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Guam Power Authority

Integrated Resource Plan

FY 2013

February 22, 2013

Guam Power Authority

PO Box 2977

Hagåtña, GUAM 96932

EXECUTIVE SUMMARY

Guam Power Authority

2013 Integrated Resource Plan

I

EXECUTIVE SUMMARY

Guam Power Authority (GPA) develops its Integrated Resource Plan (IRP) to 

provide the lowest cost solution for:

• Providing reliable, affordable power;

• Diversifying power supply resources and fuels to mitigate risk; and 

• Exercising environmentally responsible stewardship of the economic and 

natural resources of the island of Guam.

Integrated Resource Planning is an exercise in strategic and capital planning. This 

type of planning is an ongoing cycle of activity. It does not end with the submission of a 

report. Business situations change and new challenges arise continually. Therefore, the 

planning process must remain dynamic, ongoing, and mindful of new information and 

technologies as they become available. Additionally, the IRP must be congruent with 

other studies conducted by the organization, such as environmental plans, cost-of-service 

studies, strategic plans, etc.

The major strategic issues driving the development of this IRP include the 

following:

• GPA must increase its fuel diversity, mitigate fuel supply risk, and encourage 

cost-effective renewable energy;

• GPA must comply with existing and future United States Environmental 

Protection Agency requirements including but not limited to: EGU MACT, 

RICE MACT, new one-hour SO2 NAAQS;

• GPA must understand and consider the financial and operational impacts 

associated with compliance and non-compliance with existing and future 

United States Environmental Protection Agency in all of its business and 

operational planning;

• GPA must support the electric power service requirements for the impending 

Department of Defense (DOD) build-up and its economic consequences;

• GPA must evaluate the economic feasibility of retiring or extending the life of 

its existing generation units;
EXECUTIVE SUMMARY

Guam Power Authority

2013 Integrated Resource Plan

II

• GPA must work to reduce customer outages due to the instantaneous loss of 

generation. GPA must examine the operational and economic feasibility of 

using energy storage devices or requiring certain reliability enhancement 

characteristics for future generation additions; and

• GPA must understand how the acquisition of new electric energy supply will 

affect human resource requirements and GPA’s business model;

The primary recommendations of this IRP include:

• Obtain an agreement between the United States (USEPA) and Guam 

Environmental Protection Agencies to suspend compliance with the RICE MACT 

for Cabras 3&4 and MEC 8&9 until GPA completes transition to LNG;

• Procure an additional 40 MW of renewable energy resources under the Phase II 

Renewable Energy Acquisition Program, if cost-competitive with other available 

technologies, as early as 2017 to reduce present value costs;

• Develop the necessary infrastructure and contracts to engender the transition from 

residual fuel oil to Liquefied Natural Gas (LNG) by 2018 or sooner; 

• Retire Marbo CT and Dededo Diesels 1-4 by FY 2014;

• Firm up the decision by the end of FY 2014 to retire the Cabras 1 & 2 and/or 

Tanguisson 1&2 units in 2018 concurrent with the availability of LNG; 

• Based upon baseload retirement decisions, construct a new 60 to 120 MW gasfired combined cycle power plant, preferably in northern Guam to reduce 

technical line losses, online concurrent with the availability of LNG in 2018; 

• If GPA makes the decision not to retire Cabras 1&2 or Tanguisson 1&2, complete 

conversion of these units to burn natural gas concurrent with the availability of 

LNG in 2018; 

• Complete repowering Piti 7 GE Frame 6B combustion turbine generator (CTG) 

into a combined cycle burning natural gas concurrent with the availability of LNG 

in 2018; 

• Complete conversion of the Cabras 3 & 4 and MEC Piti 8 & 9 units to burn 

natural gas concurrent with the availability of LNG in 2018; 

• If economically and technically feasible, build a 10 MW Geothermal unit to come 

online in 2019; and

• Work towards compliance with all new environmental standards and regulations.
EXECUTIVE SUMMARY

Guam Power Authority

2013 Integrated Resource Plan

III

Other recommendations of this IRP include:

• Ensure that all generation plants meet the performance standards agreed with the 

Guam Public Utilities Commission (Guam PUC);

• Implement automated economic dispatch and unit commitment to optimize fuel 

use;

