Puerto Rico Electric Power Authority Integrated Resource ... Integrado de Recurs… · Page 5 August 21, 2015 Siemens Industry, Inc PREPA’s IRP According to Act 57 – 2014, PREPA’s

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Puerto Rico Electric Power Authority

Integrated Resource Plan 2016 - 2035

San Juan August 21, 2015

Page 2 Siemens Industry, Inc August 21, 2015

This presentation provides a summary of the key recommendations of the

Integrated Resource Plan (IRP) proposed for PREPA for the period from 2016

to 2035 and the underlying analysis and assumptions, especially focused in:

The IRP report at PREPA’s website (http://www.aeepr.com/Aeees/ley57.asp)

also includes:

Core Objective and Agenda

■ Supply Portfolios and Futures; generation expansion plan.

■ Transmission Analysis; transmission expansion plan.

• Demand Forecast

• Fuel Forecast

• Fuel Infrastructure

• Demand Response

• Environmental Compliance

■ Renewable penetration for multiple years, supply portfolio details and

performance, transmission study details, distributed generation.

■ Complementary Studies:


What is an Integrated Resource Plan?

■ An Integrated Resource Plan (IRP) is:

A long term planning assessment, typically covering a 20 year period, by which

an electrical service company finds the optimal plan to supply the current and

forecasted electrical demand, meeting regulatory requirements, reliability

criteria, and the least cost possible.

Usually subject to public review and final regulatory approval.

Essential to effectively plan any decision to replace, retire, or build new

generation, which are long term decisions (5 – 10 years) and are subject to

intense regulatory, financial, and environmental controls.


PREPA’s IRP

■ PREPA’s IRP is a requirement of Act 57 – 2014:

PREPA must present an IRP to the Puerto Rico Energy Commission (PREC) by

July 2015.

The IRP must be reviewed and updated at least every three years.

■ Developing an IRP is an essential part of the restructuring process that

PREPA is currently undergoing:

The results of the IRP analysis and studies are used in the development of the

Business Plan to be prepared as part of the restructuring process.


PREPA’s IRP

■ According to Act 57 – 2014, PREPA’s IRP shall include the following,

among others:

Evaluation of supply resources to satisfy Puerto Rico’s energy demand over a

20 year planning horizon

Current generation system evaluation, including improvements, replacements,

and retirements, if necessary

Interconnection of renewable energy projects to meet law requirements,

including distributed generation and utility scale producers

Energy source diversification, stabilize energy costs, improve system reliability

and stability

Electric transmission system capacity and reliability

Evaluation of energy efficiency (EE) and demand side management (DSM)

programs

Compliance with environmental regulations


PREPA’s IRP

■ Main issues affecting PREPA’s IRP:

Environmental compliance:

• MATS Rule

• Clean Power Plan (CO2)

Regulatory compliance

• PREC rules, as per Act 57-2014

PREPA’s restructuring process

• Forbearance Agreement with creditors

• Business Plan

System costs, reliability, and safety

• Renewable sources integration

• Generation, transmission and distribution infrastructure

• Fuel diversification

• Energy demand forecast


Puerto Rico Electric Power Authority Integrated Resource Plan 2016 – 2035

Supply Portfolios and Futures; generation

expansion plan



■ The IRP analysis was designed to identify solutions to key challenges

that PREPA will face over a planning horizon from FY2016 to FY2035,

including:

Efficient and cost effective supply of present and future load.

Renewable generation integration.

Environmental Compliance; MATS, Clean Power Plan and GHG

regulation.

Flexibility to deal with unknowns.

■ Extensive technical studies were carried out using specialized tools.

■ Siemens team worked closely with PREPA management and its

financial advisors throughout the analysis ensuring the use of best

information available and timely sharing of results.

Introduction


■ Siemens used a systematic approach to identify the best alternative for the

formulation of the IRP

Overall Procedure

Future Formulation: A Future is defined as a set of consistent assumptions

that describe the future external environment in which PREPA might be

expected to operate. Are used to assess performance of options.

1

Portfolio Formulation: A Portfolio is the set of generation resources that

PREPA can deploy to meet customer demand, within RPS and environmental

compliance, and system reliability requirements. 2


■ Support studies are carried out to delineate the Futures and Portfolios in

detail which are the input for the PROMOD’s Security Constrained Unit

Commitment / Security Constrained Economic Dispatch

Overall Procedure

Futures

Detailed

Definition 1

Portfolio

Detailed

Definition

2

• Demand Forecast

• Fuel Forecast

• RPS Targets


• Capital

5

• Portfolio design criteria

• Existing Fleet

• Thermal Options

• Renewable Projects

4

PROMOD IV

SCUC/SCED

Preliminary Transmission Study:

Evaluation of minimum generation in the

North & Minimum Reinforcements

3


■ PROMOD outputs for each combination of Portfolio – Future (PXFY) are

used to:

Evaluate the Portfolio’s Performance Metrics and

Input to the final transmission analysis / verification.

Overall Procedure

PROMOD IV

SCUC/SCED Portfolio-Future: Generation

Dispatch

PSS®E

Transmission

Assessment

8

Additional

Transmission

Investments

Portfolio-Future: fuel costs,

O&M, Curtailment, LOLH,

emissions

Portfolio Analysis

• Metrics Formulation

• Performance Assessment

• Selection


■ Main components of the Four Futures

considered on the IRP:

Four Futures

Note: Supporting specialized studies and

analysis were performed regarding these main

components.

Futures

Detailed

Definition 1

• Demand Forecast

• Fuel Forecast

• RPS Targets


• Capital

5


■ The table below is a summary of the Futures.

Four Futures

Summary

Future 1 Future 2 Future 3 Future 4

AOGP yes no yes yes

Gas to North no no yes no

Fuel Prices Costa Sur, Eco and Aguirre gas prices

converge

Price deferential maintained

Costa Sur, Eco and Aguirre gas prices

converge

Costa Sur, Eco and Aguirre gas prices

converge

Capital Costs Limited capital Limited capital Increased capital Limited capital

Load Gross PREPA forecast PREPA forecast PREPA forecast PREPA reduced forecast

RPS

10% 2020 12% 2025 15% 2035

10% 2020 12% 2025 15% 2035

10% 2020 12% 2025 15% 2035

Same installations as other Futures / Results differ due to reduced

sales

Distributed Generation PREPA forecast 350 MW

by 2035

PREPA forecast 350 MW by 2035

PREPA forecast 350 MW by 2035

Increased to 600 MW by 2035

Government Energy Efficiency (EE)

80% of mandate achieved





■ Futures 1, 3, and 4:

AOGP will come online on July 1, 2017 and supply gas needs for Aguirre 1&2

combined cycle and Aguirre 1&2 steam units.

