 Assignment and Transfer. Neither party may assign this Agreement without the
prior written consent of the other party (which shall not be unreasonably withheld) and the
assignee’s written assumption of the assigning party’s obligations hereunder. Upon any such
assignment and assumption, the assigning party shall furnish a copy thereof to the other party.
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Section 9.2 Governing Law. This Agreement and any dispute arising hereunder shall be
governed by and interpreted in accordance with the laws of Florida and shall be subject to all
applicable laws, rules and orders of any Federal, state or local governmental authority having
jurisdiction over the parties, their facilities or the transactions contemplated. Venue for any
action, at law or in equity, commenced by either party against the other and arising out of or in
connection with this Agreement shall be in a court having jurisdiction, located within Leon
County, Florida.
Section 9.3 Severability. If any term or provision hereof is declared by a court of competent
jurisdiction to be, or becomes under applicable law, illegal, unenforceable or invalid, such
illegality, unenforceability or invalidity shall not affect any other term or provision of this
Agreement, and this Agreement shall continue in full force and effect without said term or
provision; provided, however, that if such severability materially changes the economic benefits
of this Agreement to either party, the parties agree to negotiate in good faith to modify this
Agreement so as to effect the original intent of the parties as closely as possible in a mutually
acceptable manner (further provided, however, that the inability of the parties to agree after
good faith negotiations to a mutually acceptable modification shall not make this Agreement
voidable or terminable by a party).
Section 9.4 Entire Agreement; Appendices. This Agreement sets forth the complete
understanding of the parties as of the date first written above, and supersedes any and all prior
negotiations, agreements and understandings with respect to the subject matter hereof. The
appendices attached hereto are an integral part hereof. All capitalized terms used and not
otherwise defined in the appendices shall have the meanings given to such terms herein.
Section 9.5 Waiver. No waiver of any of the provisions hereof shall be deemed to be a waiver
Section 9.6 Notices. (a) All notices and other communications hereunder shall be in writing
confirmed with a read receipt), by facsimile (if receipt is confirmed by telephone) or by a
recognized overnight delivery service, or on the tenth (10th) day after mailing if mailed by first
class United States mail, registered or certified, return receipt requested, postage prepaid, and
properly addressed to the party as set forth below.
PGS:
FMPA:
Peoples Gas System
P. O. Box 2562
Telephone: (813) 228-4526
Facsimile: (813) 228-4643
E-mail:
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11
Orlando, FL 32819
Telephone: 407-355-7767
Facsimile: 407-355-5794
E-mail:
With a Copy To:
With a copy to:
Peoples Gas System
P. O. Box 2562
Telephone: (813) 228-1556
Facsimile: (813) 228- 228-4643
2061-2 Delta Way
Telephone: (850) 297-2011
Facsimile: (850) 297-2014
Payment:
Peoples Gas System
P. O. Box 2562
Telephone: (813) 228-4191
Facsimile: (813) 228-4643
Invoices:
Orlando, FL 32819
Telephone: 407-355-7767
Facsimile: 407-355-5795
Section 9.7 Amendments. This Agreement may not be amended except by an instrument in
writing signed by both PGS and FMPA. A change in (a) the place to which notices hereunder
must be sent or (b) the individual designated as Contact Person shall not be deemed nor
require an amendment hereof provided such change is communicated pursuant to Section 9.6.
Section 9.8 Project Agreement. This Agreement is a liability and obligation of the AllRequirements Power Supply Project only. No liability or obligation under this Agreement shall
inure to or bind any of the funds, accounts, monies, property, instruments, or rights of the
Florida Municipal Power Agency generally or any of any other "project" of FMPA as that term is
defined in the Interlocal Agreement Creating the Florida Municipal Power Agency, as may be
amended or supplemented pursuant thereto.
Section 9.9 Prior Agreements. PGS and FMPA entered into (i) that certain Gas
Transportation Agreement dated as of June 8, 2006, and (ii) that certain Gas Transportation
Agreement dated as of February 10, 2012 (the “TCEC Gas Transportation Agreement”)
(collectively, the “Prior Agreements”), and desire by this Agreement to amend, restate and
combine the provisions of said Prior Agreements in order to reimburse FMPA for PGS
overbillings between May 2008 and April 2014 under the TCEC Gas Transportation Agreement
through extensions of the terms of the Prior Agreements and of the Pipeline Capacity Release
Agreement dated as of June 1, 2008, between PGS and FMPA, and the Pipeline Capacity
Release Agreement dated as of February 10, 2012, between PGS and FMPA, and modification
of the rates set forth in the Prior Agreements, and to reflect the additional agreements of the
parties as set forth in this Agreement. This Agreement shall supersede and replace, as of the
date first written above, the Prior Agreements; provided, however, that the obligations of a party
that have accrued as of the date first written above shall survive the termination of the Prior
Agreements.
Section 9.10 Counterparts. This Agreement may be executed in one or more counterparts,
same instrument.
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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed by their respective duly authorized officers as of the date first above written.
FLORIDA MUNICIPAL POWER
AGENCY (All-Requirements
Power Supply Project)
By: ____________________________
Gordon L. Gillette
President
By:__________________________
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13
APPENDIX A – AMENDED AND RESTATED GAS TRANSPORTATION AGREEMENT
PGS RECEIPT POINT(S)
Maximum Transportation Quantity:
PGS Ft. Pierce Meter Station
FGT or PGS Meter at Oleander
FGT Meter at Cane Island:
GS Meter at Cane Island:
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APPENDIX B – AMENDED AND RESTATED GAS TRANSPORTATION AGREEMENT
PGS DELIVERY POINT(S)
Maximum Delivery Quantity*
TCEC
Up to 9,000 MMBtu per Hour @ 475 psig
Oleander
Cane Island (FGT):
Cane Island (GS):
* PGS will provide FMPA with like service to that delivered to PGS by FGT or GS, as applicable (e.g., pressure
and deliverability (including hourly tolerance) to FMPA from PGS is contingent on service delivered to PGS by
FGT or GS, as applicable)
Page 92 of 223
AGENDA ITEM 9 – ACTION ITEMS
b) Approval of ARP Contract Section 29
Withdrawal Payment Calculation Protocols
Executive Committee
August 25, 2016
Page 93 of 223
TO:
FROM:
Fred Bryant, Jody Finklea, and Frank Gaffney
DATE:
August 16,, 2016
ITEM:
EC 9b – Approval of ARP Contract Section 29 Withdrawal Payment Calculation Protocols
Strategic Relevance
• EC Strategy A2: Identify, understand and manage risk responsibly.
•
EC Strategy A3: Maintain sound financial policies and practices.
Introduction
On October 15, 2012, Vero Beach provided FMPA with notice pursuant to Section
29 of the ARP Contract to terminate its ARP Contract and withdraw from the ARP
effective September 30, 2016. While FMPA has previously provided estimates of
Section 29 withdrawal costs to various ARP Participants, including Vero Beach,
staff has developed a protocols that it is requesting that the Executive Committee
formally adopt as business practices for staff to follow in calculating Section 29
withdrawal payments. These protocols would guide the calculation of the official
Section 29 withdrawal payment for Vero Beach and future estimates of such
payments for all other ARP Participants. The proposed protocols are attached to
this memo as Attachment 1.
Discussion
Section 29 of the ARP Contract allows for a Project Participant to terminate its ARP
Contract and withdraw from the ARP with at least three years notice. In order for
the withdrawal to be effective, among other conditions, the Withdrawing Participant
must pay to FMPA on the anticipated withdrawal date a cash withdrawal payment
as set forth in Section 29(c) of the ARP Contract (the “Section 29 Withdrawal
Payment”). The intent of the Section 29 Withdrawal Payment is to protect
bondholders, credit support providers, and non-withdrawing Participants from
financial harm. There are two components to the Section 29 Withdrawal Payment,
which are summarized as follows:
•
Section 29(c)1. requires that the withdrawing Participant pay “the amount
necessary to call… a percentage of FMPA's then outstanding Bonds (other
than Bonds issued to finance additions to the System which FMPA
committed to after the receipt of the Project Participant's withdrawal notice)
equal to the greater of the Project Participant's share of the AllRequirements Power Supply Project's total electric load on the date of
receipt of the withdrawal notice or such share on the withdrawal date.”
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EC 9b – Approval of the ARP Contract Section 29 Withdrawal Payment Calculation Protocols
August 16, 2016
Page 2
•
Section 29(c)2. requires that the withdrawing Participant pay the
"additional costs reasonably paid or incurred, reasonably anticipated to be
paid or incurred, or reasonably projected to be incurred by FMPA (as
determined by FMPA in its sole discretion) as a result of the withdrawal of
the Project Participant.” Unlike Section 2 (c)1., Section 29(c)2. provides
FMPA some latitude in how to calculate the portion of the Section 29
Withdrawal Payment not related to Bonds.
While the Section 29 Withdrawal Payment is a one-time calculation and payment,
Section 29 does not include a “claw-back provision.” So, if the Section 29
Withdrawal Payment is later determined to be insufficient to pay the ARP’s actual
incurred stranded costs, FMPA cannot later recover the shortfall from the
withdrawn Participant. FMPA must “identify, understand and manage risk
responsibly” by calculating the Section 29 Withdrawal Payment using the standard
of what a reasonable utility would do to prevent under-recovery of these costs.
In order to establish a “roadmap” for the calculation of the Section 29 Withdrawal
Payment in accordance with the ARP Contract, and to provide for transparency in
that process, staff has developed a protocols document that proposes how the
Section 29 Withdrawal Payment will be calculated. Staff’s proposed protocols are
compliant with Section 29 of the ARP Contract, and they are accordant with the
Section 29 Withdrawal Payment estimates that we have provided to members since
at least 2010. As part of the development of this document, we have retained both
Baker Tilly and Nixon Peabody (as Bond Counsel) 1 to review and provide input,
and both parties have agreed to our proposed approach. The proposed protocols are
attached to this memo as Attachment 1.
FMPA is requesting that the Executive Committee adopt the proposed protocols. If
adopted, these protocols will remain open to be revised from time to time by vote
of the Executive Committee to address changed or unanticipated events or
circumstances or a truly unique or otherwise specific situation involving a
withdrawing Participant. Staff would use the protocols in the calculation of the
actual Section 29 Withdrawal Payment for Vero Beach, which we are bringing
before the Executive Committee for information in August and intend to bring for
approval in September (note that Vero Beach had been provided an estimate in June
of 2014). 2 Additionally, FMPA proposes to develop estimated Section 29
Withdrawal Payments for each Participant on a biennial basis beginning in 2016
based on these protocols and provide these estimates to the Executive Committee
as an information item.
1
Art McMahon, who was one of the drafters of the ARP Contract, provided input as part of the Nixon Peabody
review.
2
Vero Beach must pay the Section 29 Withdrawal Payment to FMPA no later than September 30, 2016, as one of the
conditions required for it to withdraw from the ARP and terminate its ARP Contract. Therefore, we must have an
approved Section 29 Withdrawal Payment prior to this date. The Section 29 Withdrawal Payment for Vero Beach that
is being presented this month for information is an estimate and remains subject to change.
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EC 9b – Approval of the ARP Contract Section 29 Withdrawal Payment Calculation Protocols
August 16, 2016
Page 3
Recommended Motion
Move approval of the proposed ARP Contract Section 29 Withdrawal Payment
Calculation Methodology attached to this memo for use by FMPA staff as
protocols for calculating estimated and actual Section 29 Withdrawal Payments
for ARP Participants.
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ATTACHMENT 1
1. Purpose
The purpose of this document is to describe how FMPA presently intends to calculate the
Withdrawal Payments commensurate with the withdrawal provisions provided for in Section 29
of the All-Requirements Power Supply Project (ARP) Contract (ARP Contract).
The “Withdrawal Payments” are as described in Section 29(c) of the ARP Contract, as quoted
below (in relevant part):
“(c) The Project Participant shall, on the anticipated withdrawal date, pay to
FMPA an amount in cash equal to:
1. the amount necessary to call (including payment of any required call
premiums and interest to the call date or dates), on the first permissible call
date or dates, a percentage of FMPA's then outstanding Bonds (other than
Bonds issued to finance additions to the System which FMPA committed to after
the receipt of the Project Participant's withdrawal notice) equal to the greater
of the Project Participant's share of the All-Requirements Power Supply Project's
total electric load on the date of receipt of the withdrawal notice or such share
on the withdrawal date. Such amount shall be calculated on the assumption that
the Bonds to be called will be the applicable percentage of each series of such
Bonds and of each maturity within each such series.[…]; and
2. an amount equal to the present value on the Withdrawal Date, calculated at
the rate of 6% per annum, of all of the additional costs reasonably paid or
incurred, reasonably anticipated to be paid or incurred, or reasonably projected
to be incurred by FMPA (as determined by FMPA in its sole discretion) as a result
of the withdrawal of the Project Participant, over the term specified in such
Project Participant's All-Requirements Power Supply Project Contract (as
determined on the anticipated withdrawal date). Such costs shall be determined
on the assumption that, during the remaining term of such Project Participant's
All-Requirements Power Supply Project Contract, FMPA was unable to make use
of or sell any generating, transmission or other resources (or portions thereof)
which FMPA had anticipated would be used to supply, or had acquired with the
intention of supplying, all or any portion of the withdrawing Project Participant's
electric load.[…]”
Since Section 29 operates for the life of the ARP Contract and attempts to deal with costs and
expenses which may change from time to time in the future or may arise at unknown future
dates, FMPA anticipates that it may determine, in its sole discretion, that it is necessary to amend
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ATTACHMENT 1
or modify this document from time to time to address changed or unanticipated events or
circumstances or a truly unique or otherwise specific situation involving an individual
withdrawing participant in order to maintain the intent of Section 29 to protect bondholders,
credit support providers, and non-withdrawing participants without unduly disadvantaging the
withdrawing participant. A complete copy of Section 29 is attached to this document as Appendix
A.
2. Introduction
FMPA currently has what has been described as one of the most lenient 1 early termination
provisions amongst Joint Action Agencies (JAAs). In this regard, most JAAs do not allow their
participants to withdraw early while there is outstanding debt or other outstanding costs. The
original ARP Contract did not provide for separate withdrawal rights. The withdrawal provisions
were later added to the ARP Contract at the request of certain cities with generation facilities
who were considering joining the ARP. The withdrawal provisions of Section 29 were negotiated
and then discussed with both the rating agencies and the bonds insurers prior to their inclusion
in the ARP Contract. In accordance with these provisions, FMPA allows its ARP participants to
withdraw from the ARP early, with at least three (3) years notice, as long as the withdrawing
participant pays up-front its pro rata share of FMPA ARP’s outstanding Bonds and other Stranded
Costs 2 that would otherwise be left with the remaining participants.
For purposes of this document, Stranded Costs are defined as: “The withdrawing participant’s
pro rata share of costs reasonably paid or incurred, reasonably anticipated to be paid or incurred,
or reasonably projected to be incurred for the ARP, assuming that FMPA is unable to make use
of or sell any resources from which FMPA had anticipated or acquired to supply the withdrawing
participant, that would otherwise be additional costs to the remaining ARP participants if not for
the Withdrawal Payments collected from the withdrawing participant.” 3
The Section 29 withdrawal provision was designed to protect the interests of the ARP’s
bondholders, the remaining ARP participants, and the withdrawing participant. This is done
through a two-step process:
1. Share of debt and other Stranded Cost payments by the withdrawing participant - The
withdrawing participant must pay (“Withdrawal Payments”) for its load ratio share of the
According to the Florida State Auditor General’s audit of FMPA conducted in 2015.
Please note that the term Stranded Costs in this document, although used in regulatory proceedings, is not
intended to have the same meaning as that term is used in various regulatory proceedings. Rather, it is meant to be
a short description for the intent for which the Withdrawal Payments are collected as described in the ARP Contract.
3
Compare with the Congressional Budget Office paper “Electric Utilities: Deregulation and Stranded Costs”, dated
October 1998, page 7: “Many researchers and state public utility commissions (PUCs) have identified separate
categories of Stranded Costs. Ultimately, costs become stranded because the price of electricity or the quantity
marketed drops ...” (emphasis added). When a participant withdraws, the quantity of electricity marketed drops,
stranding costs to the remaining participants.
1
2
Page 2 of 9
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ATTACHMENT 1
outstanding debt (Section 29(c)1) and for a pro rata share 4 of other Stranded Costs
(Section 29(c)2). The calculation methodology for determining these Withdrawal
Payments is the subject of this protocol document. It is notable that there are no clawback provisions to collect from the withdrawing participant any more funds after it has
withdrawn; as such, the contract gives FMPA discretion in determining the costs paid by
a withdrawing participant to meet the contract’s overall objectives.
Section 29(c) Withdrawal Payments are deposited into two accounts, one for debt
(“Section 29(c)1 Account”), and the other for Stranded Costs other than debt (“Section
29(c)2 Account”). FMPA staff proposes that both accounts be interest bearing 5 to help
mitigate risk of unforeseen costs that a lack of a claw-back provision would cause the
remaining participants to incur, to manage interest rate risk to remaining participants as
a result of the time delay to retire bonds, and to manage the risk associated with the 6%
discount rate required for the present value analysis of the Section 29(c)2 calculation.
Management and use of the Section 29(c)1 and Section 29(c)2 funds will be a subject for
a proposed future protocols document.
2. Benefits (Additional Benefits)6 from the stranded assets are paid to the withdrawing
participant - The contract also provides that any Additional Benefits actually received
resulting from the withdrawal of the participant are paid to the withdrawing participant,
capped at 90% of the total funds collected from the withdrawing participant and
deposited in the Section 29(c)2 Account to reflect administrative burden and
risk/uncertainty to the remaining participants due to the lack of a claw-back provision.
The methodology by which Additional Benefits will be calculated will be the subject of a
future protocols document.
3. Section 29(c)1 – Stranded Bond 7 Indebtedness Calculation Approach
Section 29(c)1: “the amount necessary to call (including payment of any
required call premiums and interest to the call date or dates), on the first
permissible call date or dates, a percentage of FMPA's then outstanding Bonds
(other than Bonds issued to finance additions to the System which FMPA
committed to after the receipt of the Project Participant's withdrawal notice)
Note that, for Stranded Costs other than Bonds (Section 29(c)2), a pro rata share of costs can be determined using
other formulas than a load ratio share.
5
Investments of the Section 29(c)1 Withdrawal Payment are limited to investments meeting the requirements for a
defeasance escrow under the ARP Bond Resolution. Investment of the Section 29(c)2 Withdrawal Payment should
be limited to very secure highly rated instruments.
6
For purposes of this document, Additional Benefits is capitalized whereas in the ARP Contract the term is not.
However, here, the term Additional Benefits is being used consistent with its description in Section 29(f) of the ARP
Contract: “an amount equal to the additional benefits actually received by FMPA during the preceding year as a
result of (the withdrawing participant’s) withdrawal.”
7
“Bonds” is a defined term in the ARP Contract which essentially means all debt (except leases).
4
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ATTACHMENT 1
equal to the greater of the Project Participant's share of the All-Requirements
Power Supply Project's total electric load on the date of receipt of the
withdrawal notice or such share on the withdrawal date. Such amount shall be
calculated on the assumption that the Bonds to be called will be the applicable
percentage of each series of such Bonds and of each maturity within each such
series.[…].”
The ARP Contract prescribes stranded Bond indebtedness as the most important component of
the types of Stranded Costs to be paid by a withdrawing participant. That is, the Stranded Costs
associated with Bonds are put into a separate account for purposes of retiring Bonds, or paying
capital costs to avoid additional debt. The underlying intent is that the Section 29(c)1 collection
will be used to retire Bonds equal to the withdrawing participant’s load ratio share as determined
on the date of receipt of notice of withdrawal, or the Withdrawal Date.
Treasury provides calculations for the Section 29(c)1 payment amount based on the pro rata
share of each series and each maturity with a series of outstanding bonds related to the
Participant. Any bonds FMPA committed to after the receipt of a Participant’s withdrawal notice
will not be included as outstanding bonds for purposes of this calculation. The Participant’s share
is based on the coincident peak of the Project (for either the Fiscal Year that includes the
Withdrawal Date 8 or the Fiscal Year within which the withdrawal notice was received whichever
produces the higher number) and the portion of that peak attributable to the Participant. This
“share” is then multiplied by each maturity of the bonds and rounded to the nearest $5,000 (the
bonds can only be redeemed in $5,000 increments). Once the principal share of the amount of
bonds is determined, then the interest on those bonds and any premium that would be required
to pay off the bonds at the first permitted early call date or maturity date can be determined.
4. Section 29(c)2 – Stranded Costs other than Bonds Calculation Approach
Section 29(c)2: “an amount equal to the present value on the Withdrawal Date,
calculated at the rate of 6% per annum, of all of the additional costs reasonably
paid or incurred, reasonably anticipated to be paid or incurred, or reasonably
projected to be incurred by FMPA (as determined by FMPA in its sole discretion)
as a result of the withdrawal of the Project Participant, over the term specified
in such Project Participant's All-Requirements Power Supply Project Contract (as
determined on the anticipated withdrawal date). Such costs shall be
determined on the assumption that, during the remaining term of such Project
Participant's All- Requirements Power Supply Project Contract, FMPA was
unable to make use of or sell any generating, transmission or other resources
(or portions thereof) which FMPA had anticipated would be used to supply, or
had acquired with the intention of supplying, all or any portion of the
withdrawing Project Participant's electric load.” (emphases added)
8
As defined in Section 29(a) of the ARP Contract.
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4.1. Present Value of Stranded Costs Other than Bonds Over the Stranded Term
For purposes of this document, “Stranded Term” means the time between the Withdrawal Date
and the date the withdrawing participant’s ARP Contract would have otherwise terminated. 9
The ARP contract specifies a 6% discount rate to determine a present value of Stranded Costs
other than Bonds, that is: “additional costs reasonably paid or incurred, reasonably anticipated
to be paid or incurred, or reasonably projected to be incurred by FMPA (as determined by FMPA
in its sole discretion) as a result of the withdrawal of the Project Participant,” over the Stranded
Term. 10
4.2. Examples of Stranded Costs other than Bonds
Generally, Stranded Costs are ARP committed costs 11 reasonably paid or incurred, reasonably
anticipated to be paid or incurred, or reasonably projected to be incurred. Since stranded Bond
indebtedness is recovered in the Section 29(c)1 Withdrawal Payment as described above, then
the stranded Section 29(c)2 costs are ARP committed costs other than Bonds, but generally not
costs that vary with generation output, such as fuel burned, for which the ARP will not be
burdened because those costs decrease with the withdrawal of the withdrawing participant.
Stranded Costs other than Bonds include, but are not limited to:
•
Operating and Maintenance (O&M) costs for generation owned by FMPA (including,
planned maintenance agreements, O&M staff, inventory, physical and cyber security,
etc.)
•
Committed cost components of power purchase agreements (PPA), such as demand rates
or minimum-take amounts. This includes the capacity component of Capacity and Energy
Sales Contracts for participant owned/entitled capacity.
•
Committed fuel costs such as firm pipeline capacity, railroad transportation reservations
for coal, fuel minimum take amounts.
•
Losses as a result of selling fuel from a must-take fuel production facility at a loss.
Section 2 of the ARP contract, as amended in January 1999, provides for the Term of the ARP Contract, which is
until at least October 1, 2030 and evergreen thereafter with automatic 1 year extensions each October 1st unless an
ARP participant provides notice to not extend before that date. This essentially provides for a 30+ year notice to
terminate. Hence, the “Stranded Term” is the time between the Withdrawal Date as defined in Section 29 and the
end of the Term as defined in Section 2.
10
Note that, to the extent the 6% discount rate exceeds the return on investment of the Section 29(c)2 Account, the
remaining participants bear the risk of the loss of time value of money in paying for actual Stranded Costs other than
Bonds from that account over the Stranded Term.
11
For purposes of this document, “committed costs” are those costs that FMPA ARP has a responsibility to pay
regardless of the withdrawal of the withdrawing participant, such as contractual requirements or non-fuel O&M
necessary to maintain an asset over its useful life.
9
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ATTACHMENT 1
•
Firm Point to Point transmission service.
•
Committed costs associated with transmission ownership, such as O&M costs of
transmission owned by FMPA or for which FMPA has the contractual obligation to
contribute (including, the Keys STATCOM and series capacitor project).
•
General and Administration (G&A) costs12 such as insurance, G&A staff, bank fees (such
as costs for letters of credit).
•
Required payments in lieu of taxes.
•
Decommissioning and other retirement costs at asset retirement. 13
•
Capital expenditures reasonably projected to be incurred, such as reasonably projected
renewal and replacement 14, and major capital additions in response to new
environmental regulations (such as the Clean Power Plan).