• Work collaboratively with the Guam PUC and stakeholders to improve GPA’s 

financial position relative to obtaining funding for these projects;

• Continue to investigate geothermal potential for Guam;

• Continue to investigate other resource options including Ocean Thermal Energy 

Conversion (OTEC), Sea Water Air Conditioning (SWAC) and other 

technologies;

• Work with the Guam PUC to establish the rules of engagement and rates for net 

metering;

• Work with the Guam PUC on implementing economically and socially viable 

Demand-Side Management (DSM) Programs as none of the projects evaluated by 

R.W. Beck pass the Rate Impact Measure (RIM) Test;

• Examine supplying natural gas for industrial, commercial, and residential use as a 

utility under the Consolidated Commission on Utilities (CCU) and the Guam 

PUC; 

• Finalize the disposition of assets currently under Independent Power Producers 

including the possible retirement of Tanguisson power plant and the transition of 

these power plants to operation under Performance Management Contracts (PMC) 

or Independent Power Producers (IPP); 

• Consider a business model using competitive bidding where GPA generates

immediate cash from the sale of assets currently held under expiring Energy 

Conversion Agreements to Independent Power Producers while simultaneously 

awarding long-term power purchase agreements to these IPPs; and

• Work with Guam Waterworks Authority (GWA) on an interruptible load 

arrangement in order to hedge against the risk of higher than baseline load 

growth. 

Table E-1 shows the potential net present value savings of the top three 

generation expansion scenario plans. These plans indicate net present value savings 

greater than one billion dollars for a GPA conversion from residual fuel oil to liquefied 
EXECUTIVE SUMMARY

Guam Power Authority

2013 Integrated Resource Plan

IV

natural gas. Tables E-2 through E-4 illustrate capex requirements for the three expansion 

plans.

Table E-1, Potential Savings of Diversifying to LNG

CASE Retirement Units

PV Utility Costs 

($000)

Present Value 

Variance 

(Savings) from 

Base Case ($000)

1 None 6,451,778 BASE CASE

2 Marbo, Dededo Diesel, Cabras 1&2 5,258,080 (1,193,698)

3 Marbo, Dededo Diesel, Tanguisson 1&2 5,311,525 (1,140,253)

4 Marbo, Dededo Diesel, Cabras 1&2, Tanguisson 1&2 5,241,317 (1,210,462)

5 Marbo, Dededo Diesel, Dededo CT 1&2, Yigo, Macheche 5,348,209 (1,103,570)

6 Marbo, Dededo Diesel, Dededo CT 1&2, Yigo 5,354,665 (1,097,114)

7 Marbo, Dededo Diesel, Dededo CT 1&2 5,360,709 (1,091,069)

8 Marbo, Dededo Diesel 5,388,596 (1,063,182)

CASE Retirement Units

Initial Screening 

Assumptions1

Test 

Assumptions2

1 None BASE CASE BASE CASE

2 Marbo, Dededo Diesel, Cabras 1&2 (1,193,698) (1,204,930)

3 Marbo, Dededo Diesel, Tanguisson 1&2 (1,140,253) (1,146,924)

4 Marbo, Dededo Diesel, Cabras 1&2, Tanguisson 1&2 (1,210,462) (1,201,425)

5 Marbo, Dededo Diesel, Dededo CT 1&2, Yigo, Macheche (1,103,570)

6 Marbo, Dededo Diesel, Dededo CT 1&2, Yigo (1,097,114)

7 Marbo, Dededo Diesel, Dededo CT 1&2 (1,091,069)

8 Marbo, Dededo Diesel (1,063,182)

2

 Testing assumptions evaluate results based on removal of initial screening assumptions.

Present Value Variance (Savings) 

from Base Case ($000)

1

 Initial screening assumptions include additional operation costs for intermittent renewable options (solar 

and wind) and the availability of geothermal potential.
EXECUTIVE SUMMARY

Guam Power Authority

2013 Integrated Resource Plan

V

Avoided Compliance Costs due to Retirement or Fuel Conversion by Scenario ($000)

Retirement Fuel Conversion Total

2 Cabras 1&2 Retirement 161,300 300,000 461,300

3 Cabras 1&2 and Tango Retirement 221,300 240,000 461,300

4 Tanguisson Retirement 61,300 400,000 461,300

Avoided Compliance Costs1 ($000)

1

 Avoided compliance costs assumes that GPA would be allowed to defer compliance of RICE 

MACT for Slow Speed Diesel units and BOILER MACT (MATS) for Steam units until LNG is 

available in 2018.