No gas will be available in the North, except Future 3.

Four Futures

Fuels Details

Delivered gas pricing at Costa

Sur, Aguirre and EcoEléctrica

plants will converge due to

expected gas-on-gas competition

after AOGP comes online in 2017.

• Costa Sur gas no longer linked

to No.6 nor EcoEléctrica’s spot

to avoided costs.

■ Future 2:

No gas is available in the North

and Aguirre.

0

2

4

6

8

10

12

14

16

18

20

22

24

26

Ap

r-1

5

Jan

-16

Oct

-16

Jul-

17

Ap

r-1

8

Jan

-19

Oct

-19

Jul-

20

Ap

r-2

1

Jan

-22

Oct

-22

Jul-

23

Ap

r-2

4

Jan

-25

Oct

-25

Jul-

26

Ap

r-2

7

Jan

-28

Oct

-28

Jul-

29

Ap

r-3

0

Jan

-31

Oct

-31

Jul-

32

Ap

r-3

3

Jan

-34

Oct

-34

Jul-

35

20

15

$ /

MM

BTU

Costa Sur Future 2

EcoElectrica Future 2 Spot Fuel Price

EcoElectrica Future 1,3 & 4 Spot Fuel Price

Nat Gas CS 5&6 Future 1,3,&4

Nat Gas Aguirre


■ Limit the priority of capital spending in the first 10 years (FY 2016 - 2025) to:

MATS compliance; new generation for retirement of PSSP and SJSP.

System reliability (generation in the North).

Integration of renewables (issues identified).

Four Futures

CapEx & Demand

2,500

2,600

2,700

2,800

2,900

3,000

3,100

3,200

3,300

3,400

Pe

ak D

em

and

(M

W)

Fiscal Year

Projection: PREPA P-1F-2 PREPA Base

■ PREPA’s official load

forecast less Government

energy efficiency at 80% of

Law 57’s target; 150 MW

reduction.

With Gov. Efficiency

Base


■ Reduced and delayed RPS milestones were selected for all Futures:

10 percent renewable generation of energy sales by 2020,

12 percent by 2025, and

15 percent by 2035.

■ A sensitivity to 20% by 2035 was included as well as one for renewable

freeze for the selected portfolio and all Futures.

■ AES Contract renewed after 2027 was assumed for all Futures and

Portfolios, but a sensitivity of no-renewal was carried out for the selected

portfolio and all Futures.

Four Futures

Sensitivities


■ Three portfolios were selected for the

IRP study.

■ Main criteria for the formulation of the

Portfolios:

Three Portfolios


■ Supply Portfolio 1 focuses on minimizing investments by pursuing

repowering initiatives and utilizing existing equipment to the extent

possible.

AG 1&2 and CS 5&6 Repowering in Future 1 and Future 4 after 2025. On

Future 3, from 2023 to 2026. AG CC Repower in 2021 / 2022.

Under Future 2 with no AOGP, Portfolio 1 is not feasible as Aguirre 1& 2

need to be retired.

■ Supply Portfolio 2 focuses on new builds of smaller combined cycle

units across all four Futures.

Aguirre 1&2 and Costa Sur 5&6 replaced on Future 1 after 2025. On

Future 2, Aguirre 1&2 replacement from 2020 to 2022.

AG CC Repower on 2021 / 2022.

On Future 3, Aguirre 1&2 and Costa Sur 5&6 replaced from 2023 to 2029.

On Future 4, Aguirre 1&2 replacement after 2025 (same as Future 1).

Three Supply Portfolios

Portfolio 1 & 2


■ Supply Portfolio 3 focuses on new builds of larger combined cycle units

across all four Futures.

Aguirre 1&2 and Costa Sur 5&6 Replaced on Future 1 after 2025. On Future 2,

Aguirre 1&2 replacement from 2020 to 2021.

AG CC Repower on 2021 / 2022.

On Future 3, Aguirre 1&2 and Costa Sur 5&6 replaced from 2023 to 2028. On

Future 4, Aguirre 1&2 replacement after 2025 (same as Future 1).

Three Supply Portfolios

Portfolio 3


Generating Units IRP Considerations

Aguirre 1&2 Steam Units Converted to natural gas to comply with MATS, except in Future 2

where they are retired.

Aguirre CC 1&2 First, converted to dual fuel with natural gas as primary fuel and

distillate as backup. Later, repowered.

San Juan CC 5&6 In Future 3, will be converted to dual fuel with natural gas as primary

and distillate as backup.

Palo Seco 3&4 and San

Juan 9&10 Steam Units

Continue operation burning No. 6 fuel until new generation is added

in the North, when they will be retired or designated to limited use.

Costa Sur 3&4, Palo

Seco 1&2, San Juan 7&8

Steam Units

Declared limited use or retired; hence, not considered in the study.

Generation Options for Portfolios

Existing Fleet


■ All new units selected based on the following minimum conditions:

Dual fuel (natural gas and LFO -No. 2-)

1x1 combined cycles (flexibility to locate at any desired site independently of

other capacity expansions).

Flexibility to match increases and decreases in solar and wind turbine

generation on the grid each day:

• Daily start/stop and fast start/fast ramp capability.

• Optimized to allow a lower minimum: 40% rated capacity.

Supplemental duct firing to provide flexible capacity:

• Gas turbines have excess oxygen in their exhaust and so additional fuel

can be burned to raise the temperature of exhaust gas entering the Heat

Recovery Steam Generator (HRSG).

Dual shaft options so the ST can trip and the GT can continue to run until

another unit is brought online.


New Generation



New Gen Candidates

• 1x1 combined cycle:

• MHI J-Class, G-Class, and

F-Class

• Siemens H-Class, F-Class, and

SCC-800

• GE H-Class, F-Class, and

small CC

• Alstom

• Rolls-Royce

• Single cycle:

• GE

• Rolls-Royce

• Hitachi (repower)

• Wartsila Reciprocating Engine

• Gas turbine (GT) (repower):

• GE

• Siemens

• Hitachi

• 2x1 combined cycle (repower):

• Hitachi


■ A three-step process to select technologies for portfolios:

1. Screening of available simple cycle gas turbines and combined cycle units

based on published data at standard conditions on natural gas.

2. Analysis of selected configurations at site-specific conditions on gas and

distillate fuels.