Staff will take care to ensure that Stranded Costs that could be categorized in more than one
category are not double-counted.
Firm Network Integration Transmission Service (NITS) costs are not included in Stranded Costs
calculations even though they are fixed costs because the withdrawing participant would no
longer be included under FMPA’s network service and FMPA is billed through FPL’s and DEF’s
transmission tariffs for NITS based on monthly peak load, which would not include the
withdrawing participant’s load; hence, costs for NITS to FMPA is reduced as a result of the
withdrawal and the costs are not stranded.
4.3. Approach to Calculating Stranded Costs Other than Bonds
4.3.1. Existing Resources at time the Withdrawing Participant Joined the ARP
For those resources that existed when the withdrawing participant joined the ARP, the pro rata
share at the Withdrawal Date, or on receipt of the application to withdraw, whichever is greater,
is used to determine Stranded Costs other than Bonds associated with those resources.
Section 29(c)1 is prescriptive as to the dates and methodology used to determine the pro rata
share. Section 29(c)2 is silent concerning what dates are used and the methodology used to
determine the pro rata share. The key phrase for existing resources in Section 29(c)2 is “which
FMPA had anticipated would be used to supply …” which is silent as to when FMPA anticipated
using existing resources. To be consistent with Section 29(c)1, the Withdrawal Date, or the date
of receipt of the withdrawal request, whichever results in a greater pro rata share, is used. The
pro rata share is determined using the load ratio share at FMPA’s coincident peak.
Baker Tilly Virchow Krause, LLP (“Baker Tilly”) recommendation.
Baker Tilly recommendation.
14
Baker Tilly recommendation.
12
13
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4.3.2. New Resources Acquired After the Withdrawing Participant Joined the ARP
For those resources that FMPA acquired after the withdrawing participant joined the ARP, the
pro rata share is determined using the load forecast depended upon to make the commitment
for the acquired resource at the time the commitment was made (for those participants who had
given their CROD notice before the commitment to acquire was made, the pro rata share would
be in proportion to the forecast of the CROD amount at the time the resource commitment had
been made), with updates to the pro rata share each time a new participant joined the ARP after
the commitment to that new resource was made. Since the last ARP Participants to join were in
2002, for practical purposes, unless and until a new participant joins the ARP, this means:
a) For those resources acquired after the withdrawing participant joined the ARP, but before
2002, use the 2002 load forecast to determine the pro rata share.
b) For those resources acquired after 2002, use the load forecast utilized to justify the
acquisition at the time of the commitment to that acquisition (e.g., date of signature of the
Engineer-Procure-Construct contract, or date of execution of a Power Purchase Agreement).
The key phrase in Section 29(c)2 for resources acquired after the withdrawing participant joined
the ARP is “which FMPA … had acquired with the intention of supplying”. This phrase provides
some guidance as to when the pro rata share is to be calculated because the language implies
that the “intention of supplying” was at the time of the acquisition of the new resource. However,
to reflect that those newly acquired resources would also be used to supply new participants
who joined after the commitment to acquire that resource was made, there is an update to the
pro rata share made to reflect the addition of the new participant(s).
4.3.3. Treatment of Capacity Ownership/Entitlement by “Generating Cities”
The pro rata share of a withdrawing participant is not reduced by the capacity and energy brought
to the ARP by a “generating city” (a participant who owned or was entitled to resources before
joining the ARP) as a result of joining the ARP (for instance, a participant’s entitlement share of a
Stanton project is not used to reduce the pro rata share of that participant). 15
5. Periodic Estimates to ARP Participants for Informational Purposes
FMPA will biennially provide Withdrawal Payment estimates to its ARP participants using the
approach described in this protocol document. In order to provide those estimates, a Withdrawal
Date will be assumed even though no withdrawal notice has been provided.
This is different from the section 3 provision of the ARP Contract addressing contract rate of delivery. A generating
city’s capacity and energy resource brought into the ARP becomes an ARP system resource through the Capacity and
Energy Sales Contract (C&E Contract). However, upon effectiveness of that generating city’s withdrawal, the C&E
Contract terminates by its own terms, eliminating all obligations of both FMPA and the generating city, one to the
other, for that resource in the future.
15
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6. Estimates and Final Determination of Withdrawal Payments for a Withdrawing Participant
The ARP Contract causes the final determination of the Withdrawal Payment to not occur until
after the September 30th peak load hour of the withdrawal year because the pro rata share for
both Section 29(c)1 and 29(c)2 can be that as of the Withdrawal Date (which is a September 30th
date), for instance:
Section 29(c)1: “the amount necessary to call … a percentage of FMPA's then
outstanding Bonds … equal to the greater of the Project Participant's share of
the All-Requirements Power Supply Project's total electric load on the date of
receipt of the withdrawal notice or such share on the withdrawal date.”
(emphasis added)
The determination of a “Withdrawal Date” and the withdrawal notice requirements are provided
in Section 29(a) and (b):
“SECTION 29. Withdrawal By Project Participant
(a) Notwithstanding Section 2 of this Contract, a Project Participant may
terminate this All-Requirements Power Supply Project Contract and withdraw
from the All-Requirements Power Supply Project only as provided in this section.
The date on which any such termination becomes effective, which must be a
September 30 date, shall be known as the "Withdrawal Date."
(b) The Project Participant shall notify FMPA and all other Project Participants
in writing of its intention to terminate this All-Requirements Power Supply
Project Contract and to withdraw from the All-Requirements Power Supply
Project at least three years prior to the Withdrawal Date ...”
As such, a final determination cannot be made until after the peak hour of September 30th
because it is feasible that a new coincident peak can be set for FMPA as late as September 30th
which could result is a higher pro rata share of committed costs allocable to the withdrawing
participant. Note that although the contract is silent as to time of day when withdrawal becomes
effective, it is clear that the intent is to align withdrawal with the Fiscal Year. Hence, withdrawal
is effective on September 30th immediately prior to midnight of October 1st (e.g., 11:59:59 PM).
However, the withdrawing participant must pay the Withdrawal Payment to be able to withdraw.
As such, FMPA will provide estimates to the withdrawing participant such that the withdrawing
participant can raise funds to pay the Withdrawal Payment based on good faith estimate(s). At
least two estimates will be provided to the withdrawing participant as follows:
•
FMPA will provide for at least one estimate during the biennial process described above
in Section 5 during the 3 years notice period required for withdrawal.
•
FMPA will provide an estimate in August immediately prior to the Withdrawal Date (see
discussion below).
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ATTACHMENT 1
•
The withdrawing participant can request an estimate at any time during the notice period.
FMPA will use reasonable best efforts to accommodate such a request.
The estimate provided in August immediately prior to the Withdrawal Date will be brought to the
Executive Committee for information at the committee’s August meeting. The calculations will
be updated in September (based on a new coincident peak if such a peak were to occur, or any
other necessary adjustments) and presented to the Executive Committee for approval at the
committee’s September meeting with the understanding that the final determination may
change if a new FMPA coincident peak occurs after the Executive Committee approval and before
October 1st. The Executive Committee delegates to FMPA staff through this Executive Committee
approved protocol document the authority to update the final determination of the Withdrawal
Payments if such a new FMPA coincident peak were to occur between the September Executive
Committee meeting and October 1st.
Revision
Date
Version 0
July 22, 2016
Version 1
August 25, 2016
Page 9 of 9
Approved By
Executive Committee
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APPENDIX A
SECTION 29. Withdrawal By Project Participant
(a) Notwithstanding Section 2 of this Contract, a Project Participant may terminate this
All-Requirements Power Supply Project Contract and withdraw from the All-Requirements Power
Supply Project only as provided in this section. The date on which any such termination becomes
effective, which must be a September 30 date, shall be known as the "Withdrawal Date."
(b) The Project Participant shall notify FMPA and all other Project Participants in writing
of its intention to terminate this All-Requirements Power Supply Project Contract and to withdraw
from the All-Requirements Power Supply Project at least three years prior to the Withdrawal Date;
provided that such notice may not be given prior to October 1, 2000. Such notice shall be deemed
given when mailed by U. S. Mail, Certified-Return Receipt Requested or sent by overnight
delivery service to FMPA and each Project Participant and shall be deemed irrevocable.
(c) The Project Participant shall, on the anticipated withdrawal date, pay to FMPA an
amount in cash equal to:
1. the amount necessary to call (including payment of any required call premiums
and interest to the call date or dates), on the first permissible call date or dates, a percentage of
FMPA's then outstanding Bonds (other than Bonds issued to finance additions to the System which
FMPA committed to after the receipt of the Project Participant's withdrawal notice) equal to the
greater of the Project Participant's share of the All-Requirements Power Supply Project's total
electric load on the date of receipt of the withdrawal notice or such share on the withdrawal date.
Such amount shall be calculated on the assumption that the Bonds to be called will be the
applicable percentage of each series of such Bonds and of each maturity within each such series.
Unless all or any portion of such cash is needed at any time to cure any deficiency in any fund or
account under the Bond Resolution, FMPA will deposit such amount in a separate account in the
General Reserve Fund (as defined in said Bond Resolution) and will retain such amount in such
account pending its application to actually redeem Bonds, to purchase Bonds in the open market,
or to pay other capital costs of the All-Requirements Power Supply Project; pending the decision
as to such application, such cash may be invested only in securities which could be deposited in
an escrow fund to defease Bonds under the Bond Resolution. FMPA must determine its use of the
cash received from the Project Participant pursuant to this clause 1 by action of its Board of
Directors taken within three months after the Withdrawal Date or it shall be conclusively presumed
that such cash shall be used to redeem or purchase Bonds; and
2. an amount equal to the present value on the Withdrawal Date, calculated at the
rate of 6% per annum, of all of the additional costs reasonably paid or incurred, reasonably
anticipated to be paid or incurred, or reasonably projected to be incurred by FMPA (as determined
1
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APPENDIX A
by FMPA in its sole discretion) as a result of the withdrawal of the Project Participant, over the
term specified in such Project Participant's All-Requirements Power Supply Project Contract (as
determined on the anticipated withdrawal date). Such costs shall be determined on the assumption
that, during the remaining term of such Project Participant's All-Requirements Power Supply
Project Contract, FMPA was unable to make use of or sell any generating, transmission or other
resources (or portions thereof) which FMPA had anticipated would be used to supply, or had
acquired with the intention of supplying, all or any portion of the withdrawing Project Participant's
electric load. Such amount shall, unless all or any portion thereof is required at any time to be
used to cure any deficiency in any fund or account under the Bond Resolution, be deposited into
and retained in a separate account in the General Reserve Fund to be applied to pay any such costs
actually incurred and/or to make any payments required to be made to such withdrawing Project
Participant described below.
If and to the extent that any amounts received by FMPA pursuant to either clause 1 or
clause 2 of this condition (c) are applied to cure any deficiency in any fund or account under the
Bond Resolution, FMPA shall be required to restore to the separate account under clause 1 or
clause 2 the amount so applied from the Revenues (as defined in the Bond Resolution) of the AllRequirements Power Supply Project, and FMPA shall treat such obligation to restore as an expense
of the All-Requirements Power Supply Project in determining Revenue Requirements. In addition,
at the end of each fiscal year of the All-Requirements Power Supply Project, FMPA may, in its
sole discretion, remove from either the separate account provided for payments received under
clause 1 of this condition (c) or the account provided for payments received under clause 2 of this
condition (c), or both, such amounts determined by FMPA to be in excess of the amounts needed
to make the payments anticipated to be made from such accounts and deposit such excess amounts
into the General Reserve Fund itself.
(d) If FMPA has Bonds outstanding which are secured by some form of credit support, any
required approvals of such credit support provider shall have been obtained within six months of
receipt by FMPA of notice of withdrawal given as provided in condition (b) of this section. If
FMPA has any Bonds outstanding which are not so secured and which are rated by a national
rating agency, the rating in effect prior to the receipt by FMPA of notice of such withdrawal shall
be confirmed by the rating agency within six months of such notice of withdrawal. FMPA shall
use its best efforts to obtain the consents or confirmations provided for in this condition (d) and
shall keep the Project Participant reasonably advised of its efforts to this end.
(e) FMPA shall receive the opinion of nationally recognized bond counsel that such
withdrawal does not adversely affect the federal and/or State of Florida tax-exempt status on any
Bonds then outstanding or which FMPA may issue in the future. If such withdrawal would require
2
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APPENDIX A
FMPA to obtain a private activity bond allocation to issue any future Bonds, such requirement
shall be treated as adversely affecting the federal and/or State of Florida tax-exempt status of
Bonds or future bonds,
(f) Within 180 days after the first anniversary of the Withdrawal Date and annually
thereafter for the remaining term of the withdrawing Project Participant's All-Requirements Power
Supply Project Contract (as such term is determined on the Withdrawal Date), FMPA will pay to
the withdrawing Project Participant an amount equal to the additional benefits actually received
by FMPA during the preceding year as a result of such withdrawal as calculated by FMPA in its
sole discretion. The net amount of payments to the withdrawing Project Participant hereunder may
not exceed 90% of the payment to FMPA by the Project Participant under condition (b). To the
extent that the amounts remaining on deposit in the separate account referred to in clause 2 of
condition (c) are, or are anticipated to be, insufficient to make any payment required by this
paragraph, the amount required to make such payment shall be treated as an expense of the AllRequirements Power Supply Project to be recovered as a Revenue Requirement.
(g) If all of the foregoing conditions have not been satisfied on the anticipated Withdrawal
Date, the Project Participant shall continue as a Project Participant in the All-Requirements Power
Supply Project. In such event, the Project Participant shall pay all costs incurred by FMPA as a
result of the Project Participant's anticipated withdrawal and subsequent continuance in the AllRequirements Power Supply Project, and FMPA shall have no obligation to make any payments
to the Project Participant under the preceding paragraph.
3
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AGENDA ITEM 10 – INFORMATION ITEMS
a) Results of Swap Advisory RFP
Executive Committee
August 25, 2016
Page 109 of 223
TO:
FMPA Board of Directors
FROM:
Edwin Nunez
DATE:
August 16, 2016
ITEM:
BOD 8a; EC 10a – Results of Swap Advisory RFP
Introduction
• Staff put together a request for proposals (RFP) for Swap Advisory services.
• The RFP was presented to the Board of Directors and the Executive Committee
for their information at their meetings on June 23, 2016.
• On June 27, 2016, the Agency sent the RFP to the current swap advisors and
seven other firms that provide this type of service.
• The Agency needs to select a provider that will offer quality service at
reasonable costs.
Background
Finding No. 10 of the Auditor General operational audit was that the Agency had
not recently used a competitive selection process to select bond professionals. As
quoted from the Operational Audit:
“The GFOA recommends that issuers selecting financial advisers, underwriters, and
bond counsel employ a competitive process using a Request for Proposal (RFP) or
Request for Qualifications (RFQ). A competitive process allows the issuer to
compare the qualifications of proposers and to select the most qualified firm based
on the scope of services and evaluation criteria outlined in the RFP or RFQ. A
competitive process also provides objective assurance that the best services and
interest rates are obtained at the lowest cost possible and demonstrates that
marketing and procurement decisions are free of self-interest and personal or
political influences. Furthermore, a competitive process reduces the opportunity
for fraud and abuse and is fair to competing professionals. The GFOA’s best
practice further recommends that debt issuers review their relationships with bond
professionals periodically.”
The last time FMPA competitively selected a firm for swap advisory services was
in 2009. Swap Financial Group, LLC is the current provider of the Agency’s swap
advisory services and has been since 2009. Swap Financial Group, LLC’s contract
with the Agency expires on October 1, 2016.
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BOD 8a – EC 10a – Results of Swap Advisory RFP
August 16, 2016
Page 2
Analysis
We received complete responses from the following firms:
Cityview Capital Solutions, LLC
PFM Asset Management, LLC
HilltopSecurities, Inc.
Swap Financial Group, LLC
Each proposal was compared in the following areas: pricing, staff experience,
analytical tools and systems used by each of the responding firms.
___________________________________________________________________
Documents
Some of the proposals include information, including pricing terms, that the
proposing firms have deemed to be their confidential proprietary business
information. Therefore, to enable FMPA’s Board of Directors and Executive
Committee members to view this information staff has established a separate FTP
site, to which the following documents have been uploaded:
Copies of each of the 4 proposals; and
A grid showing a pricing comparison among the proposers.
Directions on how to access the FTP site will be sent to the Board of Directors and
the Executive Committee under separate cover.
The Finance Team will have a recommendation for the top three ranked proposals
in September when presented for action.
Recommended
Action
For information only. No action required.
Page 111 of 223
b) Wells Fargo Credit Agreement for Line of
Credit
Executive Committee
August 25, 2016
Page 112 of 223
TO:
FROM:
Mark Larson
DATE:
August 16, 2016
ITEM:
EC10b – Wells Fargo Credit Agreement for a Line of Credit
Strategic Relevance
As a wholesale power provider, become and remain competitive in the Florida
market.
Background
The All-Requirements Project currently has a $100 million line of credit with
JPMorgan, approved via Resolution 2016-EC2 at the May 19, 2016 meeting of the
Executive Committee (EC). In the staff memo that supported this action, agenda
item EC 9b, staff noted that efforts were ongoing to obtain interest from a second
bank to provide some portion of the total Line of Credit of $100 million. Wells
Fargo has stepped up since then and is working with staff on a $25 million Line of
Credit, which if approved by the EC would be coupled with a $25 million reduction
in the Credit Agreement with JPMorgan.
The Wells Fargo Credit Agreement (Agreement) is in substantial form, closely
following the current one executed with JPMorgan. There are a few remaining
points to work out the wording on, all of which we believe will be settled in time to
present this item back to the EC for action in September. This discussion is at
“Comparability” below.
The effort of having two banks involved in providing Lines of Credit is in support
of maintaining the All-Requirement Project’s credit rating which has the effect of
helping to maintain cost competitiveness. The Finance Team is in full support of
this objective.
Comparability
The current language of the draft Agreement with Wells Fargo differs from the
current JPMorgan Credit Agreement but on the whole, the differences do not alter
the overall substantive comparability of the documents.
Page 113 of 223
EC 10b – Wells Fargo Credit Agreement for a Line of Credit
August 16, 2016
Page 2
1. Language on the pass-through nature of certain costs, taxes and fees is being
reviewed. FMPA seeks to reduce its future exposure to increases in these.
2. FMPA seeks agreement between the banks and itself on how the new credit
agreement with Wells Fargo could be adopted by JPMorgan (pursuant to
applicable, so-called “Most Favored Nations” clauses); and vice-versa. Before
staff and the Finance Team recommends a Wells Fargo Agreement to the EC, we
will know how such acceptance will impact the current JPMorgan credit agreement
language.
3. Language in the sections on Letters of Credit are different as are the costs
associated with usage, with both versions acceptable to FMPA. We don’t currently
use Letters of Credit, nor currently see a need to use them.
Based on the terms in the current JPMorgan Credit Agreement, JPMorgan may
elect to revise certain of its existing terms to be consistent with the Wells
Agreement. Also being considered is the potential for Wells Fargo to take from the
JPMorgan Credit Agreement if it considers the language more favorable.
ARP Cost
Both the undrawn use fee and borrowed interest rates, at the ARP’s current credit
ratings, under the proposed Wells Agreement, are lower than they were under
Wells Fargo’s prior Credit Agreement with FMPA. At the ARP’s current credit
ratings, the undrawn use fee and borrowed interest rates for taxable borrowings will
also be lower than those of the current JPMorgan Credit Agreement. Borrowed
interest rates on tax-exempt borrowings would be higher under the Wells
Agreement. It is expected that the total cost of the combined $100 million in Lines
of Credit will be approximately $25,000 less annually than having the entirety of
the Line with just JPMorgan. Like in the JPMorgan Credit Agreement and as one
would expect, rates and fees increase in the Wells Agreement as the credit rating of
the ARP declines.
EC Next Step
Staff, with the recommendation of the Finance Team, will present the Wells Fargo
Agreement for approval at the EC’s September meeting. This will include an
updated EC Resolution authorizing the action.
Recommended
Action
No action at this time. For information only.
___________________________________________________________________
Page 114 of 223
c) ARP Contract Section 29 Withdrawal Payment
Estimates for All ARP Participants
Executive Committee
August 25, 2016
Page 115 of 223
TO:
FROM:
Fred Bryant, Jody Finklea, and Frank Gaffney
DATE:
August 16, 2016
ITEM:
EC 10c - ARP Contract Section 29 Withdrawal Payment Estimates for All ARP Participants
Strategic Relevance
Introduction
•
EC Strategy A2: Identify, understand and manage risk responsibly.
•
EC Strategy A3: Maintain sound financial policies and practices.
While staff has historically provided estimates of Section 29 withdrawal costs to
any Participant that has requested it, FMPA has also committed to provide to each
ARP Participant an estimate of its Section 29 withdrawal costs at least biennially.
This memorandum provides the first biennial estimates to all ARP Participants.
Additionally, in October 2012, the City of Vero Beach issued its notice pursuant to
Section 29 of the ARP Contract of its intent to withdraw from the ARP effective
September 30, 2016. This memorandum also provides an estimate of Vero Beach’s
Withdrawal Payment for information. The Executive Committee will be asked to
approve a substantially final estimate at the September EC meeting.
Discussion
Among other conditions required for a Participant to withdraw, Section 29 (c) of the
ARP Contract specifies that the Participant must pay to FMPA on the withdrawal
date an amount in cash equal to:
1. the amount necessary to call (including payment of any required
call premiums and interest to the call date or dates), on the first
permissible call date or dates, a percentage of FMPA's then
outstanding Bonds (other than Bonds issued to finance additions to
the System which FMPA committed to after the receipt of the
Project Participant's withdrawal notice) equal to the greater of the
Project Participant's share of the All-Requirements Power Supply
Project's total electric load on the date of receipt of the withdrawal
notice or such share on the withdrawal date. Such amount shall be
calculated on the assumption that the Bonds to be called will be the
applicable percentage of each series of such Bonds and of each
maturity within each such series; and
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August 16, 2016
Page 2
2. an amount equal to the present value on the Withdrawal Date,
calculated at the rate of 6% per annum, of all of the additional costs
reasonably paid or incurred, reasonably anticipated to be paid or
incurred, or reasonably projected to be incurred by FMPA (as
determined by FMPA in its sole discretion) as a result of the
withdrawal of the Project Participant, over the term specified in
such Project Participant's All-Requirements Power Supply Project
Contract (as determined on the anticipated withdrawal date). Such
costs shall be determined on the assumption that, during the
remaining term of such Project Participant's All-Requirements
Power Supply Project Contract, FMPA was unable to make use of
or sell any generating, transmission or other resources (or portions
thereof) which FMPA had anticipated would be used to supply, or
had acquired with the intention of supplying, all or any portion of
the withdrawing Project Participant's electric load.”
Attached to this memorandum as Attachment 1 are the current estimated Section 29
withdrawal costs for all ARP Participants, which have also been summarized in the
following table:
Estimated Section 29 Withdrawal Costs by Participant
as of August 2016
ARP Participant
Estimated Section
29(c)1. Withdrawal
Payment [2] [3] [4]
Assumed Section 29
Withdrawal Date [1]
Estimated Section
29(c)2. Withdrawal
Payment [2] [3]
Total Estimated
Section 29 Withdrawal
Payment [2] [3]
Bushnell
9/30/2019
$
4,849,242
$
9,844,261
$
14,693,503
Clewiston
9/30/2019
$
16,449,619
$
35,985,574
$
52,435,193
Fort Meade
9/30/2019
$
7,760,135
$
13,502,124
$
21,262,259
Fort Pierce
9/30/2019
$
76,138,802
$
176,869,932
$
253,008,734
Green Cove Springs
9/30/2019
$
18,284,547
$
35,209,075
$
53,493,622
Havana
9/30/2019
$
4,055,413
$
9,684,126
$
13,739,539
Jacksonville Beach
9/30/2019
$
121,962,501
$
310,506,115
$
432,468,616
Key West
9/30/2019
$
109,600,887
$
223,446,066
$
333,046,953
271,577,739
KUA
9/30/2019
$
Lake Worth
9/30/2019
$
$
604,091,445
$
875,669,184
$
39,215,680
$
39,215,680
Leesburg
9/30/2019
$
87,403,628
$
184,977,511
$
272,381,138
Newberry
9/30/2019
$
6,598,515
$
15,186,336
$
21,784,851
Ocala
9/30/2019
$
241,474,160
$
554,032,778
$
795,506,938
Starke
9/30/2019
$
11,614,546
$
17,440,914
$
29,055,460
Vero Beach
9/30/2016
$
$
33,411,871
$
33,411,871
0 [5]
0 [6]
[1] The withdrawal date for Vero Beach of September 30, 2016, is fixed pursuant to the City’s October
2012 notice. For all other Participants, the September 30, 2019, date shown represents the earliest
possible withdrawal date for each Participant assuming it gives notice of its Section 29 withdrawal
on or before September 30, 2016.