Case Retirement Units

Table E-2, Recommended Capital Requirements (thru 2020) – Tanguisson Retirement

Complete / 

Commission 

By FY Description Project Period

IWPS Capacity 

Impact 

(MW)

Life 

Extension 

($000)

Fuel Conversion / 

New Construction 

($000)

EPA Compliance 

($000)

Total CAPEX 

($000)

2013 Retire Marbo CT and Dededo CT - 26 MW $ - $ - $ - $ - 

2014 Life Extension & Environmental 

Compliance for Peaking Units 1 2013 - 2014 - $ 24,220 $ - $ 7,150 $ 31,370 

2015 Environmental Compliance for 

Baseload Plant 2 2013 - 2015 - $ - $ 13,002 $ 13,002 

2018 Life Extension of Baseload Plants 

(Excluding Cabras 1&2 & Tanguisson) 2014 - 2019 - $ 9,680 $ - $ - $ 9,680 

Solar PV 2014 - 2017 + 20 MW 

(2x10MW) $ 90,000 $ 90,000 

Wind 2014 - 2017 + 20 MW $ 93,000 $ 93,000 

LNG Import Terminal & Gasification 

Facility3 2013 - 2018 - $ 212,000 $ 212,000 

TEMES CT Repower as Combined 

Cycl e4

 & LNG Conversion 2014 - 2018

+ 20 MW

(capacity 

increase)

 $ 81,000 $ 81,000 

New Combined Cycle4 Units (2 Each) 2014 - 2018 + 60 MW $ 128,400 $ 128,400 

Cabras 3 LNG Conversion 2014 - 2018 - $ 13,560 $ 13,560 

Cabras 4 LNG Conversion 2014 - 2018 - $ 13,560 $ 13,560 

MEC 8 LNG Conversion 2014 - 2018 - $ 13,711 $ 13,711 

MEC 9 LNG Conversion 2014 - 2018 - $ 13,711 $ 13,711 

Retire Tanguisson 1 & 2 - 53 MW

(-2x26.5MW) $ - 

TOTAL: $ 33,900 $ 658,942 $ 20,152 $ 712,994

LNG Related Costs: $ 475,942

Renewable Costs: $ 183,000

NOTES:

1

2

3

4 Combined Cycle reference is a Combustion Turbine (CT) which ties in a Heat Recovery Steam Generator (HRSG) to its exhaust. The HRSG used in this 

reference is an additional 20 MW which increases plant efficiency since no additional fuel is used for power generated through the HRSG.

2017

2018

Peaking Units are the following diesel fueled combustion turbine and diesel engine units which are primarily used for peak hours or during maintenance of 

baseload units: Dededo CT 1&2, Macheche CT, Yigo CT, Marbo CT, Dededo Diesel Units 1-4, Tenjo Diesel Units 1-6, Talofofo Diesel Units 1-2, Manenggon 

Diesel Units 1-2 and Piti 7 (TEMES).

Baseload Plants refer to the high sulfur fuel oil fueled plants which primarily dispatched first due to fuel costs. These plants include Cabras 1&2, Cabras 

3&4, Piti 8&9 (MEC), and Tanguisson 1&2.

This is the total construction cost of the facility, however GPA will evaluate other contracting options to minimize cost impact.
EXECUTIVE SUMMARY

Guam Power Authority

2013 Integrated Resource Plan

VI
EXECUTIVE SUMMARY

Guam Power Authority

2013 Integrated Resource Plan

VII

Table E-3, Recommended Capital Requirements (thru 2020) – Cabras 1&2 Retirement 

Complete / 

Commission 

By FY Description Project Period

IWPS Capacity 

Impact 

(MW)

Life 

Extension 

($000)

Fuel Conversion / 

New Construction 

($000)

EPA Compliance 

($000)

Total CAPEX 

($000)