3. Selection of technologies to develop generation portfolios for analysis in

PROMOD.

■ GT Pro performance estimates were used to select configurations to incorporate in

the three Supply Portfolios

■ Selections are representative of particular technology class, but not final. Exact

sizing, configuration and performance to be optimized during project planning

and implementation

■ Selected options based on actual products as representative of the class. In all

cases, there is at least one additional unit available from a different

manufacturer for competitive bidding.

Generation Options for Portfolios New Gen Selection Process


■ Portfolio 1: Repower

North: SCC-800 (Small CC, Reciprocating, and LM6000 were considered).

South: Repowering (Aguirre CC with Hitachi H-80 GT; Aguirre and Costa

Sur Steam Units with Heavily Fired CC-Hot Windbox Repowering).

■ Portfolio 2: Smaller Flexible CC

North: SCC-800 (F – Class CC, Small CC, Reciprocating and LM6000 were

considered).

South: F – Class CC (Smaller 1x1 CC, F – Class CC or SCC-800, were

considered); Aguirre CC repowered with Hitachi H-80 GT.

■ Portfolio 3: Large Efficient CC

North: F – Class CC (Smaller 1x1 CC was considered).

South: H – Class CC (Larger 1x1 CC was considered); Aguirre CC

repowered with Hitachi H-80 GT.


Selected Options


■ Below is summary of the Options Considered for the Portfolios.

■ Capital Costs include Engineering, Procurement and Construction

(EPC) price, owner’s costs for development, permitting and

legal/contracting activities, financing cost of 2 percent and Interest

during Construction (IDC) based on the EPC duration, drawdown

schedule, and cost of debt of 6.86% (9% nominal)


Summary of Thermal Options

Repower & New Generation Configurations Fuel Unit Capacity

(MW) Heat Rate

(BTU/kWh HHV) Capital Costs ($2015/kW)

Aguirre CC 1 & 2 Gas Turbine Replacement/Repower Natural Gas 263 7,582 703

Diesel 255 7,368 726

Aguirre 1 & 2 HFCC Repower Natural Gas or

Diesel 543 9,200 320

Costa Sur 5 & 6 HFCC Repower Natural Gas 503 9,200 320

Siemens SCC-800 (Duct Fired) Natural Gas 72 8.031 1,648

Diesel 70 7,764 1,693

F Class CC (GE S107F.05) (Duct Fired) Natural Gas 369 7,310 1,001

Diesel 359 7,065 1,030

H Class CC (Siemens SCC6-8000H) (Duct Fired) Natural Gas 393 6,979 1,011

Reciprocating Engines Diesel 17 7,580 1,304

GE LM6000PG SPRINT SC Diesel 48 9,785 1,315


■ Renewable Generation projects are

included in all supply portfolios as:

Utility Scale PPOA Projects

DG Projects installed by customers

■ PPOA Projects selected to meet RPS

targets:

The RPS levels considered in the study,

10%, 12%, 15% and 20%, were modeled

using best available data on existing and

candidate projects and their location.

Renewable Generation


Projects Description

Installed

Capacity

(MW)

Approximate

Cumulative Percent

of Penetration

8 existing interconnected projects 181 3%

17 projects whose location and conditions had been

assessed and had good probability of been

interconnected

433 8%

18 PV projects whose location had been assessed

and either the project will be built or a similar project

could be built (parameters were obtained from the

Renewable Integration Study)

442 12.9%

5 generic projects close to existing projects at strong

transmission substations to reach 15% penetration 160 15%

5 generic projects close to existing projects at strong

transmission substations to reach 20% penetration 600 20%

Total Installed Capacity (MW): 1,816

Generation Options for Portfolios Utility Scale Renewable Generation (PPOA)


■ There are approximately 61 MW of DG in the system

■ It is expected that this will grow to over 300 MW by 2035 and this was included in

all Futures but in Future 4.

Generation Options for Portfolios Distributed Generation

Area Num Residencial Comercial Transmission Residential Secondary Primary Transmission Total

San Juan 1 615 1,461 93 1,494 385 2,453 6,000 12,501

Bayamón 2 777 1,088 2,749 1,582 239 2,670 1,204 10,309

Carolina 3 80 365 14 708 239 2,225 1,500 5,130

Caguas 4 215 504 2,947 1,624 609 2,991 1,000 9,891

Ponce 5 - 6 214 419 2,836 1,391 567 2,077 1,260 8,765

Arecibo 7 188 782 1,118 825 762 275 1,686 5,634

Mayagüez 8 1,932 1,202 606 1,854 1,031 1,531 500 8,655

Total 4,020 5,822 10,363 9,478 3,832 14,221 13,149 60,885

Not in Net Metering Total Net Metering Total

Base Forecast (Future 1 to 3)

Area Num Proposed Bus 2/1/2015 7/1/2015 7/1/2020 7/1/2025 7/1/2035

1 88- SJSP 12.5 13.9 28.3 40.7 66.1

2 45 -Bayamon 115 10.3 11.5 23.3 33.6 54.5

3 85 - S. Llana 5.1 5.7 11.6 16.7 27.1

4 21 - Caguas 9.9 11.0 22.4 32.2 52.3

5 - 6 8 - Jobos 8.8 9.7 19.8 28.5 46.4

7 38 - Dos Bocas 5.6 6.3 12.7 18.3 29.8

8 277 Mayaguz TC 8.7 9.6 19.6 28.2 45.8

Total Base 60.9 67.6 137.7 198.3 322.1


■ For Future 4 the DG is expected to almost double by the end of FY 2035.

■ The combination of PPOA generation and DG results in much

higher levels of penetration than those corresponding only to the

PPOA projects, which is shown next for 20% penetration.

Generation Options for Portfolios Distributed Generation

Area Num Proposed Bus 2/1/2015 7/1/2015 7/1/2020 7/1/2025 7/1/2035

1 88- SJSP 12.5 13.9 36.4 62.8 116.1

2 45 -Bayamon 115 10.3 11.5 30.0 51.8 95.8

3 85 - S. Llana 5.1 5.7 14.9 25.8 47.7

4 21 - Caguas 9.9 11.0 28.8 49.7 91.9

5 - 6 8 - Jobos 8.8 9.7 25.5 44.0 81.4

7 38 - Dos Bocas 5.6 6.3 16.4 28.3 52.3

8 277 Mayaguz TC 8.7 9.6 25.2 43.5 80.4

Total Increased 60.9 67.6 177.3 306.0 565.6


■ A 20% RPS Sensitivity was carried out for 2035 under all Futures:

This implies 23% renewable penetration and that 68% of the peak could be

supplied from renewable for Future 1 to 3. For Future 4 the values are 25%

and 75%, respectively.