Page 117 of 223
August 16, 2016
Page 3
[2] Amounts shown are estimates and are subject to change. Amounts shown also do not include any
additional contractually obligated payments specific to individual Participants (for instance,
pursuant to the TARP agreement, Key West would be required to purchase from FMPA the
generating units and all associated and other facilities and equipment owned by FMPA and
physically located within Key West’s system if it undertook a Section 29 withdrawal).
[3] Because the estimated withdrawal cost for each Participant was developed using the assumption
that it is the only Participant to withdraw, the amounts shown in each column cannot be summed
to represent total Stranded Costs for the ARP. (see infra discussion of the Bushnell example on
pages 3-4)
[4] Amounts shown were developed based on the principal amount of Bonds (as defined in the ARP
Contract) projected to be outstanding after October 1, 2019.
[5] Based on the methodology specified in Section 29(c)1. of the ARP Contract, and because Lake
Worth established a Contract Rate of Delivery of 0 MW effective January 1, 2014, the Section
29(c)1. Withdrawal Payment for Lake Worth would be $0, as Lake Worth's share of the AllRequirements Power Supply Project's total electric load on the assumed date of receipt of its
withdrawal notice (on or before September 30, 2016) and its share on the assumed withdrawal date
(September 30, 2019) would both be 0%.
[6] Based on the methodology specified in Section 29(c)1. of the ARP Contract, and because Vero
Beach established a Contract Rate of Delivery of 0 MW effective January 1, 2010, the Section
29(c)1. Withdrawal Payment for Vero Beach will be $0, as Vero Beach's share of the AllRequirements Power Supply Project's total electric load on the date of receipt of its withdrawal
notice (October 18, 2012) and its share on the withdrawal date (September 30, 2016) are both 0%.
Staff developed these estimates in accordance with the proposed protocols that were
provided to the Executive Committee as information in July and are being brought
for approval this month. With the exception of Vero Beach, which has a fixed
withdrawal date of September 30, 2016, each Participant’s estimate was developed
assuming that it would give its Section 29 withdrawal notice no later than September
30, 2016, which would result in a withdrawal date of September 30, 2019. For those
Participants that have also previously given their notice pursuant to Section 2 of the
ARP Contract to stop the automatic annual extension of their ARP Contract,
Stranded Costs 1 were computed through their established ARP Contract termination
date 2; otherwise, Stranded Costs were computed through September 30, 2050.
Further, each Participant’s estimate was developed using the assumption that it is
the only Participant to withdraw. Because of this, each Participant’s estimate should
be viewed as being mutually exclusive; in other words, summing the columns in the
table will not produce a meaningful estimate of withdrawal costs if multiple
Participants withdrew. For example, Bushnell’s estimate includes an allocation of
Stranded Costs associated with Starke’s Power Entitlement Shares in the Stanton
and Stanton II Projects, which entitlements have been assigned to the ARP.
However, if Starke also withdrew at the same time, Starke would take its Stanton
1
For purposes of these calculations, Stranded Costs are defined as the withdrawing participant’s pro rata share of “costs
reasonably paid or incurred, reasonably anticipated to be paid or incurred, or reasonably projected to be incurred for the
ARP, assuming that FMPA is unable to make use of or sell any resources from which FMPA had anticipated or
acquired to supply the withdrawing participant, that would otherwise be additional costs to the remaining ARP
participants if not for the Withdrawal Payments collected from the withdrawing participant.” For such purposes, this
term is not intended to have the same meaning as would be used in regulatory proceedings.
2
The cities of Starke, Green Cove Springs, Fort Meade, and Vero Beach have each given their Section 2 notice; their
ARP Contracts will terminate effective September 30 of 2035, 2037, 2041, and 2046, respectively.
Page 118 of 223
August 16, 2016
Page 4
and Stanton II entitlements with it upon its withdrawal, so those costs would not be
included in the Stranded Cost calculation for Bushnell.
Finally, the estimates do not include any additional Participant-specific costs that
would also need to be paid by the withdrawing Participant on the withdrawal date.
For example, pursuant to the TARP agreement between FMPA and Key West, Key
West would be required to purchase from FMPA the Stock Island generating units
and all associated and other facilities and equipment owned by FMPA and
physically located within Key West’s system at Net Salvage Value (as defined in
the TARP agreement) in the event that it undertook a Section 29 withdrawal. An
estimate of such purchase price is not reflected in the estimate for Key West.
However, any such Participant-specific costs would be included in the actual
calculation of Section 29 withdrawal costs for that Participant.
It is important to recognize that these estimates are only that – estimates – and were
developed based on information that was known and assumptions of future
conditions that staff believed to be reasonable at the time the estimates were
developed. As the underlying information and assumptions change in the future, or
to the extent the proposed protocols are revised, the estimated withdrawal costs will
also change.
For all ARP Participants, these estimates have been developed and are being
provided for informational purposes only.
Vero Beach Estimate
As shown in the table and Attachment 1, staff’s current estimate of the Section 29
withdrawal payment that Vero Beach will be required to make on September 30,
2016, in order for its Section 29 withdrawal from the ARP to be effective is
$33,411,871. Staff plans to bring the substantially final estimate of Withdrawal
Payments for Vero Beach for approval at the September 2016 Executive Committee
meeting. However, because the estimate cannot be finalized until September 30,
2016 (e.g., the ARP could set a new coincident peak demand that would need to be
considered in the calculation), staff also intends to ask the Executive Committee for
authority to adjust the Vero Beach substantially final estimate, in accordance with
the protocols if approved by the EC, between the date of the September Executive
Committee meeting and September 30, 2016, if it becomes necessary.
Recommended Motion
For information only. No action requested.
Page 119 of 223
ATTACHMENT 1 SECTION 29(C) WITHDRAWAL PAYMENT ESTIMATES BY PARTICIPANT Page 120 of 223
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE CITY OF BUSHNELL AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 121 of 223
All-Requirements Estimated Bushnell Section 29(c)(1) Withdrawal Payment
Calculation Date:
9/30/2016
Exit notice on or before 9/30/2016
Using Section 29 Withdrawal
Effective Date of Withdrawal:
9/30/2019
Bushnell Pro-Rata Share of Debt Section 29(c)(1): a percentage of FMPA's then outstanding Bonds
(other than Bonds issued to finance additions to the System which FMPA committed to after the receipt of the Project
Participant's withdrawal notice) equal to the greater of the Project Participant's share of the the All-Requirements Power
Supply Project's total electric load on the date of receipt of the withdrawal notice or such share on the withdrawal date.
Bushnell Pro-Rata Share of Bonds:
coincident peak for Bushnell
5.601 (as of June 2015)
St. Lucie excluded resources
0.000
5.601
coincident peak for All-Requirments Project less excl. resources:
Bushnell share:
1,158.877 (as of June 2015)
0.483%
as of 9/30/2019
to be determined
Bonds Outstanding:
Bond Maturity
Bonds
Outstanding Coupon Rate
Bond Payment or
Pro-Rata Share Redemption Date
Bond Principal
Liability
Bond Interest
Liability
Series 2008A Bonds maturing on or after 10/1/2020 are subject to optional redemption at par on or after 10/1/18
10/1/2020
5,765,000
5.250%
27,862.98
11/1/2019
30,000
131
10/1/2021
6,045,000
5.250%
29,216.25
11/1/2019
30,000
131
10/1/2022
3,580,000
5.250%
17,302.60
11/1/2019
20,000
88
10/1/2023
3,770,000
5.250%
18,220.89
11/1/2019
20,000
88
10/1/2024
3,005,000
945,000
4.750%
5.250%
14,523.55
4,567.31
11/1/2019
11/2/2019
15,000
5,000
59
22
10/1/2026
2,195,000
630,000
4.750%
5.000%
10,608.71
3,044.87
11/1/2019
11/2/2019
15,000
5,000
59
21
10/1/2027
3,580,000
5.000%
17,302.60
11/1/2019
20,000
83
10/1/2028
6,730,000
5.000%
32,526.95
11/1/2019
35,000
146
10/1/2029
370,000
6,135,000
5.250%
5.000%
1,788.26
29,651.24
11/1/2019
11/2/2019
5,000
30,000
22
125
10/1/2030
395,000
6,535,000
5.250%
5.000%
1,909.09
31,584.49
11/1/2019
11/2/2019
5,000
35,000
22
146
10/1/2031
545,000
8,930,000
5.250%
5.000%
2,634.05
43,159.83
11/1/2019
11/2/2019
5,000
45,000
22
188
705,989.40
11/1/2019
710,000
2,367
59,155,000
Series 2008C (VRDO's) callable daily
10/01/35
146,073,000 daily variable
Series 2011A-1 Private Placement
Page 122 of 223
1
10/01/30
28,000,000 Variable Rate
135,327.56
11/1/2019
140,000
529
2
202,991.34
11/1/2019
205,000
1,051
2
202,991.34
11/1/2019
205,000
769
2
35,000
58
10/01/25
42,000,000 Taxable Variable Rate
Series 2011B Private Placement
10/01/30
Series 2013A bonds maturing on 10/1/23 are subject to optional and mandatory redemption prior to maturity
10/1/2023
6,615,000
2.000%
31,971.14
11/1/2019
Series 2015B bonds maturing after 10/1/25 are subject to optional redemption on 10/1/25 prior to maturity
10/1/2020
1,000,000
5,235,000
4.000%
5.000%
4,833.13
25,301.42
10/1/2020
10/1/2020
5,000
30,000
200
1,500
10/1/2021
6,535,000
5.000%
31,584.49
10/1/2021
35,000
3,500
10/1/2022
6,865,000
5.000%
33,179.42
10/1/2022
35,000
5,250
10/1/2023
7,205,000
5.000%
34,822.68
10/1/2023
35,000
7,000
10/1/2024
7,565,000
5.000%
36,562.61
10/1/2024
40,000
10,000
10/1/2025
1,250,000
3.000%
6,041.41
10/1/2025
10,000
1,800
6,695,000
5.000%
32,357.79
10/1/2025
35,000
10,500
10/1/2026
8,315,000
5.000%
40,187.45
10/1/2025
45,000
13,500
10/1/2027
1,735,000
3.250%
8,385.48
10/1/2025
10,000
1,950
7,000,000
5.000%
33,831.89
10/1/2025
35,000
10,500
10/1/2028
9,140,000
5.000%
44,174.78
10/1/2025
45,000
13,500
10/1/2029
9,595,000
5.000%
46,373.86
10/1/2025
50,000
15,000
10/1/2030
10,075,000
5.000%
48,693.76
10/1/2025
50,000
15,000
10/1/2031
10,580,000
5.000%
51,134.49
10/1/2025
55,000
16,500
98,790,000
Series 2016A bonds maturing after 10/1/25 are subject to optional redemption on 10/1/25 prior to maturity
10/1/2020
38,415,000
5.00%
185,664.58
10/1/2025
190,000
9,500
10/1/2021
40,330,000
5.00%
194,920.02
10/1/2025
195,000
19,500
10/1/2022
26,720,000
5.00%
129,141.16
10/1/2025
130,000
19,500
10/1/2023
27,975,000
5.00%
135,206.73
10/1/2025
140,000
28,000
10/1/2024
29,355,000
5.00%
141,876.45
10/1/2025
145,000
36,250
10/1/2026
4,500,000
4.00%
21,749.07
10/1/2025
25,000
6,000
18,375,000
5.00%
88,808.71
10/1/2025
90,000
27,000
10/1/2027
27,260,000
5.00%
131,751.05
10/1/2025
135,000
40,500
10/1/2028
45,110,000
5.00%
218,022.37
10/1/2025
220,000
66,000
Page 123 of 223
10/1/2029
48,475,000
5.00%
234,285.84
10/1/2025
235,000
70,500
10/1/2030
51,345,000
5.00%
248,156.92
10/1/2025
250,000
75,000
10/1/2031
20,000,000
3.00%
96,662.54
10/1/2025
100,000
18,000
46,260,000
5.00%
223,580.47
10/1/2025
225,000
67,500
424,120,000
Total Bonds Outstanding
846,753,000
ARP Line of Credit
$100 MM
5,000,000.00
24,165.64
4,210,000
Estimated Payment Calculation for the City of Bushnell:
Principal portion of all bonds and line of credit
Estimated interest on all bonds through maturity or call dates
4,234,166
615,076
4,849,242
1 - This amount is estimated at 4% interest
2 - Bonds will be called as soon as practicable, interest collected to call dates. Interest calculated at estimated rates
3 - This amount can not be estimated in advance, it is based on what is drawn on the line at the time of exit.
Page 124 of 223
3
?
615,076
Estimated Bushnell
Section 29(c)2. Withdrawal Payment
for September 30, 2019:
Withdrawal Year
Contract End Year
Present Worth Base Year
General Escalation Rate
Discount Rate
Calculated 8/12/2016
ARP Termination Pmt Calcs 081216.xlsx
Page 1
$9,844,261
2019
2050
2019
2.25%
6.00%
All-Requirements Power Supply Project
Projected Costs
Allocated
Costs
(2019 $000)
2020
2021
Projected Annual Costs (Nominal Dollars - $000, Unallocated)
Fiscal Year Ending September 30,
2022
2023
2024
2025
2026
2027
2028
Operation & Maintenance Costs
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 1 [1] [2]
Cane Island 4 [2]
Indian River CTs [1]
Stock Island CT 1-4, MSD 1-2, EP2, Common
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
339
149
211
51
137
558
517
101
229
414
19
2,725
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
Capital Additions Costs
1,036
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
16,415
16,784
17,162
-
-
-
-
-
-
-
-
-
-
-
1,378
22,251
23,783
24,133
34,250
24,928
25,307
24,816
19,600
16,384
16,994
17,589
Fixed Purchased Power Costs
Stanton A - CC PPA
Southern Oleander
Sub Total Fixed Purchased Power Costs
103
208
312
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
TARP Capacity Credits & Other Obligations
947
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
Fixed Gas Transportation Costs
1,485
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
25,886
26,073
26,626
Direct Charges & Other
1,596
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
331
4,500
4,599
4,700
4,803
4,029
4,118
4,208
4,300
4,544
4,644
5,650
Decommissioning Costs
Member Capacity Costs (Stanton Unit 1 & 2 C&E)
Firm Transmission Costs
Totals
ARP Total Fixed Costs (Nominal Dollars - $000)
ARP Total Fixed Costs (2019 Dollars - $000)
Bushnell Costs (2019 Dollars - $000)
35
Grand Total
5,253,778
2,361,148
9,844
2020
164,147
154,856
642
2021
168,410
149,884
622
2022
167,905
140,976
585
2023
222,078
175,907
727
[1] Includes KUA's ownership share.
[2] Includes allocated share of projected Common Facilities costs.
Page 125 of 223
2024
162,433
121,379
508
2025
165,228
116,479
488
2026
167,132
111,152
465
2027
164,442
103,173
431
2028
153,829
91,051
382
2029
2030
2029
153,531
85,731
360
2030
157,696
83,072
349
Estimated Bushnell
Withdrawal Year
Contract End Year
Discount Rate
$9,844,261
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2031
2032
2033
2034
2035
2036
2037
2038
2039
339
149
211
51
137
558
517
101
229
414
19
2,725
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
1,036
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
18,773
19,196
19,628
-
-
-
-
-
4,931
-
-
-
-
-
17,940
18,521
18,920
19,689
19,647
19,553
19,993
20,443
20,903
21,373
21,854
Page 2
35
1,378
2040
2041
Stanton A - CC PPA
Southern Oleander
103
208
312
-
-
-
-
-
-
-
-
-
-
-
947
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
1,485
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
1,596
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
331
5,775
5,902
6,132
6,268
6,406
6,458
6,743
6,892
7,045
7,201
7,360
Totals
Grand Total
5,253,778
2,361,148
9,844
2031
160,792
79,909
335
2032
164,180
76,974
323
2033
167,550
74,107
311
2034
171,256
71,459
300
Page 126 of 223
2035
170,808
67,238
282
2036
171,390
63,648
266
2037
170,019
59,565
249
2038
173,519
57,350
240
2039
177,097
55,220
231
2040
180,755
53,170
222
2041
184,496
51,199
214
Estimated Bushnell
Withdrawal Year
Contract End Year
Discount Rate
$9,844,261
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2042
2043
2044
2045
2046
2047
2048
339
149
211
51
137
558
517
101
229
414
19
2,725
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
8,212
3,701
5,094
1,908
20,832
2,483
5,664
7,152
452
55,498
8,397
3,784
5,209
1,951
21,301
2,539
5,792
463
49,434
8,586
3,869
5,326
1,994
21,780
2,596
5,922
473
50,547
1,036
16,720
15,920
16,278
16,645
17,019
17,402
15,700
12,951
13,242
35
9,696
-
-
-
-
-
-
24,247
-
1,378
22,346
22,849
23,363
23,888
24,426
24,976
25,537
26,112
26,700
-
-
-
-
-
-
-
-
Page 3
2049
2050
Stanton A - CC PPA
Southern Oleander
103
208
312
-
947
3,941
871
871
871
871
871
871
871
871
1,485
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
1,596
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
331
7,523
7,690
7,861
8,035
8,213
8,396
8,582
8,773
8,968
Totals
Grand Total
5,253,778
2,361,148
9,844
2042
174,366
45,648
189
2043
160,017
39,521
163
2044
163,561
38,109
157
Page 127 of 223
2045
167,185
36,749
151
2046
170,891
35,437
146
2047
174,680
34,173
141
2048
167,416
30,898
128
2049
178,888
31,146
128
2050
158,081
25,966
109
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE CITY OF CLEWISTON AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 128 of 223
All-Requirements Estimated Clewiston Section 29(c)(1) Withdrawal Payment
Calculation Date:
9/30/2016
9/30/2019
Clewiston Pro-Rata Share of Debt Section 29(c)(1): a percentage of FMPA's then outstanding Bonds
Clewiston Pro-Rata Share of Bonds:
coincident peak for Clewiston
21.263 (as of June 2015)
1.908
19.355
Clewiston share:
1,158.877 (as of June 2015)
1.670%
as of 9/30/2019
to be determined
Bonds Outstanding:
Bond Maturity
Bonds
Bond Payment or
Bond Principal
Liability
Bond Interest
Liability
10/1/2020
5,765,000
5.250%
96,284.23
11/1/2019
100,000
438
10/1/2021
6,045,000
5.250%
100,960.65
11/1/2019
105,000
459
10/1/2022
3,580,000
5.250%
59,791.42
11/1/2019
60,000
263
10/1/2023
3,770,000
5.250%
62,964.71
11/1/2019
65,000
284
10/1/2024
3,005,000
945,000
4.750%
5.250%
50,188.05
15,782.93
11/1/2019
11/2/2019
55,000
20,000
218
88
10/1/2026
2,195,000
630,000
4.750%
5.000%
36,659.82
10,521.95
11/1/2019
11/2/2019
40,000
15,000
158
63
10/1/2027
3,580,000
5.000%
59,791.42
11/1/2019
60,000
250
10/1/2028
6,730,000
5.000%
112,401.19
11/1/2019
115,000
479
10/1/2029
370,000
6,135,000
5.250%
5.000%
6,179.56
102,463.79
11/1/2019
11/2/2019
10,000
105,000
44
438
10/1/2030
395,000
6,535,000
5.250%
5.000%
6,597.10
109,144.39
11/1/2019
11/2/2019
10,000
110,000
44
458
10/1/2031
545,000
8,930,000
5.250%
5.000%
9,102.32
149,144.52
11/1/2019
11/2/2019
10,000
150,000
44
625
2,439,640.20
11/1/2019
2,440,000
8,133
59,155,000
10/01/35
Page 129 of 223
1
10/01/30
467,642.38
11/1/2019
470,000
1,775
2
701,463.57
11/1/2019
705,000
3,616
2
701,463.57
11/1/2019
705,000
2,645
2
115,000
192
10/01/25
10/01/30
10/1/2023
6,615,000
2.000%
110,480.51
11/1/2019
10/1/2020
1,000,000
5,235,000
4.000%
5.000%
16,701.51
87,432.42
10/1/2020
10/1/2020
20,000
90,000
800
4,500
10/1/2021
6,535,000
5.000%
109,144.39
10/1/2021
110,000
11,000
10/1/2022
6,865,000
5.000%
114,655.89
10/1/2022
115,000
17,250
10/1/2023
7,205,000
5.000%
120,334.41
10/1/2023
125,000
25,000
10/1/2024
7,565,000
5.000%
126,346.95
10/1/2024
130,000
32,500
10/1/2025
1,250,000
3.000%
20,876.89
10/1/2025
25,000
4,500
6,695,000
5.000%
111,816.63
10/1/2025
115,000
34,500
10/1/2026
8,315,000
5.000%
138,873.09
10/1/2025
140,000
42,000
10/1/2027
1,735,000
3.250%
28,977.13
10/1/2025
30,000
5,850
7,000,000
5.000%
116,910.60
10/1/2025
120,000
36,000
10/1/2028
9,140,000
5.000%
152,651.83
10/1/2025
155,000
46,500
10/1/2029
9,595,000
5.000%
160,251.02
10/1/2025
165,000
49,500
10/1/2030
10,075,000
5.000%
168,267.75
10/1/2025
170,000
51,000
10/1/2031
10,580,000
5.000%
176,702.01
10/1/2025
180,000
54,000
98,790,000
10/1/2020
38,415,000
5.00%
641,588.65
10/1/2025
645,000
32,250
10/1/2021
40,330,000
5.00%
673,572.04
10/1/2025
675,000
67,500
10/1/2022
26,720,000
5.00%
446,264.44
10/1/2025
450,000
67,500
10/1/2023
27,975,000
5.00%
467,224.84
10/1/2025
470,000
94,000
10/1/2024
29,355,000
5.00%
490,272.93
10/1/2025
495,000
123,750
10/1/2026
4,500,000
4.00%
75,156.81
10/1/2025
80,000
19,200
18,375,000
5.00%
306,890.31
10/1/2025
310,000
93,000
10/1/2027
27,260,000
5.00%
455,283.26
10/1/2025
460,000
138,000
10/1/2028
45,110,000
5.00%
753,405.28
10/1/2025
755,000
226,500
Page 130 of 223
10/1/2029
48,475,000
5.00%
809,605.87
10/1/2025
810,000
243,000
10/1/2030
51,345,000
5.00%
857,539.22
10/1/2025
860,000
258,000
10/1/2031
20,000,000
3.00%
334,030.27
10/1/2025
335,000
60,300
46,260,000
5.00%
772,612.02
10/1/2025
775,000
232,500
424,120,000
846,753,000
ARP Line of Credit
$100 MM
5,000,000.00
83,507.57
14,275,000
Estimated Payment Calculation for the City of Clewiston:
14,358,508
2,091,112
16,449,619
Page 131 of 223
3
?
2,091,112
Estimated Clewiston
Withdrawal Year
Contract End Year
Discount Rate
$35,985,574
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
Page 1
2020
2021
2022
2023
2024
2025
2026
2027
2028
1,275
515
750
180
488
1,981
2,093
368
882
1,424
70
10,024
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
3,800
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
16,415
16,784
17,162
-
-
-
-
-
-
-
-
-
-
-
121
2029
2030
5,017
22,251
23,783
24,133
34,250
24,928
25,307
24,816
19,600
16,384
16,994
17,589
Stanton A - CC PPA
Southern Oleander
419
716
1,135
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
3,446
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
5,433
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
25,886
26,073
26,626
5,810
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
1,199
4,500
4,599
4,700
4,803
4,029
4,118
4,208
4,300
4,544
4,644
5,650
Totals
Clewiston Costs (2019 Dollars - $000)
Grand Total
5,253,778
2,361,148
35,986
2020
164,147
154,856
2,349
2021
168,410
149,884
2,275
2022
167,905
140,976
2,141
2023
222,078
175,907
2,665
Page 132 of 223
2024
162,433
121,379
1,848
2025
165,228
116,479
1,773
2026
167,132
111,152
1,692
2027
164,442
103,173
1,567
2028
153,829
91,051
1,392
2029
153,531
85,731
1,313
2030
157,696
83,072
1,272
Estimated Clewiston
Withdrawal Year
Contract End Year
Discount Rate
$35,985,574
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
Page 2
2031
2032
2033
2034
2035
2036
2037
2038
2039
1,275
515
750
180
488
1,981
2,093
368
882
1,424
70
10,024
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
3,800
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
18,773
19,196
19,628
-
-
-
-
-
4,931
-
-
-
-
-
121
2040
2041
5,017
17,940
18,521
18,920
19,689
19,647
19,553
19,993
20,443
20,903
21,373
21,854
Stanton A - CC PPA
Southern Oleander
419
716
1,135
-
-
-
-
-
-
-
-
-
-
-
3,446
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
5,433
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
5,810
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
1,199
5,775
5,902
6,132
6,268
6,406
6,458
6,743
6,892
7,045
7,201
7,360
Totals
Grand Total
5,253,778
2,361,148
35,986
2031
160,792
79,909
1,224
2032
164,180
76,974
1,179
2033
167,550
74,107
1,135
2034
171,256
71,459
1,094
Page 133 of 223
2035
170,808
67,238
1,029
2036
171,390
63,648
973
2037
170,019
59,565
910
2038
173,519
57,350
876
2039
177,097
55,220
844
2040
180,755
53,170
812
2041
184,496
51,199
782
Estimated Clewiston
Withdrawal Year
Contract End Year
Discount Rate
Page 3
$35,985,574
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2042
2043
2044
2045
2046
2047
2048
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
1,275
515
750
180
488
1,981
2,093
368
882
1,424
70
10,024
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
8,212
3,701
5,094
1,908
20,832
2,483
5,664
7,152
452
55,498
8,397
3,784
5,209
1,951
21,301
2,539
5,792
463
49,434
8,586
3,869
5,326
1,994
21,780
2,596
5,922
473
50,547
3,800
16,720
15,920
16,278
16,645
17,019
17,402
15,700
12,951
13,242
121
9,696
-
-
-
-
-
-
24,247
-
5,017
22,346
22,849
23,363
23,888
24,426
24,976
25,537
26,112
26,700
Stanton A - CC PPA
Southern Oleander
419
716
1,135
-
-
-
-
-
-
-
-
-
3,446
3,941
871
871
871
871
871
871
871
871
5,433
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
5,810
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
1,199
7,523
7,690
7,861
8,035
8,213
8,396
8,582
8,773
8,968
Totals
Grand Total
5,253,778
2,361,148
35,986
2042
174,366
45,648
694
2043
160,017
39,521
600
2044
163,561
38,109
578
Page 134 of 223
2045
167,185
36,749
558
2046
170,891
35,437
538
2047
174,680
34,173
519
2048
167,416
30,898
474
2049
2049
178,888
31,146
474
2050
2050
158,081
25,966
405
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE CITY OF FORT MEADE AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 135 of 223
All-Requirements Estimated Ft. Meade Section 29(c)(1) Withdrawal Payment
Calculation Date:
9/30/2016
9/30/2019
Ft. Meade Pro-Rata Share of Debt Section 29(c)(1): a percentage of FMPA's then outstanding Bonds
Ft. Meade Pro-Rata Share of Bonds:
coincident peak for Ft. Meade
9.353 (as of June 2015)
0.291
9.062
Ft. Meade share:
1,158.877 (as of June 2015)
0.782%
as of 9/30/2019
to be determined
Bonds Outstanding:
Bond Maturity
Bonds
Bond Payment or
Bond Principal
Liability
Bond Interest
Liability
10/1/2020
5,765,000
5.250%
45,080.22
11/1/2019
50,000
219
10/1/2021
6,045,000
5.250%
47,269.72
11/1/2019
50,000
219
10/1/2022
3,580,000
5.250%
27,994.31
11/1/2019
30,000
131
10/1/2023
3,770,000
5.250%
29,480.04
11/1/2019
30,000
131
10/1/2024
3,005,000
945,000
4.750%
5.250%
23,498.02
7,389.56
11/1/2019
11/2/2019
25,000
10,000
99
44
10/1/2026
2,195,000
630,000
4.750%
5.000%
17,164.11
4,926.37
11/1/2019
11/2/2019
20,000
5,000
79
21
10/1/2027
3,580,000
5.000%
27,994.31
11/1/2019
30,000
125
10/1/2028
6,730,000
5.000%
52,626.17
11/1/2019
55,000
229
10/1/2029
370,000
6,135,000
5.250%
5.000%
2,893.27
47,973.49
11/1/2019
11/2/2019
5,000
50,000
22
208
10/1/2030
395,000
6,535,000
5.250%
5.000%
3,088.76
51,101.34
11/1/2019
11/2/2019
5,000
55,000
22
229
10/1/2031
545,000
8,930,000
5.250%
5.000%
4,261.70
69,829.38
11/1/2019
11/2/2019
5,000
70,000
22
292
1,142,238.15
11/1/2019
1,145,000
3,817
59,155,000
10/01/35
Page 136 of 223
1
10/01/30
218,949.90
11/1/2019
220,000
831
2
328,424.85
11/1/2019
330,000
1,693
2
328,424.85
11/1/2019
330,000
1,238
2
55,000
92
10/01/25
10/01/30
10/1/2023
6,615,000
2.000%
51,726.91
11/1/2019
10/1/2020
1,000,000
5,235,000
4.000%
5.000%
7,819.64
40,935.81
10/1/2020
10/1/2020
10,000
45,000
400
2,250
10/1/2021
6,535,000
5.000%
51,101.34
10/1/2021
55,000
5,500
10/1/2022
6,865,000
5.000%
53,681.82
10/1/2022
55,000
8,250
10/1/2023
7,205,000
5.000%
56,340.50
10/1/2023
60,000
12,000
10/1/2024
7,565,000
5.000%
59,155.57
10/1/2024
60,000
15,000
10/1/2025
1,250,000
3.000%
9,774.55
10/1/2025
10,000
1,800
6,695,000
5.000%
52,352.48
10/1/2025
55,000
16,500
10/1/2026
8,315,000
5.000%
65,020.30
10/1/2025
70,000
21,000
10/1/2027
1,735,000
3.250%
13,567.07
10/1/2025
15,000
2,925
7,000,000
5.000%
54,737.47
10/1/2025
55,000
16,500
10/1/2028
9,140,000
5.000%
71,471.50
10/1/2025
75,000
22,500
10/1/2029
9,595,000
5.000%
75,029.44
10/1/2025
80,000
24,000
10/1/2030
10,075,000
5.000%
78,782.86
10/1/2025
80,000
24,000
10/1/2031
10,580,000
5.000%
82,731.78
10/1/2025
85,000
25,500
98,790,000
10/1/2020
38,415,000
5.00%
300,391.44
10/1/2025
305,000
15,250
10/1/2021
40,330,000
5.00%
315,366.05
10/1/2025
320,000
32,000
10/1/2022
26,720,000
5.00%
208,940.76
10/1/2025
210,000
31,500
10/1/2023
27,975,000
5.00%
218,754.41
10/1/2025
220,000
44,000
10/1/2024
29,355,000
5.00%
229,545.51
10/1/2025
230,000
57,500
10/1/2026
4,500,000
4.00%
35,188.38
10/1/2025
40,000
9,600
18,375,000
5.00%
143,685.87
10/1/2025
145,000
43,500
10/1/2027
27,260,000
5.00%
213,163.36
10/1/2025
215,000
64,500
10/1/2028
45,110,000
5.00%
352,743.92
10/1/2025
355,000
106,500
Page 137 of 223
10/1/2029
48,475,000
5.00%
379,057.01
10/1/2025
380,000
114,000
10/1/2030
51,345,000
5.00%
401,499.37
10/1/2025
405,000
121,500
10/1/2031
20,000,000
3.00%
156,392.78
10/1/2025
160,000
28,800
46,260,000
5.00%
361,736.51
10/1/2025
365,000
109,500
424,120,000
846,753,000
ARP Line of Credit
$100 MM
5,000,000.00
39,098.20
6,735,000
Estimated Payment Calculation for the City of Ft. Meade:
6,774,098
986,036
7,760,135
Page 138 of 223
3
?
986,036
Estimated Fort Meade
Withdrawal Year
Contract End Year
Discount Rate
Page 1
$13,502,124
2019
2041
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2020
2021
2022
2023
2024
2025
2026
2027
2028
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
423
191
274
55
210
844
730
128
282
611
23
3,771
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
1,506
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
16,415
16,784
17,162
-
-
-
-
-
-
-
-
-
-
-
1,744
22,251
23,783
24,133
34,250
24,928
25,307
24,816
19,600
16,384
16,994
17,589
197
361
558
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
1,389
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
2,177
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
25,886
26,073
26,626
1,927
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
417
4,500
4,599
4,700
4,803
4,029
4,118
4,208
4,300
4,544
4,644
5,650
Stanton A - CC PPA
Southern Oleander
Totals
Fort Meade Costs (2019 Dollars - $000)
12
Grand Total
5,253,778
2,361,148
13,502
2020
164,147
154,856
1,024
2021
168,410
149,884
991
2022
167,905
140,976
932
2023
222,078
175,907
1,163
Page 139 of 223
2024
162,433
121,379
801
2025
165,228
116,479
768
2026
167,132
111,152
733
2027
164,442
103,173
681
2028
153,829
91,051
601
2029
2030
2029
153,531
85,731
566
2030
157,696
83,072
549
Withdrawal Year
Contract End Year
Discount Rate
$13,502,124
2019
2041
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2031
2032
2033
2034
2035
2036
2037
2038
2039
423
191
274
55
210
844
730
128
282
611
23
3,771
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
1,506
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
18,773
19,196
19,628
-
-
-
-
-
4,931
-
-
-
-
-
17,940
18,521
18,920
19,689
19,647
19,553
19,993
20,443
20,903
21,373
21,854
-
-
-
-
-
-
-
-
-
-
-
Stanton A - CC PPA
Southern Oleander
Page 2
12
1,744
197
361
558
2040
2041
1,389
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
2,177
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
1,927
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
417
5,775
5,902
6,132
6,268
6,406
6,458
6,743
6,892
7,045
7,201
7,360
Totals
Grand Total
5,253,778
2,361,148
13,502
2031
160,792
79,909
528
2032
164,180
76,974
509
2033
167,550
74,107
490
2034
171,256
71,459
472
Page 140 of 223
2035
170,808
67,238
444
2036
171,390
63,648
421
2037
170,019
59,565
394
2038
173,519
57,350
379
2039
177,097
55,220
365
2040
180,755
53,170
352
2041
184,496
51,199
338
Withdrawal Year
Contract End Year
Discount Rate
$13,502,124
2019
2041
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2042
2043
2044
2045
2046
2047
2048
423
191
274
55
210
844
730
128
282
611
23
3,771
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
8,212
3,701
5,094
1,908
20,832
2,483
5,664
7,152
452
55,498
8,397
3,784
5,209
1,951
21,301
2,539
5,792
463
49,434
8,586
3,869
5,326
1,994
21,780
2,596
5,922
473
50,547
1,506
16,720
15,920
16,278
16,645
17,019
17,402
15,700
12,951
13,242
12
9,696
-
-
-
-
-
-
24,247
-
1,744
22,346
22,849
23,363
23,888
24,426
24,976
25,537
26,112
26,700
-
-
-
-
-
-
-
-
-
Stanton A - CC PPA
Southern Oleander
Page 3
197
361
558
2049
2050
1,389
3,941
871
871
871
871
871
871
871
871
2,177
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
1,927
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
417
7,523
7,690
7,861
8,035
8,213
8,396
8,582
8,773
8,968
Totals
Grand Total
5,253,778
2,361,148
13,502
2042
174,366
45,648
‐
2043
160,017
39,521
‐
2044
163,561
38,109
‐
Page 141 of 223
2045
167,185
36,749
‐
2046
170,891
35,437
‐
2047
174,680
34,173
‐
2048
167,416
30,898
‐
2049
178,888
31,146
‐
2050
158,081
25,966
‐
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE FORT PIERCE UTILITIES AUTHORITY AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 142 of 223
All-Requirements Estimated Ft. Pierce Section 29(c)(1) Withdrawal Payment
Calculation Date:
9/30/2016
9/30/2019
Ft. Pierce Pro-Rata Share of Debt Section 29(c)(1): a percentage of FMPA's then outstanding Bonds
Ft. Pierce Pro-Rata Share of Bonds:
coincident peak for Ft. Pierce
103.412 (as of June 2015)
13.174
90.238
Ft. Pierce share:
1,158.877 (as of June 2015)
7.787%
as of 9/30/2019
to be determined
Bonds Outstanding:
Bond Maturity
Bonds
Bond Payment or
Bond Principal
Liability
Bond Interest
Liability
10/1/2020
5,765,000
5.250%
448,901.89
11/1/2019
450,000
1,969
10/1/2021
6,045,000
5.250%
470,704.58
11/1/2019
475,000
2,078
10/1/2022
3,580,000
5.250%
278,763.01
11/1/2019
280,000
1,225
10/1/2023
3,770,000
5.250%
293,557.69
11/1/2019
295,000
1,291
10/1/2024
3,005,000
945,000
4.750%
5.250%
233,989.62
73,584.09
11/1/2019
11/2/2019
235,000
75,000
930
328
10/1/2026
2,195,000
630,000
4.750%
5.000%
170,917.54
49,056.06
11/1/2019
11/2/2019
175,000
50,000
693
208
10/1/2027
3,580,000
5.000%
278,763.01
11/1/2019
280,000
1,167
10/1/2028
6,730,000
5.000%
524,043.31
11/1/2019
525,000
2,188
10/1/2029
370,000
6,135,000
5.250%
5.000%
28,810.70
477,712.59
11/1/2019
11/2/2019
30,000
480,000
131
2,000
10/1/2030
395,000
6,535,000
5.250%
5.000%
30,757.37
508,859.29
11/1/2019
11/2/2019
35,000
510,000
153
2,125
10/1/2031
545,000
8,930,000
5.250%
5.000%
42,437.39
695,350.19
11/1/2019
11/2/2019
45,000
700,000
197
2,917
11,374,231.58
11/1/2019
11,375,000
37,917
59,155,000
10/01/35
Page 143 of 223
1
10/01/30
2,180,269.35
11/1/2019
2,185,000
8,252
2
3,270,404.02
11/1/2019
3,275,000
16,798
2
3,270,404.02
11/1/2019
3,275,000
12,286
2
520,000
867
10/01/25
10/01/30
10/1/2023
6,615,000
2.000%
515,088.63
11/1/2019
10/1/2020
1,000,000
5,235,000
4.000%
5.000%
77,866.76
407,632.50
10/1/2020
10/1/2020
80,000
410,000
3,200
20,500
10/1/2021
6,535,000
5.000%
508,859.29
10/1/2021
510,000
51,000
10/1/2022
6,865,000
5.000%
534,555.32
10/1/2022
535,000
80,250
10/1/2023
7,205,000
5.000%
561,030.02
10/1/2023
565,000
113,000
10/1/2024
7,565,000
5.000%
589,062.06
10/1/2024
590,000
147,500
10/1/2025
1,250,000
3.000%
97,333.45
10/1/2025
100,000
18,000
6,695,000
5.000%
521,317.97
10/1/2025
525,000
157,500
10/1/2026
8,315,000
5.000%
647,462.13
10/1/2025
650,000
195,000
10/1/2027
1,735,000
3.250%
135,098.83
10/1/2025
140,000
27,300
7,000,000
5.000%
545,067.34
10/1/2025
550,000
165,000
10/1/2028
9,140,000
5.000%
711,702.21
10/1/2025
715,000
214,500
10/1/2029
9,595,000
5.000%
747,131.59
10/1/2025
750,000
225,000
10/1/2030
10,075,000
5.000%
784,507.63
10/1/2025
785,000
235,500
10/1/2031
10,580,000
5.000%
823,830.35
10/1/2025
825,000
247,500
98,790,000
10/1/2020
38,415,000
5.00%
2,991,251.68
10/1/2025
2,995,000
149,750
10/1/2021
40,330,000
5.00%
3,140,366.53
10/1/2025
3,145,000
314,500
10/1/2022
26,720,000
5.00%
2,080,599.89
10/1/2025
2,085,000
312,750
10/1/2023
27,975,000
5.00%
2,178,322.68
10/1/2025
2,180,000
436,000
10/1/2024
29,355,000
5.00%
2,285,778.81
10/1/2025
2,290,000
572,500
10/1/2026
4,500,000
4.00%
350,400.43
10/1/2025
355,000
85,200
18,375,000
5.00%
1,430,801.76
10/1/2025
1,435,000
430,500
10/1/2027
27,260,000
5.00%
2,122,647.94
10/1/2025
2,125,000
637,500
10/1/2028
45,110,000
5.00%
3,512,569.65
10/1/2025
3,515,000
1,054,500
Page 144 of 223
10/1/2029
48,475,000
5.00%
3,774,591.31
10/1/2025
3,775,000
1,132,500
10/1/2030
51,345,000
5.00%
3,998,068.91
10/1/2025
4,000,000
1,200,000
10/1/2031
20,000,000
3.00%
1,557,335.25
10/1/2025
1,560,000
280,800
46,260,000
5.00%
3,602,116.43
10/1/2025
3,605,000
1,081,500
424,120,000
846,753,000
ARP Line of Credit
$100 MM
5,000,000.00
389,333.81
66,065,000
Estimated Payment Calculation for the City of Ft. Pierce:
66,454,334
9,684,468
76,138,802
Page 145 of 223
3
?
9,684,468
Estimated Fort Pierce
Withdrawal Year
Contract End Year
Discount Rate
Page 1
$176,869,932
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2020
2021
2022
2023
2024
2025
2026
2027
2028
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
6,292
2,836
3,698
936
2,539
9,770
10,530
1,903
4,484
9,435
347
52,768
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
20,290
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
16,415
16,784
17,162
-
-
-
-
-
-
-
-
-
-
-
16,106
15,100
16,081
16,318
21,542
16,826
17,073
16,685
12,885
10,513
10,890
11,266
Stanton A - CC PPA
Southern Oleander
2,107
4,747
6,854
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
17,016
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
29,387
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
25,886
26,073
26,626
28,674
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
5,078
3,804
3,887
3,972
4,059
3,268
3,339
3,412
3,486
3,655
3,735
4,720
Totals
Fort Pierce Costs (2019 Dollars - $000)
696
Grand Total
4,974,267
2,239,237
176,870
2020
156,299
147,452
11,647
2021
159,995
142,395
11,246
2022
159,361
133,803
10,568
2023
208,626
165,251
13,036
Page 146 of 223
2024
153,569
114,756
9,108
2025
156,215
110,126
8,740
2026
158,205
105,215
8,349
2027
156,913
98,449
7,810
2028
147,068
87,050
6,877
2029
2030
2029
146,517
81,815
6,455
2030
150,442
79,251
6,253
Withdrawal Year
Contract End Year
Discount Rate
Page 2
$176,869,932
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2031
2032
2033
2034
2035
2036
2037
2038
2039
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
6,292
2,836
3,698
936
2,539
9,770
10,530
1,903
4,484
9,435
347
52,768
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
20,290
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
18,773
19,196
19,628
-
-
-
-
-
4,931
-
-
-
-
-
16,106
11,491
11,860
12,135
12,586
12,581
12,327
12,605
12,888
13,178
13,475
13,778
2,107
4,747
6,854
-
-
-
-
-
-
-
-
-
-
-
17,016
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
29,387
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
28,674
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
5,078
4,824
4,930
5,138
5,251
5,367
5,396
5,601
5,724
5,851
5,980
6,112
Stanton A - CC PPA
Southern Oleander
Totals
696
Grand Total
4,974,267
2,239,237
176,870
2031
153,392
76,231
6,015
2032
156,547
73,395
5,791
2033
159,770
70,666
5,575
2034
163,136
68,071
5,371
Page 147 of 223
2035
162,702
64,047
5,051
2036
163,101
60,570
4,773
2037
161,489
56,577
4,457
2038
164,796
54,467
4,290
2039
168,178
52,439
4,131
2040
2041
2040
171,636
50,488
3,977
2041
175,172
48,611
3,829
Withdrawal Year
Contract End Year
Discount Rate
Page 3
$176,869,932
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2042
2043
2044
2045
2046
2047
2048
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
6,292
2,836
3,698
936
2,539
9,770
10,530
1,903
4,484
9,435
347
52,768
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
8,212
3,701
5,094
1,908
20,832
2,483
5,664
7,152
452
55,498
8,397
3,784
5,209
1,951
21,301
2,539
5,792
463
49,434
8,586
3,869
5,326
1,994
21,780
2,596
5,922
473
50,547
20,290
16,720
15,920
16,278
16,645
17,019
17,402
15,700
12,951
13,242
696
9,696
-
-
-
-
-
-
24,247
-
16,106
14,088
14,405
14,729
15,061
15,399
15,746
16,100
16,463
16,833
2,107
4,747
6,854
-
-
-
-
-
-
-
-
-
17,016
3,941
871
871
871
871
871
871
871
871
29,387
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
28,674
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
5,078
6,247
6,385
6,526
6,671
6,818
6,969
7,123
7,281
7,443
Stanton A - CC PPA
Southern Oleander
Totals
Grand Total
4,974,267
2,239,237
176,870
2042
164,831
43,152
3,400
2043
150,268
37,113
2,936
2044
153,593
35,787
2,831
Page 148 of 223
2045
156,993
34,509
2,730
2046
160,470
33,276
2,632
2047
164,024
32,088
2,538
2048
156,520
28,887
2,273
2049
2049
167,747
29,206
2,307
2050
2050
146,690
24,094
1,879
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE CITY OF GREEN COVE SPRINGS AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 149 of 223
All-Requirements Estimated Green Cove Springs Section 29(c)(1) Withdrawal Payment
Calculation Date:
9/30/2016
9/30/2019
Green Cove Springs Pro-Rata Share of Debt Section 29(c)(1): a percentage of FMPA's then outstanding Bonds
Green Cove Springs Pro-Rata Share of Bonds:
coincident peak for Green Cove Springs
23.061 (as of June 2015)
1.522
21.539
Green Cove Springs share:
1,158.877 (as of June 2015)
1.859%
as of 9/30/2019
to be determined
Bonds Outstanding:
Bond Maturity
Bonds
Bond Payment or
Bond Principal
Liability
Bond Interest
Liability
10/1/2020
5,765,000
5.250%
107,148.85
11/1/2019
110,000
481
10/1/2021
6,045,000
5.250%
112,352.95
11/1/2019
115,000
503
10/1/2022
3,580,000
5.250%
66,538.23
11/1/2019
70,000
306
10/1/2023
3,770,000
5.250%
70,069.58
11/1/2019
75,000
328
10/1/2024
3,005,000
945,000
4.750%
5.250%
55,851.22
17,563.86
11/1/2019
11/2/2019
60,000
20,000
238
88
10/1/2026
2,195,000
630,000
4.750%
5.000%
40,796.48
11,709.24
11/1/2019
11/2/2019
45,000
15,000
178
63
10/1/2027
3,580,000
5.000%
66,538.23
11/1/2019
70,000
292
10/1/2028
6,730,000
5.000%
125,084.43
11/1/2019
130,000
542
10/1/2029
370,000
6,135,000
5.250%
5.000%
6,876.86
114,025.70
11/1/2019
11/2/2019
10,000
115,000
44
479
10/1/2030
395,000
6,535,000
5.250%
5.000%
7,341.51
121,460.14
11/1/2019
11/2/2019
10,000
125,000
44
521
10/1/2031
545,000
8,930,000
5.250%
5.000%
10,129.42
165,973.84
11/1/2019
11/2/2019
15,000
170,000
66
708
2,714,926.91
11/1/2019
2,715,000
9,050
59,155,000
10/01/35
Page 150 of 223
1
10/01/30
520,410.71
11/1/2019
525,000
1,983
2
780,616.06
11/1/2019
785,000
4,026
2
780,616.06
11/1/2019
785,000
2,945
2
125,000
208
10/01/25
10/01/30
10/1/2023
6,615,000
2.000%
122,947.03
11/1/2019
10/1/2020
1,000,000
5,235,000
4.000%
5.000%
18,586.10
97,298.22
10/1/2020
10/1/2020
20,000
100,000
800
5,000
10/1/2021
6,535,000
5.000%
121,460.14
10/1/2021
125,000
12,500
10/1/2022
6,865,000
5.000%
127,593.55
10/1/2022
130,000
19,500
10/1/2023
7,205,000
5.000%
133,912.83
10/1/2023
135,000
27,000
10/1/2024
7,565,000
5.000%
140,603.82
10/1/2024
145,000
36,250
10/1/2025
1,250,000
3.000%
23,232.62
10/1/2025
25,000
4,500
6,695,000
5.000%
124,433.92
10/1/2025
125,000
37,500
10/1/2026
8,315,000
5.000%
154,543.39
10/1/2025
155,000
46,500
10/1/2027
1,735,000
3.250%
32,246.88
10/1/2025
35,000
6,825
7,000,000
5.000%
130,102.68
10/1/2025
135,000
40,500
10/1/2028
9,140,000
5.000%
169,876.92
10/1/2025
170,000
51,000
10/1/2029
9,595,000
5.000%
178,333.60
10/1/2025
180,000
54,000
10/1/2030
10,075,000
5.000%
187,254.92
10/1/2025
190,000
57,000
10/1/2031
10,580,000
5.000%
196,640.90
10/1/2025
200,000
60,000
98,790,000
10/1/2020
38,415,000
5.00%
713,984.91
10/1/2025
715,000
35,750
10/1/2021
40,330,000
5.00%
749,577.28
10/1/2025
750,000
75,000
10/1/2022
26,720,000
5.00%
496,620.50
10/1/2025
500,000
75,000
10/1/2023
27,975,000
5.00%
519,946.06
10/1/2025
520,000
104,000
10/1/2024
29,355,000
5.00%
545,594.87
10/1/2025
550,000
137,500
10/1/2026
4,500,000
4.00%
83,637.44
10/1/2025
85,000
20,400
18,375,000
5.00%
341,519.53
10/1/2025
345,000
103,500
10/1/2027
27,260,000
5.00%
506,657.00
10/1/2025
510,000
153,000
10/1/2028
45,110,000
5.00%
838,418.82
10/1/2025
840,000
252,000
Page 151 of 223
10/1/2029
48,475,000
5.00%
900,961.04
10/1/2025
905,000
271,500
10/1/2030
51,345,000
5.00%
954,303.14
10/1/2025
955,000
286,500
10/1/2031
20,000,000
3.00%
371,721.93
10/1/2025
375,000
67,500
46,260,000
5.00%
859,792.83
10/1/2025
860,000
258,000
424,120,000
846,753,000
ARP Line of Credit
$100 MM
5,000,000.00
92,930.48
15,870,000
Estimated Payment Calculation for the City of Green Cove Springs:
15,962,930
2,321,616
18,284,547
Page 152 of 223
3
?