Futures 1 to 3 Future 4

Generation Options for Portfolios 20% Penetration

Peak Generation Total 2,894

Sales + Net Metering 16,544,075 Energy DG (589 MW) @ 21 % Capacity Factor 1,083,919

Net Sales 15,460,156

Target Penetration 20%

Target PPOA Energy 3,092,031

PPOA PV + Wind MW in Projects 1,056

Add PV @ 21% for required penetration 525

Total PPOA 1,582

Average Capacity Factor 22%

DG 589

Total Renewable 2,171

Total % Energy from Renewable 25%

% Renewable as function of peak 75%

Year 2035 Conditions

Peak Generation Total 2,927

Sales + Net Metering 16,734,283 Energy DG (322 MW) @ 21 % Capacity Factor 592,566

Net Sales 16,141,718

Target Penetration 20%

Target PPOA Energy 3,228,344

PPOA PV + Wind MW in Projects 1,056

Add PV @ 21% for required penetration 599

Total PPOA 1,656

Average Capacity Factor 22%

DG 322

Total Renewable 1,978

Total % Energy from Renewable 23%

% Renewable as function of peak 68%


■ Other key considerations for the Portfolio

Detailed Definition:

MATS ruling exists and is applicable.

Generation expansions are selected based on its

own merits independently whether these are

ultimately developed by a private company in a

response of an RFP or PREPA.

New generation was sited at existing power plants

to take advantage of existing fuel and transmission

infrastructure and minimize the risk of delays

associated with building in greenfield.

Major expansion were located at Aguirre and Costa

Sur.

In the North, the expansion were located at Palo

Seco as primary location and San Juan as

secondary location.

Other Considerations


■ All expansion options were developed maintaining Aguirre and Costa

Sur are major supply points, for the following reasons:

Fuel diversity and competition of gas supply leading to market pricing:

• Gas in Aguirre is the main driver for the assumption that the CS gas will stop being

linked to the No. 6 and the EcoEléctrica spot price will also become aligned with the

Aguirre price.

• Beyond NG, the other fuel that PREPA may be able to count for its generation in

the long term will be expensive LFO. This may give significant market power to the

owners of a single LNG terminal in the island.

Reduced dependence on one geographical location or plant:

• Experience has shown that planners need to evaluate the impacts of loosing all

transmission lines on the same corridor or an entire transmission switchyard

(NERC – TPL 001-4, FERC 754 and NERC CIP-14).

• While loss of load is expected, the vulnerability of the system is to be assessed and

mitigation identified. This vulnerabilities are to be avoided.

Other Considerations Two main Gen complexes in the South


Reduced dependence on one geographical location or plant (cont.)

• PREPA system is designed to provide two complementary transmission corridors

South – North starting at Aguirre and Costa Sur and a North Corridor. Only one

source will deviate from this design.

– Aguirre Corridor: 4,389 MVA (39%)

– Costa Sur Corridor: 3,012 MVA (27%)

– North Corridor: 3,886 MVA (34%)

• Moving generation from Aguirre to Costa Sur was tested and only moving the two

AG CC resulted in heavy contingency overloads. Moving a generation equivalent to

AG 1 resulted in voltage collapse for 60 separate events.

Feasibility of Transmission Investments:

• Transmission investments that imply new overhead transmission lines can take a

long time to develop even under favorable circumstances.

• In the US typical timelines are 5 to 10 years after the decision is made depending

on permitting and regulatory.

• Deviating from the basic design of PREPA’s transmission system would imply

major investments at 230 kV that would make the IRP risky and of doubtful

implementation.

Other Considerations Two main Gen complexes in the South


■ Analysis of the three Portfolios under

the various Futures:

Portfolio Selection

PROMOD IV

SCUC/SCED

8

Additional

Transmission

Investments

Portfolio-Future: fuel costs,

O&M, Curtailment, LOLH,

emissions

Portfolio Analysis

•Metrics Formulation

•Performance Assessment

•Selection


■ The performance of the portfolios under various futures was assessed based

on the following main metrics:

Cost Metrics

• Capital Cost

• Total System Costs (Fuel, O&M, annualized CapEx, Purchased Power)

Operations Metrics

• Reliability (LOLH / Reserve)

• Curtailment (inability to accept renewable generation)

Environmental and Compliance Metrics

• CO2 (Clean Power Plan and GHG New Source Standard)

• Other pollutants (SOX, NOX, FPM)

Portfolio Selection

Metrics


Analysis resulted in

selection of

Portfolio 3 as the

recommended

portfolio.

Analysis resulted in

selection of

Portfolio 3 as the

recommended

portfolio.

Portfolio Selection


Future Units Considerations

1 & 4

(AOGP)

(2,196 MW)

Aguirre

Complex

Converted to gas by 2017; CC 1&2 repowered (263 MW) by 2021/2022;

Steam Units replaced by H-Class CC (787 MW) in 2026/2027.

San Juan 9&10

Palo Seco 3&4

Retired or declared limited use by mid 2021, when new F-Class CC

(359 MW) is operational in Palo Seco.

Costa Sur 5&6 Replaced by H-Class CC (787 MW) in 2030/2031.

2

(No AOGP)

(2,119 MW)

Aguirre

Complex

CC 1&2 repowered (255 MW) by mid 2020/2021; Steam Units replaced

by F-Class CC (359 MW) in mid 2021/2022.

San Juan 9&10

Palo Seco 3&4


(718 MW) are operational in Palo Seco and San Juan.


3

(AOGP +

Gas to the

North)

(2,205 MW)

Aguirre

Complex

Converted to gas by 2017; CC 1&2 repowered (263 MW) by 2021/2022;

Steam Units replaced by H-Class CC (393 MW) in 2023/2024.

San Juan 9&10

Palo Seco 3&4


(762 MW) are operational in Palo Seco and San Juan.


Portfolio Selection Portfolio 3 Overview


■ Capital Costs:

Portfolio Selection Portfolio 3 Future 1 (P3F1): Costs

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

P1F1 P2F1 P3F1

$2015 M

illio

n

Capital Costs

Generation Fuel Infrastructure Transmission

$P1F1 < $P3F1 < $P2F1

Difference is exclusively in generation and is

concentrated in years 2026-2035

■ System Costs:

Portfolio 3 has the lowest system costs

for Future 1:

• Main difference with P2F1 is the capital,

while with P1F1 is the fuel.