2,321,616
Estimated Green Cove Springs
Withdrawal Year
Contract End Year
Discount Rate
Page 1
$35,209,075
2019
2037
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2020
2021
2022
2023
2024
2025
2026
2027
2028
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
1,100
499
681
141
625
2,175
1,782
334
697
1,489
60
9,584
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
3,934
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
16,415
16,784
17,162
-
-
-
-
-
-
-
-
-
-
-
36
2029
2030
4,659
22,251
23,783
24,133
34,250
24,928
25,307
24,816
19,600
16,384
16,994
17,589
Stanton A - CC PPA
Southern Oleander
557
1,010
1,567
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
3,804
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
5,597
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
25,886
26,073
26,626
4,968
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
1,061
4,500
4,599
4,700
4,803
4,029
4,118
4,208
4,300
4,544
4,644
5,650
Totals
Green Cove Springs Costs (2019 Dollars - $000)
Grand Total
5,253,778
2,361,148
35,209
2020
164,147
154,856
2,981
2021
168,410
149,884
2,886
2022
167,905
140,976
2,715
2023
222,078
175,907
3,388
Page 153 of 223
2024
162,433
121,379
2,336
2025
165,228
116,479
2,242
2026
167,132
111,152
2,139
2027
164,442
103,173
1,985
2028
153,829
91,051
1,757
2029
153,531
85,731
1,656
2030
157,696
83,072
1,605
Withdrawal Year
Contract End Year
Discount Rate
Page 2
$35,209,075
2019
2037
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2031
2032
2033
2034
2035
2036
2037
2038
2039
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
1,100
499
681
141
625
2,175
1,782
334
697
1,489
60
9,584
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
3,934
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
18,773
19,196
19,628
-
-
-
-
-
4,931
-
-
-
-
-
36
2040
2041
4,659
17,940
18,521
18,920
19,689
19,647
19,553
19,993
20,443
20,903
21,373
21,854
Stanton A - CC PPA
Southern Oleander
557
1,010
1,567
-
-
-
-
-
-
-
-
-
-
-
3,804
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
5,597
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
4,968
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
1,061
5,775
5,902
6,132
6,268
6,406
6,458
6,743
6,892
7,045
7,201
7,360
Totals
Grand Total
5,253,778
2,361,148
35,209
2031
160,792
79,909
1,544
2032
164,180
76,974
1,487
2033
167,550
74,107
1,431
2034
171,256
71,459
1,380
Page 154 of 223
2035
170,808
67,238
1,298
2036
171,390
63,648
1,229
2037
170,019
59,565
1,149
2038
173,519
57,350
‐
2039
177,097
55,220
‐
2040
180,755
53,170
‐
2041
184,496
51,199
‐
Withdrawal Year
Contract End Year
Discount Rate
Page 3
$35,209,075
2019
2037
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2042
2043
2044
2045
2046
2047
2048
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
1,100
499
681
141
625
2,175
1,782
334
697
1,489
60
9,584
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
8,212
3,701
5,094
1,908
20,832
2,483
5,664
7,152
452
55,498
8,397
3,784
5,209
1,951
21,301
2,539
5,792
463
49,434
8,586
3,869
5,326
1,994
21,780
2,596
5,922
473
50,547
3,934
16,720
15,920
16,278
16,645
17,019
17,402
15,700
12,951
13,242
36
9,696
-
-
-
-
-
-
24,247
-
4,659
22,346
22,849
23,363
23,888
24,426
24,976
25,537
26,112
26,700
Stanton A - CC PPA
Southern Oleander
557
1,010
1,567
-
-
-
-
-
-
-
-
-
3,804
3,941
871
871
871
871
871
871
871
871
5,597
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
4,968
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
1,061
7,523
7,690
7,861
8,035
8,213
8,396
8,582
8,773
8,968
Totals
Grand Total
5,253,778
2,361,148
35,209
2042
174,366
45,648
‐
2043
160,017
39,521
‐
2044
163,561
38,109
‐
Page 155 of 223
2045
167,185
36,749
‐
2046
170,891
35,437
‐
2047
174,680
34,173
‐
2048
167,416
30,898
‐
2049
2049
178,888
31,146
‐
2050
2050
158,081
25,966
‐
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE TOWN OF HAVANA AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 156 of 223
All-Requirements Estimated Havana Section 29(c)(1) Withdrawal Payment
Calculation Date:
9/30/2016
9/30/2019
Havana Pro-Rata Share of Debt Section 29(c)(1): a percentage of FMPA's then outstanding Bonds
Havana Pro-Rata Share of Bonds:
coincident peak for Havana
4.637 (as of June 2015)
0.000
4.637
Havana share:
1,158.877 (as of June 2015)
0.400%
as of 9/30/2019
to be determined
Bonds Outstanding:
Bond Maturity
Bonds
Bond Payment or
Bond Principal
Liability
Bond Interest
Liability
10/1/2020
5,765,000
5.250%
23,067.42
11/1/2019
25,000
109
10/1/2021
6,045,000
5.250%
24,187.78
11/1/2019
25,000
109
10/1/2022
3,580,000
5.250%
14,324.61
11/1/2019
15,000
66
10/1/2023
3,770,000
5.250%
15,084.85
11/1/2019
20,000
88
10/1/2024
3,005,000
945,000
4.750%
5.250%
12,023.87
3,781.22
11/1/2019
11/2/2019
15,000
5,000
59
22
10/1/2026
2,195,000
630,000
4.750%
5.000%
8,782.83
2,520.81
11/1/2019
11/2/2019
10,000
5,000
40
21
10/1/2027
3,580,000
5.000%
14,324.61
11/1/2019
15,000
63
10/1/2028
6,730,000
5.000%
26,928.66
11/1/2019
30,000
125
10/1/2029
370,000
6,135,000
5.250%
5.000%
1,480.48
24,547.90
11/1/2019
11/2/2019
5,000
25,000
22
104
10/1/2030
395,000
6,535,000
5.250%
5.000%
1,580.51
26,148.41
11/1/2019
11/2/2019
5,000
30,000
22
125
10/1/2031
545,000
8,930,000
5.250%
5.000%
2,180.70
35,731.50
11/1/2019
11/2/2019
5,000
40,000
22
167
584,480.06
11/1/2019
585,000
1,950
59,155,000
10/01/35
Page 157 of 223
1
10/01/30
112,036.05
11/1/2019
115,000
434
2
168,054.07
11/1/2019
170,000
872
2
168,054.07
11/1/2019
170,000
638
2
30,000
50
10/01/25
10/01/30
10/1/2023
6,615,000
2.000%
26,468.52
11/1/2019
10/1/2020
1,000,000
5,235,000
4.000%
5.000%
4,001.29
20,946.74
10/1/2020
10/1/2020
5,000
25,000
200
1,250
10/1/2021
6,535,000
5.000%
26,148.41
10/1/2021
30,000
3,000
10/1/2022
6,865,000
5.000%
27,468.84
10/1/2022
30,000
4,500
10/1/2023
7,205,000
5.000%
28,829.28
10/1/2023
30,000
6,000
10/1/2024
7,565,000
5.000%
30,269.74
10/1/2024
35,000
8,750
10/1/2025
1,250,000
3.000%
5,001.61
10/1/2025
10,000
1,800
6,695,000
5.000%
26,788.62
10/1/2025
30,000
9,000
10/1/2026
8,315,000
5.000%
33,270.71
10/1/2025
35,000
10,500
10/1/2027
1,735,000
3.250%
6,942.23
10/1/2025
10,000
1,950
7,000,000
5.000%
28,009.01
10/1/2025
30,000
9,000
10/1/2028
9,140,000
5.000%
36,571.77
10/1/2025
40,000
12,000
10/1/2029
9,595,000
5.000%
38,392.35
10/1/2025
40,000
12,000
10/1/2030
10,075,000
5.000%
40,312.97
10/1/2025
45,000
13,500
10/1/2031
10,580,000
5.000%
42,333.62
10/1/2025
45,000
13,500
98,790,000
10/1/2020
38,415,000
5.00%
153,709.46
10/1/2025
155,000
7,750
10/1/2021
40,330,000
5.00%
161,371.92
10/1/2025
165,000
16,500
10/1/2022
26,720,000
5.00%
106,914.40
10/1/2025
110,000
16,500
10/1/2023
27,975,000
5.00%
111,936.02
10/1/2025
115,000
23,000
10/1/2024
29,355,000
5.00%
117,457.79
10/1/2025
120,000
30,000
10/1/2026
4,500,000
4.00%
18,005.79
10/1/2025
20,000
4,800
18,375,000
5.00%
73,523.66
10/1/2025
75,000
22,500
10/1/2027
27,260,000
5.00%
109,075.10
10/1/2025
110,000
33,000
10/1/2028
45,110,000
5.00%
180,498.08
10/1/2025
185,000
55,500
Page 158 of 223
10/1/2029
48,475,000
5.00%
193,962.41
10/1/2025
195,000
58,500
10/1/2030
51,345,000
5.00%
205,446.10
10/1/2025
210,000
63,000
10/1/2031
20,000,000
3.00%
80,025.75
10/1/2025
85,000
15,300
46,260,000
5.00%
185,099.56
10/1/2025
190,000
57,000
424,120,000
846,753,000
ARP Line of Credit
$100 MM
5,000,000.00
20,006.44
3,520,000
Estimated Payment Calculation for the City of Havana:
3,540,006
515,407
4,055,413
Page 159 of 223
3
?
515,407
Estimated Havana
Withdrawal Year
Contract End Year
Discount Rate
Page 1
$9,684,126
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2020
2021
2022
2023
2024
2025
2026
2027
2028
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
332
150
179
49
134
545
598
100
230
403
18
2,739
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
1,049
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
16,415
16,784
17,162
-
-
-
-
-
-
-
-
-
-
-
1,308
22,251
23,783
24,133
34,250
24,928
25,307
24,816
19,600
16,384
16,994
17,589
Stanton A - CC PPA
Southern Oleander
120
203
322
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
898
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
1,501
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
25,886
26,073
26,626
1,514
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
320
4,500
4,599
4,700
4,803
4,029
4,118
4,208
4,300
4,544
4,644
5,650
Totals
Havana Costs (2019 Dollars - $000)
34
Grand Total
5,253,778
2,361,148
9,684
2020
164,147
154,856
634
2021
168,410
149,884
614
2022
167,905
140,976
578
2023
222,078
175,907
720
Page 160 of 223
2024
162,433
121,379
497
2025
165,228
116,479
477
2026
167,132
111,152
455
2027
164,442
103,173
422
2028
153,829
91,051
374
2029
2030
2029
153,531
85,731
353
2030
157,696
83,072
342
Estimated Havana
Withdrawal Year
Contract End Year
Discount Rate
$9,684,126
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2031
2032
2033
2034
2035
2036
2037
2038
2039
332
150
179
49
134
545
598
100
230
403
18
2,739
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
1,049
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
18,773
19,196
19,628
-
-
-
-
-
4,931
-
-
-
-
-
17,940
18,521
18,920
19,689
19,647
19,553
19,993
20,443
20,903
21,373
21,854
Page 2
34
1,308
2040
2041
Stanton A - CC PPA
Southern Oleander
120
203
322
-
-
-
-
-
-
-
-
-
-
-
898
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
1,501
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
1,514
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
320
5,775
5,902
6,132
6,268
6,406
6,458
6,743
6,892
7,045
7,201
7,360
Totals
Grand Total
5,253,778
2,361,148
9,684
2031
160,792
79,909
329
2032
164,180
76,974
317
2033
167,550
74,107
305
2034
171,256
71,459
294
Page 161 of 223
2035
170,808
67,238
277
2036
171,390
63,648
262
2037
170,019
59,565
245
2038
173,519
57,350
236
2039
177,097
55,220
227
2040
180,755
53,170
218
2041
184,496
51,199
210
Estimated Havana
Withdrawal Year
Contract End Year
Discount Rate
$9,684,126
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2042
2043
2044
2045
2046
2047
2048
332
150
179
49
134
545
598
100
230
403
18
2,739
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
8,212
3,701
5,094
1,908
20,832
2,483
5,664
7,152
452
55,498
8,397
3,784
5,209
1,951
21,301
2,539
5,792
463
49,434
8,586
3,869
5,326
1,994
21,780
2,596
5,922
473
50,547
1,049
16,720
15,920
16,278
16,645
17,019
17,402
15,700
12,951
13,242
34
9,696
-
-
-
-
-
-
24,247
-
1,308
22,346
22,849
23,363
23,888
24,426
24,976
25,537
26,112
26,700
-
-
-
-
-
-
-
-
Page 3
2049
2050
Stanton A - CC PPA
Southern Oleander
120
203
322
-
898
3,941
871
871
871
871
871
871
871
871
1,501
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
1,514
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
320
7,523
7,690
7,861
8,035
8,213
8,396
8,582
8,773
8,968
Totals
Grand Total
5,253,778
2,361,148
9,684
2042
174,366
45,648
187
2043
160,017
39,521
161
2044
163,561
38,109
156
Page 162 of 223
2045
167,185
36,749
150
2046
170,891
35,437
145
2047
174,680
34,173
140
2048
167,416
30,898
127
2049
178,888
31,146
128
2050
158,081
25,966
108
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE CITY OF JACKSONVILLE BEACH AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 163 of 223
All-Requirements Estimated Jacksonville Beach Section 29(c)(1) Withdrawal Payment
Calculation Date:
9/30/2016
9/30/2019
Jacksonville Beach Pro-Rata Share of Debt Section 29(c)(1): a percentage of FMPA's then outstanding Bonds
Jacksonville Beach Pro-Rata Share of Bonds:
coincident peak for Jacksonville Beach
151.007 (as of June 2015)
6.350
144.657
Jacksonville Beach share:
1,158.877 (as of June 2015)
12.483%
as of 9/30/2019
to be determined
Bonds Outstanding:
Bond Maturity
Bonds
Bond Payment or
Bond Principal
Liability
Bond Interest
Liability
10/1/2020
5,765,000
5.250%
719,617.01
11/1/2019
720,000
3,150
10/1/2021
6,045,000
5.250%
754,568.06
11/1/2019
755,000
3,303
10/1/2022
3,580,000
5.250%
446,874.05
11/1/2019
450,000
1,969
10/1/2023
3,770,000
5.250%
470,590.83
11/1/2019
475,000
2,078
10/1/2024
3,005,000
945,000
4.750%
5.250%
375,099.59
117,959.77
11/1/2019
11/2/2019
380,000
120,000
1,504
525
10/1/2026
2,195,000
630,000
4.750%
5.000%
273,991.21
78,639.85
11/1/2019
11/2/2019
275,000
80,000
1,089
333
10/1/2027
3,580,000
5.000%
446,874.05
11/1/2019
450,000
1,875
10/1/2028
6,730,000
5.000%
840,073.29
11/1/2019
845,000
3,521
10/1/2029
370,000
6,135,000
5.250%
5.000%
46,185.31
765,802.32
11/1/2019
11/2/2019
50,000
770,000
219
3,208
10/1/2030
395,000
6,535,000
5.250%
5.000%
49,305.94
815,732.38
11/1/2019
11/2/2019
50,000
820,000
219
3,417
10/1/2031
545,000
8,930,000
5.250%
5.000%
68,029.71
1,114,688.63
11/1/2019
11/2/2019
70,000
1,115,000
306
4,646
18,233,584.72
11/1/2019
18,235,000
60,783
59,155,000
10/01/35
Page 164 of 223
1
10/01/30
3,495,104.31
11/1/2019
3,500,000
13,218
2
5,242,656.47
11/1/2019
5,245,000
26,902
2
5,242,656.47
11/1/2019
5,245,000
19,677
2
830,000
1,383
10/01/25
10/01/30
10/1/2023
6,615,000
2.000%
825,718.39
11/1/2019
10/1/2020
1,000,000
5,235,000
4.000%
5.000%
124,825.15
653,459.68
10/1/2020
10/1/2020
125,000
655,000
5,000
32,750
10/1/2021
6,535,000
5.000%
815,732.38
10/1/2021
820,000
82,000
10/1/2022
6,865,000
5.000%
856,924.68
10/1/2022
860,000
129,000
10/1/2023
7,205,000
5.000%
899,365.23
10/1/2023
900,000
180,000
10/1/2024
7,565,000
5.000%
944,302.29
10/1/2024
945,000
236,250
10/1/2025
1,250,000
3.000%
156,031.44
10/1/2025
160,000
28,800
6,695,000
5.000%
835,704.41
10/1/2025
840,000
252,000
10/1/2026
8,315,000
5.000%
1,037,921.16
10/1/2025
1,040,000
312,000
10/1/2027
1,735,000
3.250%
216,571.64
10/1/2025
220,000
42,900
7,000,000
5.000%
873,776.08
10/1/2025
875,000
262,500
10/1/2028
9,140,000
5.000%
1,140,901.91
10/1/2025
1,145,000
343,500
10/1/2029
9,595,000
5.000%
1,197,697.35
10/1/2025
1,200,000
360,000
10/1/2030
10,075,000
5.000%
1,257,613.43
10/1/2025
1,260,000
378,000
10/1/2031
10,580,000
5.000%
1,320,650.13
10/1/2025
1,325,000
397,500
98,790,000
10/1/2020
38,415,000
5.00%
4,795,158.29
10/1/2025
4,800,000
240,000
10/1/2021
40,330,000
5.00%
5,034,198.46
10/1/2025
5,035,000
503,500
10/1/2022
26,720,000
5.00%
3,335,328.12
10/1/2025
3,340,000
501,000
10/1/2023
27,975,000
5.00%
3,491,983.68
10/1/2025
3,495,000
699,000
10/1/2024
29,355,000
5.00%
3,664,242.40
10/1/2025
3,665,000
916,250
10/1/2026
4,500,000
4.00%
561,713.19
10/1/2025
565,000
135,600
18,375,000
5.00%
2,293,662.20
10/1/2025
2,295,000
688,500
10/1/2027
27,260,000
5.00%
3,402,733.70
10/1/2025
3,405,000
1,021,500
10/1/2028
45,110,000
5.00%
5,630,862.70
10/1/2025
5,635,000
1,690,500
Page 165 of 223
10/1/2029
48,475,000
5.00%
6,050,899.34
10/1/2025
6,055,000
1,816,500
10/1/2030
51,345,000
5.00%
6,409,147.53
10/1/2025
6,410,000
1,923,000
10/1/2031
20,000,000
3.00%
2,496,503.08
10/1/2025
2,500,000
450,000
46,260,000
5.00%
5,774,411.62
10/1/2025
5,775,000
1,732,500
424,120,000
846,753,000
ARP Line of Credit
$100 MM
5,000,000.00
624,125.77
105,825,000
Estimated Payment Calculation for the City of Jacksonville Beach:
106,449,126
15,513,375
121,962,501
Page 166 of 223
3
?
15,513,375
Estimated Jacksonville Beach
Withdrawal Year
Contract End Year
Discount Rate
Page 1
$310,506,115
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2020
2021
2022
2023
2024
2025
2026
2027
2028
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
11,088
5,247
6,817
1,634
4,435
18,012
17,404
3,469
6,977
13,967
569
89,620
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
34,160
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
16,415
16,784
17,162
1,140
-
-
-
-
-
-
-
-
-
-
-
40,678
22,251
23,783
24,133
34,250
24,928
25,307
24,816
19,600
16,384
16,994
17,589
Stanton A - CC PPA
Southern Oleander
3,483
7,026
10,509
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
27,949
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
48,527
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
25,886
26,073
26,626
47,106
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
10,817
4,390
4,489
4,590
4,693
3,919
4,007
4,097
4,190
4,434
4,534
5,540
Totals
Jacksonville Beach Costs (2019 Dollars - $000)
Grand Total
5,250,356
2,359,610
310,506
2020
164,037
154,751
20,254
2021
168,299
149,786
19,615
2022
167,795
140,884
18,454
2023
221,968
175,820
23,063
Page 167 of 223
2024
162,323
121,297
15,971
2025
165,118
116,401
15,328
2026
167,021
111,079
14,629
2027
164,331
103,104
13,583
2028
153,719
90,986
12,021
2029
2030
2029
153,421
85,669
11,328
2030
157,585
83,014
10,984
Withdrawal Year
Contract End Year
Discount Rate
Page 2
$310,506,115
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2031
2032
2033
2034
2035
2036
2037
2038
2039
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
11,088
5,247
6,817
1,634
4,435
18,012
17,404
3,469
6,977
13,967
569
89,620
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
34,160
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
18,773
19,196
19,628
1,140
-
-
-
-
-
4,931
-
-
-
-
-
40,678
17,940
18,521
18,920
19,689
19,647
19,553
19,993
20,443
20,903
21,373
21,854
Stanton A - CC PPA
Southern Oleander
3,483
7,026
10,509
-
-
-
-
-
-
-
-
-
-
-
27,949
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
48,527
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
47,106
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
10,817
5,664
5,792
6,022
6,157
6,296
6,348
6,632
6,782
6,934
7,090
7,250
Totals
Grand Total
5,250,356
2,359,610
310,506
2031
160,682
79,854
10,566
2032
164,070
76,922
10,178
2033
167,439
74,059
9,800
2034
171,146
71,413
9,450
Page 168 of 223
2035
170,698
67,194
8,885
2036
171,279
63,607
8,409
2037
169,909
59,527
7,856
2038
173,408
57,314
7,564
2039
176,986
55,185
7,283
2040
2041
2040
180,645
53,138
7,013
2041
184,386
51,168
6,753
Withdrawal Year
Contract End Year
Discount Rate
Page 3
$310,506,115
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2042
2043
2044
2045
2046
2047
2048
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
11,088
5,247
6,817
1,634
4,435
18,012
17,404
3,469
6,977
13,967
569
89,620
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
8,212
3,701
5,094
1,908
20,832
2,483
5,664
7,152
452
55,498
8,397
3,784
5,209
1,951
21,301
2,539
5,792
463
49,434
8,586
3,869
5,326
1,994
21,780
2,596
5,922
473
50,547
34,160
16,720
15,920
16,278
16,645
17,019
17,402
15,700
12,951
13,242
1,140
9,696
-
-
-
-
-
-
24,247
-
40,678
22,346
22,849
23,363
23,888
24,426
24,976
25,537
26,112
26,700
Stanton A - CC PPA
Southern Oleander
3,483
7,026
10,509
-
-
-
-
-
-
-
-
-
27,949
3,941
871
871
871
871
871
871
871
871
48,527
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
47,106
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
10,817
7,413
7,580
7,750
7,925
8,103
8,285
8,472
8,662
8,857
Totals
Grand Total
5,250,356
2,359,610
310,506
2042
174,255
45,620
5,998
2043
159,906
39,493
5,155
2044
163,451
38,084
4,971
Page 169 of 223
2045
167,075
36,725
4,794
2046
170,781
35,414
4,623
2047
174,570
34,151
4,458
2048
167,306
30,877
4,041
2049
2049
178,777
31,127
4,066
2050
2050
157,971
25,947
3,410
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE UTILITY BOARD OF THE CITY OF KEY WEST AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 170 of 223
All-Requirements Estimated Key West Section 29(c)(1) Withdrawal Payment
Calculation Date:
9/30/2016
9/30/2019
Key West Pro-Rata Share of Debt Section 29(c)(1): a percentage of FMPA's then outstanding Bonds
Key West Pro-Rata Share of Bonds:
coincident peak for Key West
129.977 (as of June 2015)
0.000
129.977
Key West share:
1,158.877 (as of June 2015)
11.216%
as of 9/30/2019
to be determined
Bonds Outstanding:
Bond Maturity
Bonds
Bond Payment or
Bond Principal
Liability
Bond Interest
Liability
10/1/2020
5,765,000
5.250%
646,589.25
11/1/2019
650,000
2,844
10/1/2021
6,045,000
5.250%
677,993.41
11/1/2019
680,000
2,975
10/1/2022
3,580,000
5.250%
401,524.63
11/1/2019
405,000
1,772
10/1/2023
3,770,000
5.250%
422,834.60
11/1/2019
425,000
1,859
10/1/2024
3,005,000
945,000
4.750%
5.250%
337,033.94
105,989.04
11/1/2019
11/2/2019
340,000
110,000
1,346
481
10/1/2026
2,195,000
630,000
4.750%
5.000%
246,186.19
70,659.36
11/1/2019
11/2/2019
250,000
75,000
990
313
10/1/2027
3,580,000
5.000%
401,524.63
11/1/2019
405,000
1,688
10/1/2028
6,730,000
5.000%
754,821.44
11/1/2019
755,000
3,146
10/1/2029
370,000
6,135,000
5.250%
5.000%
41,498.36
688,087.60
11/1/2019
11/2/2019
45,000
690,000
197
2,875
10/1/2030
395,000
6,535,000
5.250%
5.000%
44,302.30
732,950.69
11/1/2019
11/2/2019
45,000
735,000
197
3,063
10/1/2031
545,000
8,930,000
5.250%
5.000%
61,125.96
1,001,568.42
11/1/2019
11/2/2019
65,000
1,005,000
284
4,188
16,383,214.37
11/1/2019
16,385,000
54,617
59,155,000
10/01/35
Page 171 of 223
1
10/01/30
3,140,416.11
11/1/2019
3,145,000
11,877
2
4,710,624.16
11/1/2019
4,715,000
24,184
2
4,710,624.16
11/1/2019
4,715,000
17,688
2
745,000
1,242
10/01/25
10/01/30
10/1/2023
6,615,000
2.000%
741,923.31
11/1/2019
10/1/2020
1,000,000
5,235,000
4.000%
5.000%
112,157.72
587,145.65
10/1/2020
10/1/2020
115,000
590,000
4,600
29,500
10/1/2021
6,535,000
5.000%
732,950.69
10/1/2021
735,000
73,500
10/1/2022
6,865,000
5.000%
769,962.74
10/1/2022
770,000
115,500
10/1/2023
7,205,000
5.000%
808,096.36
10/1/2023
810,000
162,000
10/1/2024
7,565,000
5.000%
848,473.14
10/1/2024
850,000
212,500
10/1/2025
1,250,000
3.000%
140,197.15
10/1/2025
145,000
26,100
6,695,000
5.000%
750,895.92
10/1/2025
755,000
226,500
10/1/2026
8,315,000
5.000%
932,591.43
10/1/2025
935,000
280,500
10/1/2027
1,735,000
3.250%
194,593.64
10/1/2025
195,000
38,025
7,000,000
5.000%
785,104.03
10/1/2025
790,000
237,000
10/1/2028
9,140,000
5.000%
1,025,121.54
10/1/2025
1,030,000
309,000
10/1/2029
9,595,000
5.000%
1,076,153.31
10/1/2025
1,080,000
324,000
10/1/2030
10,075,000
5.000%
1,129,989.01
10/1/2025
1,130,000
339,000
10/1/2031
10,580,000
5.000%
1,186,628.66
10/1/2025
1,190,000
357,000
98,790,000
10/1/2020
38,415,000
5.00%
4,308,538.74
10/1/2025
4,310,000
215,500
10/1/2021
40,330,000
5.00%
4,523,320.78
10/1/2025
4,525,000
452,500
10/1/2022
26,720,000
5.00%
2,996,854.23
10/1/2025
3,000,000
450,000
10/1/2023
27,975,000
5.00%
3,137,612.17
10/1/2025
3,140,000
628,000
10/1/2024
29,355,000
5.00%
3,292,389.82
10/1/2025
3,295,000
823,750
10/1/2026
4,500,000
4.00%
504,709.73
10/1/2025
505,000
121,200
18,375,000
5.00%
2,060,898.07
10/1/2025
2,065,000
619,500
10/1/2027
27,260,000
5.00%
3,057,419.40
10/1/2025
3,060,000
918,000
10/1/2028
45,110,000
5.00%
5,059,434.67
10/1/2025
5,060,000
1,518,000
Page 172 of 223
10/1/2029
48,475,000
5.00%
5,436,845.39
10/1/2025
5,440,000
1,632,000
10/1/2030
51,345,000
5.00%
5,758,738.04
10/1/2025
5,760,000
1,728,000
10/1/2031
20,000,000
3.00%
2,243,154.36
10/1/2025
2,245,000
404,100
46,260,000
5.00%
5,188,416.04
10/1/2025
5,190,000
1,557,000
424,120,000
846,753,000
ARP Line of Credit
$100 MM
5,000,000.00
560,788.59
95,100,000
Estimated Payment Calculation for the City of Key West:
95,660,789
13,940,098
109,600,887
Page 173 of 223
3
?
13,940,098
Estimated Key West
Withdrawal Year
Contract End Year
Discount Rate
Page 1
$223,446,066
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2020
2021
2022
2023
2024
2025
2026
2027
2028
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
8,775
3,954
3,941
1,305
3,541
10,413
13,844
2,654
10,158
483
59,067
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
6,483
243
36,288
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
6,628
248
37,105
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
6,778
254
37,940
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
6,930
259
38,793
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
7,086
265
39,666
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
7,245
271
40,559
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
7,408
277
41,471
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
7,575
283
42,404
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
7,746
290
43,359
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
7,920
296
44,334
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
8,098
303
45,332
22,232
11,240
12,555
12,838
54,452
13,422
13,724
14,033
14,349
14,671
15,002
15,339
-
-
-
-
-
-
-
-
-
-
-
27,094
17,857
19,061
19,342
26,520
19,959
20,257
19,825
15,456
12,744
13,211
13,672
Stanton A - CC PPA
Southern Oleander
2,770
5,110
7,880
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
23,702
19,068
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
35,581
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
25,886
26,073
26,626
39,988
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
7,110
4,003
4,090
4,180
4,271
3,486
3,561
3,639
3,719
3,918
4,004
4,995
Totals
Key West Costs (2019 Dollars - $000)
793
Grand Total
4,879,526
2,203,995
223,446
2020
154,591
145,840
14,753
2021
158,581
141,136
14,289
2022
157,892
132,569
13,430
2023
209,009
165,555
16,630
Page 174 of 223
2024
152,004
113,586
11,539
2025
154,595
108,983
11,069
2026
156,433
104,037
10,560
2027
154,462
96,911
9,807
2028
144,189
85,345
8,655
2029
2030
2029
143,613
80,193
8,137
2030
147,506
77,704
7,888
Estimated Key West
Withdrawal Year
Contract End Year
Discount Rate
Page 2
$223,446,066
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2031
2032
2033
2034
2035
2036
2037
2038
2039
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
8,775
3,954
3,941
1,305
3,541
10,413
13,844
2,654
10,158
483
59,067
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
8,280
310
46,352
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
8,467
317
47,395
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
8,657
324
48,461
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
8,852
331
49,551
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
9,051
339
50,046
6,288
2,833
3,900
915
13,209
11,208
1,901
9,255
346
49,856
6,429
2,897
3,988
936
13,506
11,460
1,944
9,463
354
50,978
6,574
2,962
4,078
957
13,810
11,718
1,988
9,676
362
52,125
6,722
3,029
4,169
979
14,121
11,982
2,033
9,894
370
53,298
6,873
3,097
4,263
1,001
14,439
12,251
2,078
10,116
379
54,497
7,028
3,167
4,359
1,023
14,764
12,527
2,125
10,344
387
55,723
22,232
15,684
16,037
16,398
16,767
16,492
15,478
15,826
16,182
16,546
16,919
17,299
-
-
-
-
-
4,931
-
-
-
-
-
27,094
13,945
14,396
14,718
15,294
15,271
15,079
15,418
15,765
16,119
16,482
16,853
2,770
5,110
7,880
-
-
-
-
-
-
-
-
-
-
-
23,702
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
35,581
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
39,988
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
7,110
5,105
5,217
5,432
5,552
5,674
5,710
5,939
6,070
6,204
6,341
6,481
Stanton A - CC PPA
Southern Oleander
Totals
793
Grand Total
4,879,526
2,203,995
223,446
2031
150,383
74,736
7,585
2032
153,497
71,965
7,303
2033
156,642
69,283
7,030
2034
160,004
66,764
6,774
Page 175 of 223
2035
159,421
62,756
6,347
2036
159,747
59,324
5,976
2037
158,075
55,381
5,560
2038
161,306
53,314
5,352
2039
164,609
51,326
5,151
2040
2041
2040
167,987
49,414
4,958
2041
171,441
47,576
4,773
Estimated Key West
Withdrawal Year
Contract End Year
Discount Rate
Page 3
$223,446,066
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2042
2043
2044
2045
2046
2047
2048
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
8,775
3,954
3,941
1,305
3,541
10,413
13,844
2,654
10,158
483
59,067
7,186
3,238
4,457
1,438
4,555
16,219
2,173
10,576
396
50,238
7,347
3,311
4,558
1,707
18,639
2,222
10,814
405
49,003
7,513
3,386
4,660
1,745
19,058
2,272
11,058
414
50,105
7,682
3,462
4,765
1,784
19,487
2,323
11,307
423
51,233
7,854
3,540
4,872
1,825
19,926
2,375
11,561
433
52,385
8,031
3,619
4,982
1,866
20,374
2,429
11,821
442
53,564
8,212
3,701
5,094
1,908
20,832
2,483
7,152
452
49,834
8,397
3,784
5,209
1,951
21,301
2,539
463
43,643
8,586
3,869
5,326
1,994
21,780
2,596
473
44,624
22,232
14,339
13,486
13,789
14,099
14,417
14,741
12,979
10,169
10,397
793
9,696
-
-
-
-
-
-
24,247
-
27,094
17,232
17,620
18,016
18,422
18,836
19,260
19,693
20,137
20,590
2,770
5,110
7,880
-
-
-
-
-
-
-
-
-
23,702
3,941
871
871
871
871
871
871
871
871
35,581
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
39,988
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
7,110
6,625
6,771
6,921
7,074
7,231
7,391
7,555
7,723
7,894
Stanton A - CC PPA
Southern Oleander
Totals
Grand Total
4,879,526
2,203,995
223,446
2042
161,016
42,154
4,248
2043
146,367
36,149
3,722
2044
149,604
34,858
3,589
Page 176 of 223
2045
152,914
33,612
3,460
2046
156,299
32,411
3,337
2047
159,760
31,254
3,218
2048
152,160
28,082
2,915
2049
2049
163,288
28,430
2,934
2050
2050
142,131
23,346
2,457
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE KISSIMMEE UTILITY AUTHORITY AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 177 of 223
All-Requirements Estimated KUA Section 29(c)(1) Withdrawal Payment
Calculation Date:
9/30/2016
9/30/2019
KUA Pro-Rata Share of Debt Section 29(c)(1): a percentage of FMPA's then outstanding Bonds
KUA Pro-Rata Share of Bonds:
coincident peak for KUA
330.474 (as of June 2015)
8.148
322.326
KUA share:
1,158.877 (as of June 2015)
27.814%
as of 9/30/2019
to be determined
Bonds Outstanding:
Bond Maturity
Bonds
Bond Payment or
Bond Principal
Liability
Bond Interest
Liability
10/1/2020
5,765,000
5.250%
1,603,456.96
11/1/2019
1,605,000
7,022
10/1/2021
6,045,000
5.250%
1,681,335.18
11/1/2019
1,685,000
7,372
10/1/2022
3,580,000
5.250%
995,728.69
11/1/2019
1,000,000
4,375
10/1/2023
3,770,000
5.250%
1,048,574.63
11/1/2019
1,050,000
4,594
10/1/2024
3,005,000
945,000
4.750%
5.250%
835,800.20
262,839.00
11/1/2019
11/2/2019
840,000
265,000
3,325
1,159
10/1/2026
2,195,000
630,000
4.750%
5.000%
610,509.63
175,226.00
11/1/2019
11/2/2019
615,000
180,000
2,434
750
10/1/2027
3,580,000
5.000%
995,728.69
11/1/2019
1,000,000
4,167
10/1/2028
6,730,000
5.000%
1,871,858.69
11/1/2019
1,875,000
7,813
10/1/2029
370,000
6,135,000
5.250%
5.000%
102,910.51
1,706,367.47
11/1/2019
11/2/2019
105,000
1,710,000
459
7,125
10/1/2030
395,000
6,535,000
5.250%
5.000%
109,863.92
1,817,622.07
11/1/2019
11/2/2019
110,000
1,820,000
481
7,583
10/1/2031
545,000
8,930,000
5.250%
5.000%
151,584.40
2,483,759.00
11/1/2019
11/2/2019
155,000
2,485,000
678
10,354
40,628,233.88
11/1/2019
40,630,000
135,433
59,155,000
10/01/35
Page 178 of 223
1
10/01/30
7,787,822.18
11/1/2019
7,790,000
29,419
2
11,681,733.26
11/1/2019
11,685,000
59,934
2
11,681,733.26
11/1/2019
11,685,000
43,836
2
1,840,000
3,067
10/01/25
10/01/30
10/1/2023
6,615,000
2.000%
1,839,872.99
11/1/2019
10/1/2020
1,000,000
5,235,000
4.000%
5.000%
278,136.51
1,456,044.61
10/1/2020
10/1/2020
280,000
1,460,000
11,200
73,000
10/1/2021
6,535,000
5.000%
1,817,622.07
10/1/2021
1,820,000
182,000
10/1/2022
6,865,000
5.000%
1,909,407.12
10/1/2022
1,910,000
286,500
10/1/2023
7,205,000
5.000%
2,003,973.53
10/1/2023
2,005,000
401,000
10/1/2024
7,565,000
5.000%
2,104,102.67
10/1/2024
2,105,000
526,250
10/1/2025
1,250,000
3.000%
347,670.63
10/1/2025
350,000
63,000
6,695,000
5.000%
1,862,123.91
10/1/2025
1,865,000
559,500
10/1/2026
8,315,000
5.000%
2,312,705.05
10/1/2025
2,315,000
694,500
10/1/2027
1,735,000
3.250%
482,566.84
10/1/2025
485,000
94,575
7,000,000
5.000%
1,946,955.54
10/1/2025
1,950,000
585,000
10/1/2028
9,140,000
5.000%
2,542,167.67
10/1/2025
2,545,000
763,500
10/1/2029
9,595,000
5.000%
2,668,719.78
10/1/2025
2,670,000
801,000
10/1/2030
10,075,000
5.000%
2,802,225.30
10/1/2025
2,805,000
841,500
10/1/2031
10,580,000
5.000%
2,942,684.24
10/1/2025
2,945,000
883,500
98,790,000
10/1/2020
38,415,000
5.00%
10,684,613.89
10/1/2025
10,685,000
534,250
10/1/2021
40,330,000
5.00%
11,217,245.30
10/1/2025
11,220,000
1,122,000
10/1/2022
26,720,000
5.00%
7,431,807.45
10/1/2025
7,435,000
1,115,250
10/1/2023
27,975,000
5.00%
7,780,868.76
10/1/2025
7,785,000
1,557,000
10/1/2024
29,355,000
5.00%
8,164,697.14
10/1/2025
8,165,000
2,041,250
10/1/2026
4,500,000
4.00%
1,251,614.28
10/1/2025
1,255,000
301,200
18,375,000
5.00%
5,110,758.30
10/1/2025
5,115,000
1,534,500
10/1/2027
27,260,000
5.00%
7,582,001.16
10/1/2025
7,585,000
2,275,500
10/1/2028
45,110,000
5.00%
12,546,737.80
10/1/2025
12,550,000
3,765,000
Page 179 of 223
10/1/2029
48,475,000
5.00%
13,482,667.14
10/1/2025
13,485,000
4,045,500
10/1/2030
51,345,000
5.00%
14,280,918.92
10/1/2025
14,285,000
4,285,500
10/1/2031
20,000,000
3.00%
5,562,730.13
10/1/2025
5,565,000
1,001,700
46,260,000
5.00%
12,866,594.78
10/1/2025
12,870,000
3,861,000
424,120,000
846,753,000
ARP Line of Credit
$100 MM
5,000,000.00
1,390,682.53
235,640,000
Estimated Payment Calculation for the City of KUA:
237,030,683
34,547,056
271,577,739
Page 180 of 223
3
?
34,547,056
Estimated KUA
Withdrawal Year
Contract End Year
Discount Rate
Page 1
$604,091,445
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2020
2021
2022
2023
2024
2025
2026
2027
2028
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
22,375
10,083
13,879
3,327
9,029
36,671
35,624
6,766
14,515
27,796
1,232
181,299
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
69,080
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
16,415
16,784
17,162
2,294
-
-
-
-
-
-
-
-
-
-
-
51,366
12,077
12,998
13,189
21,386
13,675
13,897
13,727
11,358
9,947
10,340
10,710
Stanton A - CC PPA
Southern Oleander
3,564
13,984
17,548
3,972
8,826
12,798
4,079
8,826
12,905
4,189
8,826
13,015
4,302
8,826
13,128
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
60,490
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
98,043
28,110
27,396
24,662
25,320
25,018
25,547
26,088
26,641
25,886
26,073
26,626
101,966
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
22,006
4,500
4,599
4,700
4,803
4,029
4,118
4,208
4,300
4,544
4,644
5,650
Totals
KUA Costs (2019 Dollars - $000)
Grand Total
4,950,699
2,213,421
604,091
2020
148,816
140,393
38,199
2021
152,368
135,607
36,915
2022
151,719
127,386
34,689
2023
203,836
161,457
43,860
Page 181 of 223
2024
151,180
112,970
30,869
2025
153,818
108,435
29,630
2026
156,043
103,777
28,355
2027
156,200
98,002
26,761
2028
147,392
87,241
23,916
2029
2030
2029
146,877
82,015
22,506
2030
150,816
79,448
21,805
Estimated KUA
Withdrawal Year
Contract End Year
Discount Rate
Page 2
$604,091,445
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2031
2032
2033
2034
2035
2036
2037
2038
2039
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
22,375
10,083
13,879
3,327
9,029
36,671
35,624
6,766
14,515
27,796
1,232
181,299
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
69,080
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
18,773
19,196
19,628
2,294
-
-
-
-
-
4,931
-
-
-
-
-
51,366
10,923
11,280
11,491
12,026
11,967
11,700
11,964
12,233
12,508
12,789
13,077
Stanton A - CC PPA
Southern Oleander
3,564
13,984
17,548
-
-
-
-
-
-
-
-
-
-
-
60,490
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
98,043
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
101,966
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
22,006
5,775
5,902
6,132
6,268
6,406
6,458
6,743
6,892
7,045
7,201
7,360
Totals
Grand Total
4,950,699
2,213,421
604,091
2031
153,774
76,421
20,972
2032
156,940
73,579
20,192
2033
160,120
70,821
19,434
2034
163,593
68,262
18,731
Page 182 of 223
2035
163,128
64,215
17,602
2036
163,537
60,732
16,626
2037
161,990
56,752
15,519
2038
165,308
54,637
14,940
2039
168,702
52,602
14,383
2040
2041
2040
172,172
50,645
13,847
2041
175,719
48,763
13,332
Estimated KUA
Withdrawal Year
Contract End Year
Discount Rate
Page 3
$604,091,445
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2042
2043
2044
2045
2046
2047
2048
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
22,375
10,083
13,879
3,327
9,029
36,671
35,624
6,766
14,515
27,796
1,232
181,299
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
8,212
3,701
5,094
1,908
20,832
2,483
5,664
7,152
452
55,498
8,397
3,784
5,209
1,951
21,301
2,539
5,792
463
49,434
8,586
3,869
5,326
1,994
21,780
2,596
5,922
473
50,547
69,080
16,720
15,920
16,278
16,645
17,019
17,402
15,700
12,951
13,242
2,294
9,696
-
-
-
-
-
-
24,247
-
51,366
13,372
13,672
13,980
14,295
14,616
14,945
15,281
15,625
15,977
Stanton A - CC PPA
Southern Oleander
3,564
13,984
17,548
-
-
-
-
-
-
-
-
-
60,490
3,941
871
871
871
871
871
871
871
871
98,043
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
101,966
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
22,006
7,523
7,690
7,861
8,035
8,213
8,396
8,582
8,773
8,968
Totals
Grand Total
4,950,699
2,213,421
604,091
2042
165,391
43,299
11,769
2043
150,840
37,254
10,056
2044
154,178
35,923
9,697
Page 183 of 223
2045
157,591
34,640
9,351
2046
161,081
33,403
9,017
2047
164,650
32,210
8,695
2048
157,160
29,005
7,870
2049
2049
168,401
29,320
7,927
2050
2050
147,358
24,204
6,627
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE CITY OF LAKE WORTH AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 184 of 223
Estimated Lake Worth
Withdrawal Year
Contract End Year
Discount Rate
$39,215,680
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2020
2021
2022
2023
2024
2025
2026
2027
2028
7,672
1,341
6,587
15,600
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
6,591
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
16,415
16,784
17,162
-
-
-
-
-
-
-
-
-
-
-
-
22,251
23,783
24,133
34,250
24,928
25,307
24,816
19,600
16,384
16,994
17,589
1,535
3,314
4,849
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
22
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
11,749
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
25,886
26,073
26,626
-
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
155
4,500
4,599
4,700
4,803
4,029
4,118
4,208
4,300
4,544
4,644
5,650
250
Stanton A - CC PPA
Southern Oleander
Totals
Lake Worth Costs (2019 Dollars - $000)
Page 1
Grand Total
5,253,778
2,361,148
39,216
2020
164,147
154,856
2,896
2021
168,410
149,884
2,765
2022
167,905
140,976
2,578
2023
222,078
175,907
3,377
Page 185 of 223
2024
162,433
121,379
1,915
2025
165,228
116,479
1,838
2026
167,132
111,152
1,761
2027
164,442
103,173
1,691
2028
153,829
91,051
1,331
2029
2030
2029
153,531
85,731
1,208
2030
157,696
83,072
1,165
Withdrawal Year
Contract End Year
Discount Rate
$39,215,680
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2031
2032
2033
2034
2035
2036
2037
2038
2039
7,672
1,341
6,587
15,600
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
6,591
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
18,773
19,196
19,628
-
-
-
-
-
4,931
-
-
-
-
-
17,940
18,521
18,920
19,689
19,647
19,553
19,993
20,443
20,903
21,373
21,854
-
-
-
-
-
-
-
-
-
-
-
22
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
11,749
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
-
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
155
5,775
5,902
6,132
6,268
6,406
6,458
6,743
6,892
7,045
7,201
7,360
250
Stanton A - CC PPA
Southern Oleander
1,535
3,314
4,849
Totals
Page 2
Grand Total
5,253,778
2,361,148
39,216
2031
160,792
79,909
1,123
2032
164,180
76,974
1,083
2033
167,550
74,107
1,044
2034
171,256
71,459
1,007
Page 186 of 223
2035
170,808
67,238
978
2036
171,390
63,648
959
2037
170,019
59,565
925
2038
173,519
57,350
892
2039
177,097
55,220
860
2040
2041
2040
180,755
53,170
829
2041
184,496
51,199
799
Withdrawal Year
Contract End Year
Discount Rate
$39,215,680
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2042
2043
2044
2045
2046
2047
2048
7,672
1,341
6,587
15,600
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
8,212
3,701
5,094
1,908
20,832
2,483
5,664
7,152
452
55,498
8,397
3,784
5,209
1,951
21,301
2,539
5,792
463
49,434
8,586
3,869
5,326
1,994
21,780
2,596
5,922
473
50,547
6,591
16,720
15,920
16,278
16,645
17,019
17,402
15,700
12,951
13,242
250
9,696
-
-
-
-
-
-
24,247
-
-
22,346
22,849
23,363
23,888
24,426
24,976
25,537
26,112
26,700
-
-
-
-
-
-
-
-
-
Stanton A - CC PPA
Southern Oleander
1,535
3,314
4,849
Totals
2050
3,941
871
871
871
871
871
871
871
871
11,749
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
-
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
155
7,523
7,690
7,861
8,035
8,213
8,396
8,582
8,773
8,968
2049
22
Page 3
Grand Total
5,253,778
2,361,148
39,216
2042
174,366
45,648
822
2043
160,017
39,521
822
2044
163,561
38,109
792
Page 187 of 223
2045
167,185
36,749
764
2046
170,891
35,437
736
2047
174,680
34,173
710
2048
167,416
30,898
563
2049
178,888
31,146
623
2050
158,081
25,966
359
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE CITY OF LEESBURG AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 188 of 223
All-Requirements Estimated Leesburg Section 29(c)(1) Withdrawal Payment
Calculation Date:
9/30/2016
9/30/2019
Leesburg Pro-Rata Share of Debt Section 29(c)(1): a percentage of FMPA's then outstanding Bonds
Leesburg Pro-Rata Share of Bonds:
coincident peak for Leesburg
105.630 (as of June 2015)
2.015
103.615
Leesburg share:
1,158.877 (as of June 2015)
8.941%
as of 9/30/2019
to be determined
Bonds Outstanding:
Bond Maturity
Bonds
Bond Payment or
Bond Principal
Liability
Bond Interest
Liability
10/1/2020
5,765,000
5.250%
515,447.69
11/1/2019
520,000
2,275
10/1/2021
6,045,000
5.250%
540,482.45
11/1/2019
545,000
2,384
10/1/2022
3,580,000
5.250%
320,087.21
11/1/2019
325,000
1,422
10/1/2023
3,770,000
5.250%
337,075.07
11/1/2019
340,000
1,488
10/1/2024
3,005,000
945,000
4.750%
5.250%
268,676.55
84,492.29
11/1/2019
11/2/2019
270,000
85,000
1,069
372
10/1/2026
2,195,000
630,000
4.750%
5.000%
196,254.59
56,328.20
11/1/2019
11/2/2019
200,000
60,000
792
250
10/1/2027
3,580,000
5.000%
320,087.21
11/1/2019
325,000
1,354
10/1/2028
6,730,000
5.000%
601,728.18
11/1/2019
605,000
2,521
10/1/2029
370,000
6,135,000
5.250%
5.000%
33,081.64
548,529.33
11/1/2019
11/2/2019
35,000
550,000
153
2,292
10/1/2030
395,000
6,535,000
5.250%
5.000%
35,316.88
584,293.26
11/1/2019
11/2/2019
40,000
585,000
175
2,438
10/1/2031
545,000
8,930,000
5.250%
5.000%
48,728.36
798,429.82
11/1/2019
11/2/2019
50,000
800,000
219
3,333
13,060,362.66
11/1/2019
13,065,000
43,550
59,155,000
10/01/35
Page 189 of 223
1
10/01/30
2,503,475.35
11/1/2019
2,505,000
9,460
2
3,755,213.02
11/1/2019
3,760,000
19,286
2
3,755,213.02
11/1/2019
3,760,000
14,106
2
595,000
992
10/01/25
10/01/30
10/1/2023
6,615,000
2.000%
591,446.05
11/1/2019
10/1/2020
1,000,000
5,235,000
4.000%
5.000%
89,409.83
468,060.48
10/1/2020
10/1/2020
90,000
470,000
3,600
23,500
10/1/2021
6,535,000
5.000%
584,293.26
10/1/2021
585,000
58,500
10/1/2022
6,865,000
5.000%
613,798.51
10/1/2022
615,000
92,250
10/1/2023
7,205,000
5.000%
644,197.85
10/1/2023
645,000
129,000
10/1/2024
7,565,000
5.000%
676,385.39
10/1/2024
680,000
170,000
10/1/2025
1,250,000
3.000%
111,762.29
10/1/2025
115,000
20,700
6,695,000
5.000%
598,598.84
10/1/2025
600,000
180,000
10/1/2026
8,315,000
5.000%
743,442.77
10/1/2025
745,000
223,500
10/1/2027
1,735,000
3.250%
155,126.06
10/1/2025
160,000
31,200
7,000,000
5.000%
625,868.84
10/1/2025
630,000
189,000
10/1/2028
9,140,000
5.000%
817,205.88
10/1/2025
820,000
246,000
10/1/2029
9,595,000
5.000%
857,887.36
10/1/2025
860,000
258,000
10/1/2030
10,075,000
5.000%
900,804.08
10/1/2025
905,000
271,500
10/1/2031
10,580,000
5.000%
945,956.04
10/1/2025
950,000
285,000
98,790,000
10/1/2020
38,415,000
5.00%
3,434,678.77
10/1/2025
3,435,000
171,750
10/1/2021
40,330,000
5.00%
3,605,898.60
10/1/2025
3,610,000
361,000
10/1/2022
26,720,000
5.00%
2,389,030.76
10/1/2025
2,390,000
358,500
10/1/2023
27,975,000
5.00%
2,501,240.10
10/1/2025
2,505,000
501,000
10/1/2024
29,355,000
5.00%
2,624,625.67
10/1/2025
2,625,000
656,250
10/1/2026
4,500,000
4.00%
402,344.25
10/1/2025
405,000
97,200
18,375,000
5.00%
1,642,905.70
10/1/2025
1,645,000
493,500
10/1/2027
27,260,000
5.00%
2,437,312.07
10/1/2025
2,440,000
732,000
10/1/2028
45,110,000
5.00%
4,033,277.60
10/1/2025
4,035,000
1,210,500
Page 190 of 223
10/1/2029
48,475,000
5.00%
4,334,141.69
10/1/2025
4,335,000
1,300,500
10/1/2030
51,345,000
5.00%
4,590,747.92
10/1/2025
4,595,000
1,378,500
10/1/2031
20,000,000
3.00%
1,788,196.68
10/1/2025
1,790,000
322,200
46,260,000
5.00%
4,136,098.91
10/1/2025
4,140,000
1,242,000
424,120,000
846,753,000
ARP Line of Credit
$100 MM
5,000,000.00
447,049.17
75,840,000
Estimated Payment Calculation for the City of Leesburg:
76,287,049
11,116,579
87,403,628
Page 191 of 223
3
?