System Costs Unit P2F1

Total Present Value of System Costs $ million 26,930

Average Annual System Costs $ million 2,428








-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

$2015 T

ho

usan

d

P3F1 System Costs

Fuel Regasif ication f ixed costs

O&M Purchased power

Renewables Amortized capital costs

No New PPOA Revised System's Costs

■ System Costs:


0.00

2.00

4.00

6.00

8.00

10.00

12.00

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

MM

Btu

/MW

h

P3F1 System Heat Rate

System Heat Rate (Total Generation) Prepa's Fleet's Heat Rate

-

20,000,000

40,000,000

60,000,000

80,000,000

100,000,000

120,000,000

140,000,000

160,000,000

180,000,000

200,000,000

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

MM

Btu

P3F1 Thermal Generation Fuel Consumption

Coal No. 6 fuel oil No. 2 fuel oil Natural Gas

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

20

16

20

17

20

18

20

19

20

20

20

21

20

22

20

23

20

24

20

25

20

26

20

27

20

28

20

29

20

30

20

31

20

32

20

33

20

34

20

35

Tho

usa

nd

$2

01

5

Future 1 Fuel Costs

P1F1 P2F1 P3F1


With the largest units, Portfolio 3 shows higher curtailment, resulting in slightly higher

fuel costs than Portfolio 2; Portfolio 1 still has the highest fuel costs.

Portfolio 3 achieves the target RPS and the cost associated with curtailment becomes

very small once the Portfolio is fully deployed.

Portfolio Selection Portfolio 3 Future 1 (P3F1): Operations

0%1%2%3%4%5%6%7%8%9%

10%11%12%13%14%15%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

Renewable Curtailment Percentage -Future 1

P1F1 P2F1 P3F1

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

0%

5%

10%

15%

20%

25%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

$2

01

5 T

ho

us

an

d

P3F1 RPS and Renewable Penetration

Renewable Curtailment Cost RPS (PPOA/Net sales)

RPS Target Renewable Penetration

Reduced RPS Target


Portfolio 3 under Future 1 is not expected to have significant LOLH and always under the

target of 4.

The reserves are expected to stabilize at about 44% not considering the 18x21MW GTs or

Cambalache. The lowest of the 3 Portfolios:

• Note that a system like PREPA is expected to have larger reserves: ERCOT for example

has a reserve target of 13.75% and this represents 9,500 MW or 7 times the largest unit.

• In PREPA the 3 largest unit (2x450 + 410) implies 44% reserve over 3000 MW.

• For Portfolio 3 using (3x393) / (2900) = 41%

The firm reserves, correcting for unavailability are expected to stabilize at 30%.


0%

10%

20%

30%

40%

50%

60%

70%

80%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

Operating Reserve w/o GT & CambalacheFuture 1

P1F1 P3F1 P2F1

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

% R

es

erv

e

MW

P3F1 Firm Capacity and Demand

Firm Capacity Demand Firm Capacity Reserve


■ The portfolio complies with the proposed Clean Power Plan requirements and with the GHG

New Source Standard, with some adjustments as indicated below.

The Repowered Aguirre CC 1&2 have emissions over the 1000 lb/MWh due to lower dispatch

levels and this can be addressed introducing this restriction on the economic dispatch.

■ The emissions rate declines over time as the portfolio mix changes from oil fired generation

capacity to new, more efficient natural gas fired generation capacity and greater renewable

capacity. Total CO2 emissions are expected to decline by 32 percent from 1,425 lb/MWh in

2016 to 962 lb/MWh in 2035.

Portfolio Selection Portfolio 3 Future 1 (P3F1): Environmental

800

900

1,000

1,100

1,200

1,300

1,400

1,500

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

lbs

/MW

h

P3F1 CO2 Emission

CO2 Emissions (Total Generation) CO2 Emission Target (Total Generation)

Aguirre 1 CC Repower Aguirre 2 CC Repower

Aguirre H Class Train 1 Aguirre H Class Train 2

Costa Sur H Class Train 1 Costa Sur H Class Train 2

-

10

20

30

40

50

60

70

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

Mil

lio

n l

bs

P3F1 Annual Emissions

FPM Emission NOX Emission SOX Emission


1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

P2F2 P3F2

$2

01

5 M

illio

n

Capital Costs


■ Capital Costs:


$P3F2 < $P2F2

Difference is exclusively in generation and is

concentrated in years 2016-2025

■ System Costs:


for Future 2; it has both lower capital

and fuel costs.

-

200

400

600

800

1,000

1,200

1,400

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

Real 2015$ M

illio

n

Capital Cost

New Generation Existing Generation Demolition

AOGP Gas to North

Existing Generation Conversion to Gas Transmission Upgrades








-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

20

16

20

18

20

19

20

20

20

21

20

22

20

23

20

24

20

25

20

26

20

27

20

28

20

29

20

30

20

31

20

32

20

33

20

34

20

35

Tho

usa

nd

$2

01

5

Future 2 Fuel Costs

P2F2 P3F2

■ System Costs:


-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

$2

01

5 T

ho

us

an

d

P3F2 System Costs

Fuel O&M

Purchased power Renewables

Amortized capital costs No New PPOA Revised System's Costs

-

20,000,000

40,000,000

60,000,000

80,000,000

100,000,000

120,000,000

140,000,000

160,000,000

180,000,000

200,000,000

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

MM

Btu



-

2.000

4.000

6.000

8.000

10.000

12.000

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

MM

Btu

/MW

h




Curtailment is low after the retirement of Aguirre 1&2.

The lower curtailment combined with higher efficiency and higher fuel prices (LFO)

makes Portfolio 3 the best option.

The Portfolio achieves the target RPS and the cost associated with curtailment

becomes small once Aguirre 1& 2 are retired


-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

0%

5%

10%

15%

20%

25%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

$2

01

5 T

ho

us

an

ds




Reduced RPS Target

0%1%2%3%4%5%6%7%8%9%

10%11%12%13%14%15%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034


P2F2 P3F2



target of 4.


Cambalache. The lowest of the 3 Portfolios and in line with what we would expect.


0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034


P3F2 P2F2


■ The portfolio complies with the proposed Clean Power Plan requirements and the GHG New

Source Standard.



capacity. Total CO2 emissions are expected to decline by 30 percent from 1,433 lb/MWh in 2016

to 1,007 lb/MWh in 2035.