11,116,579
Estimated Leesburg
Withdrawal Year
Contract End Year
Discount Rate
Page 1
$184,977,511
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2020
2021
2022
2023
2024
2025
2026
2027
2028
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
5,953
2,445
3,750
899
2,440
9,909
10,328
1,690
4,216
8,238
367
50,235
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
19,230
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
16,415
16,784
17,162
-
-
-
-
-
-
-
-
-
-
-
26,235
22,251
23,783
24,133
34,250
24,928
25,307
24,816
19,600
16,384
16,994
17,589
Stanton A - CC PPA
Southern Oleander
2,067
4,145
6,211
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
18,022
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
28,259
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
25,886
26,073
26,626
30,380
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
5,760
4,500
4,599
4,700
4,803
4,029
4,118
4,208
4,300
4,544
4,644
5,650
Totals
Leesburg Costs (2019 Dollars - $000)
646
Grand Total
5,253,778
2,361,148
184,978
2020
164,147
154,856
12,132
2021
168,410
149,884
11,743
2022
167,905
140,976
11,048
2023
222,078
175,907
13,706
Page 192 of 223
2024
162,433
121,379
9,561
2025
165,228
116,479
9,174
2026
167,132
111,152
8,749
2027
164,442
103,173
8,100
2028
153,829
91,051
7,150
2029
2030
2029
153,531
85,731
6,733
2030
157,696
83,072
6,519
Estimated Leesburg
Withdrawal Year
Contract End Year
Discount Rate
Page 2
$184,977,511
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2031
2032
2033
2034
2035
2036
2037
2038
2039
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
5,953
2,445
3,750
899
2,440
9,909
10,328
1,690
4,216
8,238
367
50,235
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
19,230
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
18,773
19,196
19,628
-
-
-
-
-
4,931
-
-
-
-
-
26,235
17,940
18,521
18,920
19,689
19,647
19,553
19,993
20,443
20,903
21,373
21,854
2,067
4,145
6,211
-
-
-
-
-
-
-
-
-
-
-
18,022
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
28,259
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
30,380
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
5,760
5,775
5,902
6,132
6,268
6,406
6,458
6,743
6,892
7,045
7,201
7,360
Stanton A - CC PPA
Southern Oleander
Totals
646
Grand Total
5,253,778
2,361,148
184,978
2031
160,792
79,909
6,269
2032
164,180
76,974
6,039
2033
167,550
74,107
5,812
2034
171,256
71,459
5,605
Page 193 of 223
2035
170,808
67,238
5,270
2036
171,390
63,648
4,978
2037
170,019
59,565
4,663
2038
173,519
57,350
4,489
2039
177,097
55,220
4,322
2040
2041
2040
180,755
53,170
4,161
2041
184,496
51,199
4,006
Estimated Leesburg
Withdrawal Year
Contract End Year
Discount Rate
Page 3
$184,977,511
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2042
2043
2044
2045
2046
2047
2048
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
5,953
2,445
3,750
899
2,440
9,909
10,328
1,690
4,216
8,238
367
50,235
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
8,212
3,701
5,094
1,908
20,832
2,483
5,664
7,152
452
55,498
8,397
3,784
5,209
1,951
21,301
2,539
5,792
463
49,434
8,586
3,869
5,326
1,994
21,780
2,596
5,922
473
50,547
19,230
16,720
15,920
16,278
16,645
17,019
17,402
15,700
12,951
13,242
646
9,696
-
-
-
-
-
-
24,247
-
26,235
22,346
22,849
23,363
23,888
24,426
24,976
25,537
26,112
26,700
2,067
4,145
6,211
-
-
-
-
-
-
-
-
-
18,022
3,941
871
871
871
871
871
871
871
871
28,259
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
30,380
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
5,760
7,523
7,690
7,861
8,035
8,213
8,396
8,582
8,773
8,968
Stanton A - CC PPA
Southern Oleander
Totals
Grand Total
5,253,778
2,361,148
184,978
2042
174,366
45,648
3,555
2043
160,017
39,521
3,076
2044
163,561
38,109
2,966
Page 194 of 223
2045
167,185
36,749
2,860
2046
170,891
35,437
2,758
2047
174,680
34,173
2,659
2048
167,416
30,898
2,412
2049
2049
178,888
31,146
2,426
2050
2050
158,081
25,966
2,038
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE CITY OF NEWBERRY AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 195 of 223
All-Requirements Estimated Newberry Section 29(c)(1) Withdrawal Payment
Calculation Date:
9/30/2016
9/30/2019
Newberry Pro-Rata Share of Debt Section 29(c)(1): a percentage of FMPA's then outstanding Bonds
Newberry Pro-Rata Share of Bonds:
coincident peak for Newberry
7.831 (as of June 2015)
0.159
7.672
Newberry share:
1,158.877 (as of June 2015)
0.662%
as of 9/30/2019
to be determined
Bonds Outstanding:
Bond Maturity
Bonds
Bond Payment or
Bond Principal
Liability
Bond Interest
Liability
10/1/2020
5,765,000
5.250%
38,165.47
11/1/2019
40,000
175
10/1/2021
6,045,000
5.250%
40,019.12
11/1/2019
45,000
197
10/1/2022
3,580,000
5.250%
23,700.32
11/1/2019
25,000
109
10/1/2023
3,770,000
5.250%
24,958.16
11/1/2019
25,000
109
10/1/2024
3,005,000
945,000
4.750%
5.250%
19,893.71
6,256.09
11/1/2019
11/2/2019
20,000
10,000
79
44
10/1/2026
2,195,000
630,000
4.750%
5.000%
14,531.34
4,170.73
11/1/2019
11/2/2019
15,000
5,000
59
21
10/1/2027
3,580,000
5.000%
23,700.32
11/1/2019
25,000
104
10/1/2028
6,730,000
5.000%
44,553.96
11/1/2019
45,000
188
10/1/2029
370,000
6,135,000
5.250%
5.000%
2,449.47
40,614.94
11/1/2019
11/2/2019
5,000
45,000
22
188
10/1/2030
395,000
6,535,000
5.250%
5.000%
2,614.98
43,263.02
11/1/2019
11/2/2019
5,000
45,000
22
188
10/1/2031
545,000
8,930,000
5.250%
5.000%
3,608.01
59,118.41
11/1/2019
11/2/2019
5,000
60,000
22
250
967,032.79
11/1/2019
970,000
3,233
59,155,000
10/01/35
Page 196 of 223
1
10/01/30
185,365.66
11/1/2019
190,000
718
2
278,048.49
11/1/2019
280,000
1,436
2
278,048.49
11/1/2019
280,000
1,050
2
45,000
75
10/01/25
10/01/30
10/1/2023
6,615,000
2.000%
43,792.64
11/1/2019
10/1/2020
1,000,000
5,235,000
4.000%
5.000%
6,620.20
34,656.76
10/1/2020
10/1/2020
10,000
35,000
400
1,750
10/1/2021
6,535,000
5.000%
43,263.02
10/1/2021
45,000
4,500
10/1/2022
6,865,000
5.000%
45,447.69
10/1/2022
50,000
7,500
10/1/2023
7,205,000
5.000%
47,698.56
10/1/2023
50,000
10,000
10/1/2024
7,565,000
5.000%
50,081.83
10/1/2024
55,000
13,750
10/1/2025
1,250,000
3.000%
8,275.25
10/1/2025
10,000
1,800
6,695,000
5.000%
44,322.25
10/1/2025
45,000
13,500
10/1/2026
8,315,000
5.000%
55,046.98
10/1/2025
60,000
18,000
10/1/2027
1,735,000
3.250%
11,486.05
10/1/2025
15,000
2,925
7,000,000
5.000%
46,341.42
10/1/2025
50,000
15,000
10/1/2028
9,140,000
5.000%
60,508.65
10/1/2025
65,000
19,500
10/1/2029
9,595,000
5.000%
63,520.84
10/1/2025
65,000
19,500
10/1/2030
10,075,000
5.000%
66,698.54
10/1/2025
70,000
21,000
10/1/2031
10,580,000
5.000%
70,041.74
10/1/2025
75,000
22,500
98,790,000
10/1/2020
38,415,000
5.00%
254,315.07
10/1/2025
255,000
12,750
10/1/2021
40,330,000
5.00%
266,992.75
10/1/2025
270,000
27,000
10/1/2022
26,720,000
5.00%
176,891.80
10/1/2025
180,000
27,000
10/1/2023
27,975,000
5.00%
185,200.15
10/1/2025
190,000
38,000
10/1/2024
29,355,000
5.00%
194,336.03
10/1/2025
195,000
48,750
10/1/2026
4,500,000
4.00%
29,790.91
10/1/2025
30,000
7,200
18,375,000
5.00%
121,646.21
10/1/2025
125,000
37,500
10/1/2027
27,260,000
5.00%
180,466.71
10/1/2025
185,000
55,500
10/1/2028
45,110,000
5.00%
298,637.32
10/1/2025
300,000
90,000
Page 197 of 223
10/1/2029
48,475,000
5.00%
320,914.30
10/1/2025
325,000
97,500
10/1/2030
51,345,000
5.00%
339,914.28
10/1/2025
340,000
102,000
10/1/2031
20,000,000
3.00%
132,404.04
10/1/2025
135,000
24,300
46,260,000
5.00%
306,250.55
10/1/2025
310,000
93,000
424,120,000
846,753,000
ARP Line of Credit
$100 MM
5,000,000.00
33,101.01
5,725,000
Estimated Payment Calculation for the City of Newberry:
5,758,101
840,413
6,598,515
Page 198 of 223
3
?
840,413
Estimated Newberry
Withdrawal Year
Contract End Year
Discount Rate
Page 1
$15,186,336
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2020
2021
2022
2023
2024
2025
2026
2027
2028
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
542
244
261
81
219
888
838
164
332
596
30
4,195
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
1,616
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
16,415
16,784
17,162
-
-
-
-
-
-
-
-
-
-
-
2,133
22,251
23,783
24,133
34,250
24,928
25,307
24,816
19,600
16,384
16,994
17,589
168
300
467
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
1,465
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
2,278
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
25,886
26,073
26,626
2,470
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
509
4,500
4,599
4,700
4,803
4,029
4,118
4,208
4,300
4,544
4,644
5,650
Stanton A - CC PPA
Southern Oleander
Totals
Newberry Costs (2019 Dollars - $000)
53
Grand Total
5,253,778
2,361,148
15,186
2020
164,147
154,856
991
2021
168,410
149,884
960
2022
167,905
140,976
903
2023
222,078
175,907
1,126
Page 199 of 223
2024
162,433
121,379
782
2025
165,228
116,479
751
2026
167,132
111,152
716
2027
164,442
103,173
663
2028
153,829
91,051
589
2029
2030
2029
153,531
85,731
556
2030
157,696
83,072
539
Estimated Newberry
Withdrawal Year
Contract End Year
Discount Rate
$15,186,336
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2031
2032
2033
2034
2035
2036
2037
2038
2039
542
244
261
81
219
888
838
164
332
596
30
4,195
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
1,616
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
18,773
19,196
19,628
-
-
-
-
-
4,931
-
-
-
-
-
17,940
18,521
18,920
19,689
19,647
19,553
19,993
20,443
20,903
21,373
21,854
-
-
-
-
-
-
-
-
-
-
-
Stanton A - CC PPA
Southern Oleander
Page 2
53
2,133
168
300
467
2040
2041
1,465
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
2,278
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
2,470
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
509
5,775
5,902
6,132
6,268
6,406
6,458
6,743
6,892
7,045
7,201
7,360
Totals
Grand Total
5,253,778
2,361,148
15,186
2031
160,792
79,909
518
2032
164,180
76,974
499
2033
167,550
74,107
481
2034
171,256
71,459
463
Page 200 of 223
2035
170,808
67,238
435
2036
171,390
63,648
411
2037
170,019
59,565
384
2038
173,519
57,350
370
2039
177,097
55,220
356
2040
180,755
53,170
343
2041
184,496
51,199
330
Estimated Newberry
Withdrawal Year
Contract End Year
Discount Rate
$15,186,336
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2042
2043
2044
2045
2046
2047
2048
542
244
261
81
219
888
838
164
332
596
30
4,195
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
8,212
3,701
5,094
1,908
20,832
2,483
5,664
7,152
452
55,498
8,397
3,784
5,209
1,951
21,301
2,539
5,792
463
49,434
8,586
3,869
5,326
1,994
21,780
2,596
5,922
473
50,547
1,616
16,720
15,920
16,278
16,645
17,019
17,402
15,700
12,951
13,242
53
9,696
-
-
-
-
-
-
24,247
-
2,133
22,346
22,849
23,363
23,888
24,426
24,976
25,537
26,112
26,700
-
-
-
-
-
-
-
-
-
Stanton A - CC PPA
Southern Oleander
Page 3
168
300
467
2049
2050
1,465
3,941
871
871
871
871
871
871
871
871
2,278
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
2,470
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
509
7,523
7,690
7,861
8,035
8,213
8,396
8,582
8,773
8,968
Totals
Grand Total
5,253,778
2,361,148
15,186
2042
174,366
45,648
292
2043
160,017
39,521
250
2044
163,561
38,109
241
Page 201 of 223
2045
167,185
36,749
232
2046
170,891
35,437
224
2047
174,680
34,173
216
2048
167,416
30,898
197
2049
178,888
31,146
198
2050
158,081
25,966
169
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE CITY OF OCALA AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 202 of 223
All-Requirements Estimated Ocala Section 29(c)(1) Withdrawal Payment
Calculation Date:
9/30/2016
9/30/2019
Ocala Pro-Rata Share of Debt Section 29(c)(1): a percentage of FMPA's then outstanding Bonds
Ocala Pro-Rata Share of Bonds:
coincident peak for Ocala
286.561 (as of June 2015)
0.000
286.561
Ocala share:
1,158.877 (as of June 2015)
24.727%
as of 9/30/2019
to be determined
Bonds Outstanding:
Bond Maturity
Bonds
Bond Payment or
Bond Principal
Liability
Bond Interest
Liability
10/1/2020
5,765,000
5.250%
1,425,538.83
11/1/2019
1,430,000
6,256
10/1/2021
6,045,000
5.250%
1,494,775.76
11/1/2019
1,495,000
6,541
10/1/2022
3,580,000
5.250%
885,243.54
11/1/2019
890,000
3,894
10/1/2023
3,770,000
5.250%
932,225.74
11/1/2019
935,000
4,091
10/1/2024
3,005,000
945,000
4.750%
5.250%
743,060.57
233,674.62
11/1/2019
11/2/2019
745,000
235,000
2,949
1,028
10/1/2026
2,195,000
630,000
4.750%
5.000%
542,768.04
155,783.08
11/1/2019
11/2/2019
545,000
160,000
2,157
667
10/1/2027
3,580,000
5.000%
885,243.54
11/1/2019
890,000
3,708
10/1/2028
6,730,000
5.000%
1,664,158.95
11/1/2019
1,665,000
6,938
10/1/2029
370,000
6,135,000
5.250%
5.000%
91,491.65
1,517,030.48
11/1/2019
11/2/2019
95,000
1,520,000
416
6,333
10/1/2030
395,000
6,535,000
5.250%
5.000%
97,673.52
1,615,940.38
11/1/2019
11/2/2019
100,000
1,620,000
438
6,750
10/1/2031
545,000
8,930,000
5.250%
5.000%
134,764.73
2,208,163.36
11/1/2019
11/2/2019
135,000
2,210,000
591
9,208
36,120,161.98
11/1/2019
36,125,000
120,417
59,155,000
10/01/35
Page 203 of 223
1
10/01/30
6,923,692.51
11/1/2019
6,925,000
26,152
2
10,385,538.76
11/1/2019
10,390,000
53,292
2
10,385,538.76
11/1/2019
10,390,000
38,978
2
1,640,000
2,733
10/01/25
10/01/30
10/1/2023
6,615,000
2.000%
1,635,722.35
11/1/2019
10/1/2020
1,000,000
5,235,000
4.000%
5.000%
247,274.73
1,294,483.22
10/1/2020
10/1/2020
250,000
1,295,000
10,000
64,750
10/1/2021
6,535,000
5.000%
1,615,940.38
10/1/2021
1,620,000
162,000
10/1/2022
6,865,000
5.000%
1,697,541.04
10/1/2022
1,700,000
255,000
10/1/2023
7,205,000
5.000%
1,781,614.45
10/1/2023
1,785,000
357,000
10/1/2024
7,565,000
5.000%
1,870,633.35
10/1/2024
1,875,000
468,750
10/1/2025
1,250,000
3.000%
309,093.42
10/1/2025
310,000
55,800
6,695,000
5.000%
1,655,504.33
10/1/2025
1,660,000
498,000
10/1/2026
8,315,000
5.000%
2,056,089.40
10/1/2025
2,060,000
618,000
10/1/2027
1,735,000
3.250%
429,021.66
10/1/2025
430,000
83,850
7,000,000
5.000%
1,730,923.13
10/1/2025
1,735,000
520,500
10/1/2028
9,140,000
5.000%
2,260,091.05
10/1/2025
2,265,000
679,500
10/1/2029
9,595,000
5.000%
2,372,601.06
10/1/2025
2,375,000
712,500
10/1/2030
10,075,000
5.000%
2,491,292.93
10/1/2025
2,495,000
748,500
10/1/2031
10,580,000
5.000%
2,616,166.67
10/1/2025
2,620,000
786,000
98,790,000
10/1/2020
38,415,000
5.00%
9,499,058.84
10/1/2025
9,500,000
475,000
10/1/2021
40,330,000
5.00%
9,972,589.96
10/1/2025
9,975,000
997,500
10/1/2022
26,720,000
5.00%
6,607,180.85
10/1/2025
6,610,000
991,500
10/1/2023
27,975,000
5.00%
6,917,510.64
10/1/2025
6,920,000
1,384,000
10/1/2024
29,355,000
5.00%
7,258,749.77
10/1/2025
7,260,000
1,815,000
10/1/2026
4,500,000
4.00%
1,112,736.30
10/1/2025
1,115,000
267,600
18,375,000
5.00%
4,543,673.21
10/1/2025
4,545,000
1,363,500
10/1/2027
27,260,000
5.00%
6,740,709.20
10/1/2025
6,745,000
2,023,500
10/1/2028
45,110,000
5.00%
11,154,563.18
10/1/2025
11,155,000
3,346,500
Page 204 of 223
10/1/2029
48,475,000
5.00%
11,986,642.65
10/1/2025
11,990,000
3,597,000
10/1/2030
51,345,000
5.00%
12,696,321.13
10/1/2025
12,700,000
3,810,000
10/1/2031
20,000,000
3.00%
4,945,494.65
10/1/2025
4,950,000
891,000
46,260,000
5.00%
11,438,929.12
10/1/2025
11,440,000
3,432,000
424,120,000
846,753,000
ARP Line of Credit
$100 MM
5,000,000.00
1,236,373.66
209,520,000
Estimated Payment Calculation for the City of Ocala:
210,756,374
30,717,786
241,474,160
Page 205 of 223
3
?
30,717,786
Estimated Ocala
Withdrawal Year
Contract End Year
Discount Rate
Page 1
$554,032,778
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2020
2021
2022
2023
2024
2025
2026
2027
2028
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
16,963
6,922
10,696
2,564
6,958
28,261
36,577
4,795
12,569
26,144
1,054
153,504
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
59,090
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
16,415
16,784
17,162
1,942
-
-
-
-
-
-
-
-
-
-
-
75,271
22,251
23,783
24,133
34,250
24,928
25,307
24,816
19,600
16,384
16,994
17,589
Stanton A - CC PPA
Southern Oleander
7,320
13,152
20,472
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
51,717
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
88,337
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
25,886
26,073
26,626
87,164
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
16,535
4,500
4,599
4,700
4,803
4,029
4,118
4,208
4,300
4,544
4,644
5,650
Totals
Ocala Costs (2019 Dollars - $000)
Grand Total
5,253,778
2,361,148
554,033
2020
164,147
154,856
36,568
2021
168,410
149,884
35,374
2022
167,905
140,976
33,265
2023
222,078
175,907
41,374
Page 206 of 223
2024
162,433
121,379
28,459
2025
165,228
116,479
27,307
2026
167,132
111,152
26,050
2027
164,442
103,173
24,150
2028
153,829
91,051
21,277
2029
2030
2029
153,531
85,731
20,025
2030
157,696
83,072
19,385
Estimated Ocala
Withdrawal Year
Contract End Year
Discount Rate
Page 2
$554,032,778
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2031
2032
2033
2034
2035
2036
2037
2038
2039
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
16,963
6,922
10,696
2,564
6,958
28,261
36,577
4,795
12,569
26,144
1,054
153,504
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
59,090
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
18,773
19,196
19,628
1,942
-
-
-
-
-
4,931
-
-
-
-
-
75,271
17,940
18,521
18,920
19,689
19,647
19,553
19,993
20,443
20,903
21,373
21,854
Stanton A - CC PPA
Southern Oleander
7,320
13,152
20,472
-
-
-
-
-
-
-
-
-
-
-
51,717
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
88,337
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
87,164
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
16,535
5,775
5,902
6,132
6,268
6,406
6,458
6,743
6,892
7,045
7,201
7,360
Totals
Grand Total
5,253,778
2,361,148
554,033
2031
160,792
79,909
18,645
2032
164,180
76,974
17,959
2033
167,550
74,107
17,287
2034
171,256
71,459
16,669
Page 207 of 223
2035
170,808
67,238
15,696
2036
171,390
63,648
14,853
2037
170,019
59,565
13,930
2038
173,519
57,350
13,411
2039
177,097
55,220
12,912
2040
2041
2040
180,755
53,170
12,432
2041
184,496
51,199
11,971
Estimated Ocala
Withdrawal Year
Contract End Year
Discount Rate
Page 3
$554,032,778
2019
2050
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2042
2043
2044
2045
2046
2047
2048
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
16,963
6,922
10,696
2,564
6,958
28,261
36,577
4,795
12,569
26,144
1,054
153,504
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
8,212
3,701
5,094
1,908
20,832
2,483
5,664
7,152
452
55,498
8,397
3,784
5,209
1,951
21,301
2,539
5,792
463
49,434
8,586
3,869
5,326
1,994
21,780
2,596
5,922
473
50,547
59,090
16,720
15,920
16,278
16,645
17,019
17,402
15,700
12,951
13,242
1,942
9,696
-
-
-
-
-
-
24,247
-
75,271
22,346
22,849
23,363
23,888
24,426
24,976
25,537
26,112
26,700
Stanton A - CC PPA
Southern Oleander
7,320
13,152
20,472
-
-
-
-
-
-
-
-
-
51,717
3,941
871
871
871
871
871
871
871
871
88,337
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
87,164
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
16,535
7,523
7,690
7,861
8,035
8,213
8,396
8,582
8,773
8,968
Totals
Grand Total
5,253,778
2,361,148
554,033
2042
174,366
45,648
10,708
2043
160,017
39,521
9,345
2044
163,561
38,109
9,012
Page 208 of 223
2045
167,185
36,749
8,690
2046
170,891
35,437
8,380
2047
174,680
34,173
8,081
2048
167,416
30,898
7,308
2049
2049
178,888
31,146
7,365
2050
2050
158,081
25,966
6,145
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE CITY OF STARKE AS OF AUGUST 2016 ASSUMED WITHDRAWAL DATE: SEPTEMBER 30, 2019 ESTIMATE SUBJECT TO CHANGE Page 209 of 223
All-Requirements Estimated Starke Section 29(c)(1) Withdrawal Payment
Calculation Date:
9/30/2016
9/30/2019
Starke Pro-Rata Share of Debt Section 29(c)(1): a percentage of FMPA's then outstanding Bonds
Starke Pro-Rata Share of Bonds:
coincident peak for Starke
15.556 (as of June 2015)
1.919
13.637
Starke share:
1,158.877 (as of June 2015)
1.177%
as of 9/30/2019
to be determined
Bonds Outstanding:
Bond Maturity
Bonds
Bond Payment or
Bond Principal
Liability
Bond Interest
Liability
10/1/2020
5,765,000
5.250%
67,839.21
11/1/2019
70,000
306
10/1/2021
6,045,000
5.250%
71,134.09
11/1/2019
75,000
328
10/1/2022
3,580,000
5.250%
42,127.39
11/1/2019
45,000
197
10/1/2023
3,770,000
5.250%
44,363.20
11/1/2019
45,000
197
10/1/2024
3,005,000
945,000
4.750%
5.250%
35,361.12
11,120.22
11/1/2019
11/2/2019
40,000
15,000
158
66
10/1/2026
2,195,000
630,000
4.750%
5.000%
25,829.50
7,413.48
11/1/2019
11/2/2019
30,000
10,000
119
42
10/1/2027
3,580,000
5.000%
42,127.39
11/1/2019
45,000
188
10/1/2028
6,730,000
5.000%
79,194.78
11/1/2019
80,000
333
10/1/2029
370,000
6,135,000
5.250%
5.000%
4,353.95
72,193.16
11/1/2019
11/2/2019
5,000
75,000
22
313
10/1/2030
395,000
6,535,000
5.250%
5.000%
4,648.13
76,900.13
11/1/2019
11/2/2019
5,000
80,000
22
333
10/1/2031
545,000
8,930,000
5.250%
5.000%
6,413.25
105,083.12
11/1/2019
11/2/2019
10,000
110,000
44
458
1,718,903.30
11/1/2019
1,720,000
5,733
59,155,000
10/01/35
Page 210 of 223
1
10/01/30
329,487.94
11/1/2019
330,000
1,246
2
494,231.92
11/1/2019
495,000
2,539
2
494,231.92
11/1/2019
495,000
1,857
2
80,000
133
10/01/25
10/01/30
10/1/2023
6,615,000
2.000%
77,841.53
11/1/2019
10/1/2020
1,000,000
5,235,000
4.000%
5.000%
11,767.43
61,602.48
10/1/2020
10/1/2020
15,000
65,000
600
3,250
10/1/2021
6,535,000
5.000%
76,900.13
10/1/2021
80,000
8,000
10/1/2022
6,865,000
5.000%
80,783.38
10/1/2022
85,000
12,750
10/1/2023
7,205,000
5.000%
84,784.31
10/1/2023
85,000
17,000
10/1/2024
7,565,000
5.000%
89,020.58
10/1/2024
90,000
22,500
10/1/2025
1,250,000
3.000%
14,709.28
10/1/2025
15,000
2,700
6,695,000
5.000%
78,782.92
10/1/2025
80,000
24,000
10/1/2026
8,315,000
5.000%
97,846.15
10/1/2025
100,000
30,000
10/1/2027
1,735,000
3.250%
20,416.49
10/1/2025
25,000
4,875
7,000,000
5.000%
82,371.99
10/1/2025
85,000
25,500
10/1/2028
9,140,000
5.000%
107,554.28
10/1/2025
110,000
33,000
10/1/2029
9,595,000
5.000%
112,908.46
10/1/2025
115,000
34,500
10/1/2030
10,075,000
5.000%
118,556.82
10/1/2025
120,000
36,000
10/1/2031
10,580,000
5.000%
124,499.37
10/1/2025
125,000
37,500
98,790,000
10/1/2020
38,415,000
5.00%
452,045.69
10/1/2025
455,000
22,750
10/1/2021
40,330,000
5.00%
474,580.31
10/1/2025
475,000
47,500
10/1/2022
26,720,000
5.00%
314,425.64
10/1/2025
315,000
47,250
10/1/2023
27,975,000
5.00%
329,193.76
10/1/2025
330,000
66,000
10/1/2024
29,355,000
5.00%
345,432.81
10/1/2025
350,000
87,500
10/1/2026
4,500,000
4.00%
52,953.42
10/1/2025
55,000
13,200
18,375,000
5.00%
216,226.46
10/1/2025
220,000
66,000
10/1/2027
27,260,000
5.00%
320,780.05
10/1/2025
325,000
97,500
10/1/2028
45,110,000
5.00%
530,828.61
10/1/2025
535,000
160,500
Page 211 of 223
10/1/2029
48,475,000
5.00%
570,426.00
10/1/2025
575,000
172,500
10/1/2030
51,345,000
5.00%
604,198.52
10/1/2025
605,000
181,500
10/1/2031
20,000,000
3.00%
235,348.53
10/1/2025
240,000
43,200
46,260,000
5.00%
544,361.15
10/1/2025
545,000
163,500
424,120,000
846,753,000
ARP Line of Credit
$100 MM
5,000,000.00
58,837.13
10,080,000
Estimated Payment Calculation for the City of Starke:
10,138,837
1,475,709
11,614,546
Page 212 of 223
3
?
1,475,709
Estimated Starke
Withdrawal Year
Contract End Year
Discount Rate
Page 1
$17,440,914
2019
2035
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
2020
2021
2022
2023
2024
2025
2026
2027
2028
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
563
254
313
71
349
993
812
170
354
664
31
4,575
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
1,901
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
16,415
16,784
17,162
-
-
-
-
-
-
-
-
-
-
-
2,404
21,719
23,210
23,551
33,301
24,325
24,694
24,211
19,101
15,949
16,541
17,120
279
490
769
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
1,863
1,863
-
-
2,039
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
17,768
16,470
16,470
2,669
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
25,886
26,073
26,626
2,567
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
23,981
24,520
25,072
517
4,448
4,546
4,645
4,747
3,972
4,059
4,148
4,239
4,469
4,567
5,572
Stanton A - CC PPA
Southern Oleander
Totals
Starke Costs (2019 Dollars - $000)
-
Grand Total
5,243,836
2,354,758
17,441
2020
163,563
154,304
1,579
2021
167,783
149,326
1,530
2022
167,269
140,442
1,439
2023
221,074
175,111
1,787
Page 213 of 223
2024
161,773
120,886
1,243
2025
164,557
116,006
1,193
2026
166,467
110,710
1,138
2027
163,882
102,822
1,054
2028
153,319
90,749
936
2029
2030
2029
153,002
85,435
882
2030
157,148
82,784
855
Estimated Starke
Withdrawal Year
Contract End Year
Discount Rate
$17,440,914
2019
2035
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2031
2032
2033
2034
2035
2036
2037
2038
2039
563
254
313
71
349
993
812
170
354
664
31
4,575
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
1,901
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
18,773
19,196
19,628
-
-
-
-
-
4,931
-
-
-
-
-
17,462
18,027
18,417
19,162
19,123
19,553
19,993
20,443
20,903
21,373
21,854
-
-
-
-
-
-
-
-
-
-
-
Stanton A - CC PPA
Southern Oleander
Page 2
2,404
279
490
769
2040
2041
2,039
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
12,881
12,881
12,881
2,669
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
28,929
29,546
30,177
2,567
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
30,631
31,320
32,025
517
5,695
5,820
6,049
6,182
6,319
6,458
6,743
6,892
7,045
7,201
7,360
Totals
Grand Total
5,243,836
2,354,758
17,441
2031
160,234
79,631
823
2032
163,604
76,704
792
2033
166,962
73,848
763
2034
170,643
71,204
735
Page 214 of 223
2035
170,196
66,997
691
2036
171,390
63,648
‐
2037
170,019
59,565
‐
2038
173,519
57,350
‐
2039
177,097
55,220
‐
2040
180,755
53,170
‐
2041
184,496
51,199
‐
Estimated Starke
Withdrawal Year
Contract End Year
Discount Rate
$17,440,914
2019
2035
2019
2.25%
6.00%
Projected Costs
Allocated
Costs
(2019 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2042
2043
2044
2045
2046
2047
2048
563
254
313
71
349
993
812
170
354
664
31
4,575
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
8,212
3,701
5,094
1,908
20,832
2,483
5,664
7,152
452
55,498
8,397
3,784
5,209
1,951
21,301
2,539
5,792
463
49,434
8,586
3,869
5,326
1,994
21,780
2,596
5,922
473
50,547
1,901
16,720
15,920
16,278
16,645
17,019
17,402
15,700
12,951
13,242
-
9,696
-
-
-
-
-
-
24,247
-
2,404
22,346
22,849
23,363
23,888
24,426
24,976
25,537
26,112
26,700
-
-
-
-
-
-
-
-
-
Stanton A - CC PPA
Southern Oleander
Page 3
279
490
769
2049
2050
2,039
3,941
871
871
871
871
871
871
871
871
2,669
26,200
25,133
25,665
26,209
26,765
27,333
23,805
18,236
18,629
2,567
32,745
33,482
34,236
35,006
35,794
36,599
37,422
38,264
39,125
517
7,523
7,690
7,861
8,035
8,213
8,396
8,582
8,773
8,968
Totals
Grand Total
5,243,836
2,354,758
17,441
2042
174,366
45,648
‐
2043
160,017
39,521
‐
2044
163,561
38,109
‐
Page 215 of 223
2045
167,185
36,749
‐
2046
170,891
35,437
‐
2047
174,680
34,173
‐
2048
167,416
30,898
‐
2049
178,888
31,146
‐
2050
158,081
25,966
‐
ESTIMATED SECTION 29 (C) WITHDRAWAL PAYMENT FOR THE CITY OF VERO BEACH AS OF AUGUST 2016 WITHDRAWAL DATE: SEPTEMBER 30, 2016 ESTIMATE SUBJECT TO CHANGE Page 216 of 223
Estimated Vero Beach
Withdrawal Year
Contract End Year
Discount Rate
$33,411,871
2016
2046
2016
2.25%
6.00%
Projected Costs
Allocated
Costs
(2016 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2017
2018
2019
2020
2021
2022
2023
2024
2025
2,594
7,540
1,656
1,867
2,327
15,984
4,120
1,857
2,556
521
2,590
8,107
6,659
1,246
2,842
6,064
179
36,739
4,213
1,898
2,613
533
2,648
8,289
6,808
1,274
2,906
6,200
206
37,589
4,307
1,941
2,672
545
2,708
8,476
6,962
1,303
2,971
6,340
237
38,461
4,404
1,985
2,732
557
2,769
8,666
7,118
1,332
3,038
6,483
243
39,326
4,503
2,029
2,793
569
2,831
8,861
7,278
1,362
3,106
6,628
248
40,211
4,605
2,075
2,856
582
2,895
9,061
7,442
1,392
3,176
6,778
254
41,116
4,708
2,122
2,921
595
2,960
9,265
7,610
1,424
3,248
6,930
259
42,041
4,814
2,170
2,986
609
3,027
9,473
7,781
1,456
3,321
7,086
265
42,987
4,923
2,218
3,053
622
3,095
9,686
7,956
1,489
3,395
7,245
271
43,954
5,033
2,268
3,122
636
3,164
9,904
8,135
1,522
3,472
7,408
277
44,943
5,147
2,319
3,192
651
3,236
10,127
8,318
1,556
3,550
7,575
283
45,954
5,868
13,467
12,928
13,315
12,699
14,047
14,364
56,012
15,017
15,355
15,701
16,054
-
-
-
-
-
-
-
-
-
-
-
-
27,401
30,298
27,452
22,251
23,783
24,133
34,250
24,928
25,307
24,816
19,600
582
1,536
2,119
7,334
8,826
16,160
7,532
8,826
16,358
7,735
8,826
16,561
7,944
8,826
16,770
8,158
8,826
16,984
8,379
8,826
17,204
8,605
8,826
17,431
8,826
8,826
8,826
8,826
8,826
8,826
8,826
8,826
11
19,738
19,738
19,738
19,236
19,689
19,689
19,689
19,689
19,689
19,614
19,614
8,424
31,221
31,098
29,475
29,294
28,573
25,715
26,397
25,018
25,547
26,088
26,641
-
18,774
19,197
19,629
20,071
20,522
20,984
21,456
21,939
22,432
22,937
23,453
882
4,217
4,309
4,404
4,500
4,599
4,700
4,803
4,029
4,118
4,208
4,300
124
Stanton A - CC PPA
Southern Oleander
Totals
Vero Beach Costs (2016 Dollars - $000)
ARP Termination Pmt Calcs Draft 081216.xlsx
Page 1
Grand Total
5,257,659
2,361,366
33,412
2017
167,717
158,224
2,125
2018
171,514
152,647
2,009
2019
169,034
141,924
1,925
2020
164,147
130,020
1,825
Page 217 of 223
2021
168,410
125,846
1,754
2022
167,905
118,367
1,643
2023
222,078
147,695
2,200
2024
162,433
101,913
1,430
2025
165,228
97,798
1,376
2026
2027
2026
167,132
93,325
1,324
2027
164,442
86,626
1,274
Withdrawal Year
Contract End Year
Discount Rate
$33,411,871
2016
2046
2016
2.25%
6.00%
Projected Costs
Allocated
Costs
(2016 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2028
2029
2030
2031
2032
2033
2034
2035
2036
2,594
7,540
1,656
1,867
2,327
15,984
5,262
2,371
3,264
665
3,308
10,355
8,505
1,591
3,630
7,746
290
46,988
5,381
2,425
3,338
680
3,383
10,588
8,696
1,627
3,711
7,920
296
48,046
5,502
2,479
3,413
696
3,459
10,826
8,892
1,664
3,795
8,098
303
49,127
5,626
2,535
3,490
711
3,537
11,070
9,092
1,701
3,880
8,280
310
50,232
5,752
2,592
3,568
727
3,616
11,319
9,297
1,740
3,968
8,467
317
51,362
5,882
2,651
3,648
744
3,698
11,574
9,506
1,779
4,057
8,657
324
52,518
6,014
2,710
3,730
760
3,781
11,834
9,720
1,819
4,148
8,852
331
53,699
6,149
2,771
3,814
812
2,681
12,336
10,233
1,860
4,242
9,051
339
54,288
6,288
2,833
3,900
915
13,209
11,208
1,901
4,337
9,255
346
54,193
6,429
2,897
3,988
936
13,506
11,460
1,944
4,435
9,463
354
55,413
6,574
2,962
4,078
957
13,810
11,718
1,988
4,534
9,676
362
56,659
5,868
16,415
16,784
17,162
17,548
17,943
18,347
18,759
18,529
17,561
17,956
18,360
-
-
-
-
-
-
-
-
4,931
-
-
-
16,384
16,994
17,589
17,940
18,521
18,920
19,689
19,647
19,553
19,993
20,443
582
1,536
2,119
1,863
1,863
-
-
-
-
-
-
-
-
-
-
11
17,768
16,470
16,470
16,470
16,470
16,470
16,470
15,304
12,881
12,881
12,881
8,424
25,886
26,073
26,626
27,191
27,769
28,360
28,964
28,611
27,158
27,735
28,326
-
23,981
24,520
25,072
25,636
26,213
26,803
27,406
28,023
28,653
29,298
29,957
882
4,544
4,644
5,650
5,775
5,902
6,132
6,268
6,406
6,458
6,743
6,892
124
Stanton A - CC PPA
Southern Oleander
Totals
Page 2
Grand Total
5,257,659
2,361,366
33,412
2028
153,829
76,448
1,137
2029
153,531
71,981
1,073
2030
157,696
69,749
1,035
2031
160,792
67,093
998
Page 218 of 223
2032
164,180
64,629
963
2033
167,550
62,222
928
2034
171,256
59,999
895
2035
170,808
56,454
869
2036
171,390
53,440
853
2037
2038
2037
170,019
50,012
823
2038
173,519
48,152
794
Withdrawal Year
Contract End Year
Discount Rate
$33,411,871
2016
2046
2016
2.25%
6.00%
Projected Costs
Allocated
Costs
(2016 $000)
Stanton 1 [1]
Stanton 2
Stanton A [1]
Cane Island 4 [2]
Treasure Coast 1
Other O&M Costs
Sub Total O&M Costs
2039
2040
2041
2042
2043
2044
2045
2,594
7,540
1,656
1,867
2,327
15,984
6,722
3,029
4,169
979
14,121
11,982
2,033
4,636
9,894
370
57,934
6,873
3,097
4,263
1,001
14,439
12,251
2,078
4,741
10,116
379
59,238
7,028
3,167
4,359
1,023
14,764
12,527
2,125
4,847
10,344
387
60,571
7,186
3,238
4,457
1,438
4,555
16,219
2,173
4,956
10,576
396
55,194
7,347
3,311
4,558
1,707
18,639
2,222
5,068
10,814
405
54,071
7,513
3,386
4,660
1,745
19,058
2,272
5,182
11,058
414
55,287
7,682
3,462
4,765
1,784
19,487
2,323
5,299
11,307
423
56,531
7,854
3,540
4,872
1,825
19,926
2,375
5,418
11,561
433
57,803
8,031
3,619
4,982
1,866
20,374
2,429
5,540
11,821
442
59,104
5,868
18,773
19,196
19,628
16,720
15,920
16,278
16,645
17,019
17,402
-
-
-
9,696
-
-
-
-
-
20,903
21,373
21,854
22,346
22,849
23,363
23,888
24,426
24,976
-
-
-
-
-
-
-
-
-
11
12,881
12,881
12,881
3,941
871
871
871
871
871
8,424
28,929
29,546
30,177
26,200
25,133
25,665
26,209
26,765
27,333
-
30,631
31,320
32,025
32,745
33,482
34,236
35,006
35,794
36,599
882
7,045
7,201
7,360
7,523
7,690
7,861
8,035
8,213
8,396
124
Stanton A - CC PPA
Southern Oleander
582
1,536
2,119
Totals
Page 3
Grand Total
5,257,659
2,361,366
33,412
2039
177,097
46,363
765
2040
180,755
44,643
738
2041
184,496
42,987
712
Page 219 of 223
2042
174,366
38,327
583
2043
160,017
33,182
358
2044
163,561
31,997
346
2045
167,185
30,855
333
2046
2046
170,891
29,754
321
2047
2047
174,680
28,692
‐
AGENDA ITEM 11– OTHER INFORMATION
a) FYI – Invoice Summary Report from Spiegel and
McDiarmid
Executive Committee
August 25, 2016
Page 220 of 223
TO:
FROM:
DATE:
Accounting Department
ITEM:
EC 11(a) – Invoice Summary Report of Spiegel & McDiarmid for July 2016.
August 16, 2016
Introduction
•
Historically, the paid invoices for Spiegel & McDiarmid were included in the
Agenda packages for review at the request of the members. At the July 30,
2002 FMPA Executive Committee Meeting at the Breakers Hotel in Palm Beach,
Florida, it was requested that a summary be developed and used in the Agenda
package.
•
At the December 12, 2003 FMPA Executive Committee and Board Meeting it
was requested that a brief description of the invoice charges be included in this
summary.
•
The following summary schedule is the result of those requests.
Invoice Number
Invoice Date
Description
Amount Paid
210209201
June 10, 2016
FPL Transmission
FKEC Losses/Key West
326.25
2175.00
210209229
June 21, 2016
General
1275.95
TOTAL PAID
RM/DF
Page 221 of 223
$
3,777.20
AGENDA ITEM 12– MEMBER COMMENTS
Executive Committee
August 25, 2016
Page 222 of 223
AGENDA ITEM 13– ADJOURNMENT
Executive Committee
August 25, 2016
Page 223 of 223

ARP EC Agenda Package - FMPA Member Portal

Transcription

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