Portfolio Selection Portfolio 3 Future 2 (P3F2): Environmental

800

900

1,000

1,100

1,200

1,300

1,400

1,500

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

lbs

/MW

h

P3F2 CO2 Emission

CO2 Emissions (Total Generation)

CO2 Emission Target (Total Generation)

Costa Sur H Class Train 1


-

10

20

30

40

50

60

70

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

Mil

lio

n l

bs




1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

P1F3 P2F3 P3F3

$2

01

5 M

illio

n

Capital Costs


■ Capital Costs:


$P3F1 < $P3F3 < $P2F3

Difference is exclusively in generation and occurs

in years 2016-2035

■ System Costs:


for Future 3. The main difference with

P2F3 is the capital, while with P1F3 is

the fuel.

-

200

400

600

800

1,000

1,200

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

Re

al

201

5$

Mil

lio

n

Capital Cost

New Generation Existing Generation Demolition

AOGP Gas to North

Existing Generation Conversion to Gas Transmission Upgrades

System Costs P3F3

Total Present Value of System Costs 26,660

Average Annual System Costs 2,394

System Costs P2F3



System Costs P1F3




■ System Costs:


-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

$2

01

5 T

ho

us

an

d

P3F3 Production Costs

Fuel Regasification fixed costs

O&M Purchased power



-

20,000,000

40,000,000

60,000,000

80,000,000

100,000,000

120,000,000

140,000,000

160,000,000

180,000,000

200,000,000

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

MM

Btu



-

2.000

4.000

6.000

8.000

10.000

12.000

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

MM

Btu

/MW

h



-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

Tho

usa

nd

$2

01

5

Future 3 Fuel Costs

P1F3 P2F3 P3F3


Portfolio 3 by virtue of having the largest units also shows higher curtailment that

Portfolio 2.

This higher curtailment and the associated reduced use of renewable generation

results in slightly higher fuel costs than Portfolio 2. Portfolio 1 still has the highest fuel

costs.

The Portfolio achieves the target RPS and the cost associated with curtailment

becomes very small once the Portfolio is fully deployed.


0%1%2%3%4%5%6%7%8%9%

10%11%12%13%14%15%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034


P1F3 P2F3 P3F3

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

0%

5%

10%

15%

20%

25%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

$20

15

Th

ou

san

d




Reduced RPS Target



target of 4.


Cambalache. The lowest of the 3 Portfolios, in line with our expectations.


0%

10%

20%

30%

40%

50%

60%

70%

80%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034


P1F3 P3F3 P2F3


■ The portfolio complies with the proposed Clean Power Plan requirements and with the GHG

New Source Standard, with the provisions below.

The Repowered Aguirre CC 1&2 have emissions over the 1000 lb/MWh due to lower dispatch

levels and this can be addressed introducing this restriction on the economic dispatch,.



capacity. Total CO2 emissions are expected to decline by 34 percent from 1,396 lb/MWh in

2016 to 919 lb/MWh in 2035..

Portfolio Selection Portfolio 3 Future3 (P3F3): Environmental

800

900

1,000

1,100

1,200

1,300

1,400

1,500

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

lbs/M

Wh

P3F3 CO2 Emission

CO2 Emissions (Total Generation) CO2 Emission Target (Total Generation)

Aguirre 1 CC Repower Aguirre 2 CC Repower

Palo Seco F Class Train 1 Aguirre H Class Train 1

Aguirre H Class Train 2 Costa Sur H Class Train 1


-

10

20

30

40

50

60

70

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

Mil

lio

n l

bs




Portfolio 3 also has the lowest system costs

for Future 4, with respect of Portfolio 2.

Portfolio 1 was not considered as it had already

very high curtailment.

CapEx is the same as Future 1

Curtailment is under 2% at the end of the

period.

Portfolio Selection Portfolio 3 Future 4 (P3F4) Key Results







-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

$2015 T

ho

usan

d

P3F4 System Costs

Fuel Regasification fixed costs

O&M Purchased power



-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

0%

5%

10%

15%

20%

25%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

$2015 T

ho

usan

d




Reduced RPS Target


As the amount of intermittent renewable energy in a system

increases, there are moments where there is more energy than the

system can handle at once, and would cause system unbalance and

collapse if not cut, or curtailed. The current contracts require PREPA

to pay this energy, even if it was not used. In the selected portfolio

(P3F1) we can see that when not enough flexible generation is

available, PREPA would have to pay up to $35 million a year in

curtailment costs.

0%1%2%3%4%5%6%7%8%9%

10%11%12%13%14%15%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034


P1F1 P2F1 P3F1

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

0%

5%

10%

15%

20%

25%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

$2

01

5 T

ho

us

an

d




Reduced RPS Target

Renewable Integration

Curtailment Costs


Renewable Integration

Curtailment Costs

5

5

If nothing is done to renew PREPA’s generation fleet, the situation is

much worst, paying up to $250 million in curtailment penalties in a

year for power NOT received.

0%1%2%3%4%5%6%7%8%9%

10%11%12%13%14%15%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034


P1F1 P2F1 P3F1

-

50,000

100,000

150,000

200,000

250,000

300,000

0%

5%

10%

15%

20%

25%

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

$ 2

015 T

ho

usan

d




Reduced RPS Target


20% Penetration by 2035 results in an increase in yearly (2035) cost of 3 to 4% with

respect of the base case.

The curtailment is always above the target of 2%.

Future 2 is the most capable to use this generation (2.8% increase in cost) and

Future 3 is the least (4 % increase in costs)

Portfolio Selection Portfolio 3 Sensitivity 1: 20% Penetration

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

2035

Renewable Curtailment (P3F1 vs. P3F1 S1)

P3F1 P3F1 S1

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

2035

Renewable Curtailment(P3F2 vs. P3F2 S1)

P3F2 P3F2 S1

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%

4.5%

2035


P3F3 P3F3 S1

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

2035

Renewable Curtailment (P3F4vs. P3F4 S1)

P3F4 P3F4 S1

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

2035


P3F1 P3F1 S1

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

2035


P3F2 P3F2 S1

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%

4.5%

2035


P3F3 P3F3 S1

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

2035


P3F4 P3F4 S1

System Costs P3F1 CY P3F2 P3F3 P3F4

System Costs in 2035 $ million 2,306 2,766 2,385 2,343

System Costs P3F1-S1 P3F2-S1 P3F3-S1 P3F4-S1

System Costs in 2035 $ million 2,378 2,845 2,481 2,428

Sensitivity S1 Incremental System Costs P3F1-S1 P3F2-S1 P3F3-S1 P3F4-S1

Sensitivity S1 Incremental System Costs in 2035$ million 72 78 96 85

3.12% 2.83% 4.04% 3.62%


Renewable Freeze result in important reduction of costs ranging from 2.9% in Future

2 to 5.3% in Future 4. Curtailment is controlled for the entire period.

Portfolio Selection Portfolio 3 Sensitivity 2: Renewables Freeze

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%


P3F1 P3F1 S2

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%


P3F2 P3F2 S2

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%


P3F3 P3F3 S2

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%


P3F4 P3F4 S2

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%


P3F1 P3F1 S2

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%


P3F2 P3F2 S2

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%


P3F3 P3F3 S2

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%


P3F4 P3F4 S2

System Costs Unit P3F1 P3F2 P3F3 P3F4

Total Present Value of System Costs $ million 26,842 30,013 26,660 26,648

Average Annual System Costs $ million 2,415 2,733 2,394 2,397

System Costs Unit P3F1-S2 P3F2-S2 P3F3-S2 P3F4-S2



Sensitivity S2 Change Unit P3F1-S2 P3F2-S2 P3F3-S2 P3F4-S2

Total Present Value of System Costs $ million (1,367) (882) (1,381) (1,415)

Average Annual System Costs $ million 149 94 151 156

-5.1% -2.9% -5.2% -5.3%


Portfolio 3 can manage the loss of AES in 2027. However, this results in increased

cost ranging from 2.5 % increase in Future 2 to 0.1% savings on Future 3.

These results highlight the importance of bringing gas to the north of the island in

preparation for an eventual retirement of AES Coal Fired Plant.

Portfolio Selection Portfolio 3 Sensitivity 3: AES Retirement

System Costs Unit P3F1 P3F2 P3F3 P3F4



System Costs Unit P3F1-S3 P3F2-S3 P3F3-S3 P3F4-S3



Sensitivity S3 Incremental System Costs Unit P3F1-S3 P3F2-S3 P3F3-S3 P3F4-S3

Total Present Value of System Costs $ million 126 756 -22 104

Average Annual System Costs $ million 18 111 -4 15

0.5% 2.5% -0.1% 0.4%


Puerto Rico Electric Power Authority Integrated Resource Plan 2016 – 2035

Transmission Analysis



■ New and Flexible generation at Palo Seco Plant will be available by 2022:

210 MW (3x70 MW SCC-800).

■ Investments identified from previous reliability studies:

Bayamón TC Second Transformer of 230/115 kV and 544 MVA,

Reconstruction of 115 kV line 36100 Bayamón TC to Barrio Piñas: upgraded to

231 MVA (1192.5 kcmil ACSR conductor)

A new 2.5 mile 115 kV underground cable from Humacao TC to Yabucoa TC.

Capacitor banks at Hato Rey TC (43.05 MVAr) and Berwind TC (46.6 MVAr)

refurbished and considered in service.

Reconstruction and increase capacity of the 115 kV line 37800 Cayey TC to

Caguas TC to 231 MVA (conductor 1192.5 kcmil ACSR).

■ The study identified other additional investments, based primarily on a heavy

use of the transmission system.

Transmission Study Key Inputs and Assumptions


■ As a result of the transmission system study, critical contingencies were

identified, along with their impacts on such system. Among others, the

resulting impacts include:

Heavy congestion in main 115 kV lines.

Extreme low voltages that may induce a voltage collapse at the Metropolitan and West

areas.

■ The following investments were identified for mitigating the system impacts

described before:

Reconstruction of 230 kV lines

New underground 115 kV line between Berwind TC and Sabana Llana TC.

New 50 MVAR shunt capacitor bank at Mayagüez TC.

A new dynamic reactive power compensation (i.e. STATCOM):

• 2 units of ±100 MVAr, one at Monacillo TC and one at San Juan Plant (under review).

• Having 2 units will provide sufficient compensation and permit to maintain one compensator

without compromising the security of PREPA’s grid.

Heavy use of the transmission system:

Critical Contingencies


■ Puerto Rico annually experiences a

great activity of hurricanes and tropical

storms during the months of June and

November, the Hurricane Season.

■ These events can affect the

transmission lines, potentially affecting

multiple important transmission lines

South-North.

■ With a disrupted South-North

transmission system, the generating

units at North play a crucial role in

supplying the local load as the system

is recovered.

Considerations for Extreme Events


■ It was evaluated an event where a major hurricane separates the North

from the South, with the IRP reduced generation capacity at the North and

the entire fleet being available.

■ Different load scenarios were simulated reflecting various affected areas

in the North:

Bayamón, Carolina, and San Juan

Caguas, Bayamón, Carolina, and San Juan

Arecibo, Caguas, Bayamón, Carolina, and San Juan

■ Significant load shedding was found to be required, from 6% to 39%, with

the IRP reduced generation capacity at the North and the entire fleet

available.

Extreme Events

Evaluation


■ The load shedding levels found are not acceptable, so it is recommended

to take some actions to minimize such load shedding during Major

Events.

■ Recommendations:

Have stand-by generation available at Palo Seco or San Juan, beyond what is

already considered in the IRP.

Perform a System Restoration Study:

• Assessment of feasible standby generation alternatives which result more

economical for PREPA’s operations.

• Consideration of the transmission system reconstruction, environmental

permitting process, and related costs.

• Evaluation of black start plans and emergency preparedness procedures.

Extreme Events

Conclusion and Recommendation


■ There are almost $2 billion in

transmission projects of which

$274 millions are crucial for the IRP.

Summary of Capital Expenditures

Category Description

Capital Costs

($2015)

Main

Projects

Transmission reinforcement projects (230 kV and 115 kV)

required to integrate the new generation portfolios by

increasing the transfer capability south to north.

$274 million

Other

Projects

Projects and reinforcements required to provide reliability to

the system at different voltage levels (transmission, sub-

transmission and distribution). These projects are included in

the IRP due to the urgent need to reconstruct the system to

maintain continuous operation.

$1,662 million

Support

Projects Equipment, tools, facilities improvements necessary to

develop the required projects. $45 million

Total $1,981 million


■ These projects are required before Palo Seco 3&4 are replaced by the new CC.

■ Palo Seco 3&4 and San Juan 9&10 must be online during the developing of these projects.


Main Transmission Projects

Jul-S

ept

Oct-

Dec

Jan-M

ar

April-Jun

Jul-S

ept

Oct-

Dec

Jan-M

ar

April-Jun

Jul-S

ept

Oct-

Dec

Jan-M

ar

April-Jun

Jul-S

ept

Oct-

Dec

Jan-M

ar

April-Jun

Jul-S

ept

Oct-

Dec

Jan-M

ar

April-Jun

Jul-S

ept

Oct-

Dec

Jan-M

ar

April-Jun

San Juan GIS 38 kV & 115 kV Bus 115 KV

Control and Protection Metropolitan Area TC 115 KV

Bus Reconstruction 115 KV

Line 37800 Cayey - Caguas & Caguas TC - Monacillo TC 115 KV

Line 50100 Cambalache TC - Manati TC 230 kV

Line 36100 Bayamón TC – Ciales 115 kV

Line 37400 Cambalache TC - Barceloneta TC 115 kV

Line 36200 Monacillo TC- Quebrada Negrito 115 kV

Line 41400 Humacao TC-Juncos TC 115 kV

New 115 kV Underground Cable Sabana Llana TC – Berwind TC 115 kV

Line 50200 Manati TC - Bayamon TC 230 kV

Line 38900 Hato Rey TC – Martin Peña GIS 115 kV

Dynamic Reactive Compensation STATCOM 100 MVAR Monacillo 115 KV

New 230/115 kV Transformer Bayamon 230/115

Mora Capacitor Bank 115 KV

Line 50200 Costa Sur - Manati TC 230 kV

Venezuela Transmission Center 115 kV

Yabucoa - Humacao Corridor(41000 &36300) Reinforcement and

Relocation115 kV

Line 51000 Aguas Buenas - Sabana Llana TC 230 kV

Dynamic Reactive Compensation STATCOM 100 MVAR at SJSP 115 KV

Line 50900 Aguas Buenas - Bayamón TC 230 kV

Line 50900 Aguirre - Aguas Buenas 230 kV



Facility

2015 20212016 2017 2018 2019 2020

Voltage

Switchyards protection, coordination

and control replacement

230 kV lines reconstruction


New 115 kV lines

New 115/38 kV switchyard

New STATCOM

Engineering and Procurement

Mayagüez TC Capacitor Bank





Facility Voltage

2015 2016 2017 2018 2019 2020 2021

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San Juan GIS 38 kV & 115 kV Bus 115 KV

Control and Protection Metropolitan Area TC 115 KV

Bus Reconstruction Metropolitan Area TC 115 KV

Line 37800 Cayey - Caguas & Caguas TC - Monacillo TC 115 KV

Line 50100 Cambalache TC - Manati TC 230 kV

Line 36100 Bayamón TC – Ciales 115 kV

Line 37400 Cambalache TC - Dorado TC 115 kV

Line 36200 Monacillo TC- Quebrada Negrito 115 kV

Line 41400 Humacao TC-Juncos TC 115 kV

New 115 kV Underground Cable Sabana Llana TC –

Berwind TC 115 kV

Line 50200 Manati TC - Bayamon TC 230 kV

Line 38900 Hato Rey TC – Martin Peña GIS 115 kV

Dynamic Reactive Compensation STATCOM 100 MVAR

Monacillo 115 KV

New 230/115 kV Transformer Bayamon 230/115

West Area Capacitor Bank 115 KV

Line 50200 Costa Sur - Manati TC 230 kV

Venezuela Transmission Center 115 kV

Yabucoa - Humacao Corridor(41000 &36300)

Reinforcement and Relocation 115 kV

Line 51000 Aguas Buenas - Sabana Llana TC 230 kV

Dynamic Reactive Compensation STATCOM 100 MVAR

at SJSP 115 KV

Line 50900 Aguas Buenas - Bayamón TC 230 kV



Switchyards protection, coordination

and control replacement



New 115 kV lines

New 115/38 kV switchyard

New STATCOM

Engineering and Procurement


Within the proposed plan these are the necessary projects in the selected portfolio (P3F1),

deemed to be the least cost alternative, complying with the required statutes:

Driver Site Project COD Fuel Cost

MATS Compliance

AOGP and related

Gas Port Jul-17 --

373.6

Aguirre Steam 1 Conversion Oct-16 Gas

38.4

Aguirre Steam 2 Conversion Jul-17 Gas

38.4

Aguirre CC 1 Dual Fuel Conversion Oct-16 Gas/Diesel

24.1

Aguirre CC 1 Dual Fuel Conversion Jul-17 Gas/Diesel

24.1

Palo Seco New Palo Seco F Class Jan-21 Diesel

369.3

Unit Retirements FY21, FY27, FY31 --

135.6

Energy Efficiency

Improvements

Aguirre

Aguirre CC 1 Repowering Jul-21 Gas

185.2

Aguirre CC 2 Repowering Jul-22 Gas

185.2

New Aguirre 1 H Class Jul-26 Gas

397.7

New Aguirre 2 H Class Jul-27 Gas

397.7

Costa Sur New Costa Sur 5 H Class Jul-30 Gas

397.7

New Costa Sur 6 H Class Jul-31 Gas

397.7

Additional T&D Investments FY16-FY20

262.4

(in millions$) Total 3,227.1

PREPA’s IRP Recommended Main Projects


AG CC Aguirre Combined Cycle

AOGP Aguirre Offshore Gas Port

CapEx Capital Expenditures

CC Combined Cycle

CPP Clean Power Plan

DG Distributed Generation

DSM Demand Side Management

EE Energy Efficiency

EPA Federal Environmental Protection Agency

EPC Engineering, Procurement, and Construction

FPM Fine Particulate Matter

FY Fiscal Year

GHG Green House Gases

GT Gas Turbine

IDC Interest During Construction

IRP Integrated Resource Plan

LFO Light Fuel Oil

LNG Liquefied Natural Gas

LOLH Loss Of Load Hours

MATS Mercury and Air Toxics Standard

NG Natural Gas

NM Net Metering

No 6 Heavy Fuel Oil

O&M Operations and Maintenance

PPOA Power Purchase and Operating Agreement

PREC Puerto Rico Energy Commission

PV Photovoltaic System (Solar)

RFP Request For Proposals

RPS Renewable Portfolio Standard

STATCOM Static Synchronous Condenser

TC Transmission Center

Acronyms

Documents

Puerto Rico Electric Power Authority Integrated Resource ... Integrado de Recurs… · Page 5 August 21, 2015 Siemens Industry, Inc PREPA’s IRP According to Act 57 – 2014, PREPA’s