2013 Retire Marbo CT and Dededo CT - 26 MW $ - $ - $ - $ - 

2014 Life Extension & Environmental 

Compliance for Peaking Units 1 2013 - 2014 - $ 24,220 $ - $ 7,150 $ 31,370 

2015 Environmental Compliance for 

Baseload Plant 2 2013 - 2015 - $ - $ 13,002 $ 13,002 

2018 Life Extension of Baseload Plants 

(Excluding Cabras 1&2) 2014 - 2019 - $ 6,340 $ - $ - $ 6,340 

Solar PV 2014 - 2017 + 20 MW 

(2x10MW) $ 90,000 $ 90,000 

Wind 2014 - 2017 + 20 MW $ 93,000 $ 93,000 

LNG Import Terminal & Gasification 

Facility3 2013 - 2018 - $ 212,000 $ 212,000 

TEMES CT Repower as Combined 

Cycl e4

 & LNG Conversion 2014 - 2018

+ 20 MW

(capacity 

increase)

 $ 81,000 $ 81,000 

New Combined Cycle4 Unit 2014 - 2018 + 60 MW $ 128,400 $ 128,400 

Cabras 3 LNG Conversion 2014 - 2018 - $ 13,560 $ 13,560 

Cabras 4 LNG Conversion 2014 - 2018 - $ 13,560 $ 13,560 

MEC 8 LNG Conversion 2014 - 2018 - $ 13,711 $ 13,711 

MEC 9 LNG Conversion 2014 - 2018 - $ 13,711 $ 13,711 

Retire Cabras 1 & 2 - 132 MW 

(-2x66MW) $ - 

Tanguisson 1 LNG Conversion5 2014-2018 - $ 16,817 $ 16,817 

Tanguisson 2 LNG Conversion5 2014-2018 - $ 16,817 $ 16,817 

TOTAL: $ 30,560 $ 692,576 $ 20,152 $ 743,288

LNG Related Costs: $ 509,576

Renewable Costs: $ 183,000

NOTES:

1

2

3

4

5

2017

2018

2019

Tanguisson Units would either need to convert or retire since it would the only remaining plant on RFO requiring GPA to maintain fuel storage and 

inventory for three fuels.

Baseload Plants refer to the high sulfur fuel oil fueled plants which primarily dispatched first due to fuel costs. These plants include Cabras 1&2, Cabras 

3&4, Piti 8&9 (MEC), and Tanguisson 1&2.

This is the total construction cost of the facility, however GPA will evaluate other contracting options to minimize cost impact.

Combined Cycle reference is a Combustion Turbine (CT) which ties in a Heat Recovery Steam Generator (HRSG) to its exhaust. The HRSG used in this 

reference is an additional 20 MW which increases plant efficiency since no additional fuel is used for power generated through the HRSG.

Peaking Units are the following diesel fueled combustion turbine and diesel engine units which are primarily used for peak hours or during maintenance of 

baseload units: Dededo CT 1&2, Macheche CT, Yigo CT, Marbo CT, Dededo Diesel Units 1-4, Tenjo Diesel Units 1-6, Talofofo Diesel Units 1-2, Manenggon 

Diesel Units 1-2 and Piti 7 (TEMES).
EXECUTIVE SUMMARY

Guam Power Authority

2013 Integrated Resource Plan

VIII

Table E-4, Recommended Capital Requirements (thru 2020) – Cabras 1&2 and Tanguisson 

Retirement

Complete / 

Commission 

By FY Description Project Period

IWPS Capacity 

Impact 

(MW)

Life 

Extension 

($000)

Fuel Conversion / 

New Construction 

($000)

EPA Compliance 

($000)

Total CAPEX 

($000)

2013 Retire Marbo CT and Dededo CT - 26 MW $ - $ - $ - $ - 

2014 Life Extension & Environmental 

Compliance for Peaking Units 1 2013 - 2014 - $ 24,220 $ - $ 7,150 $ 31,370 

2015 Environmental Compliance for 

Baseload Plant 2 2013 - 2015 - $ - $ 13,002 $ 13,002 

2018 Life Extension of Baseload Plants 

(Excluding Cabras 1&2 & Tanguisson) 2014 - 2019 - $ 2,680 $ - $ - $ 2,680 

Solar PV 2014 - 2017 + 20 MW 

(2x10MW) $ 90,000 $ 90,000 

Wind 2014 - 2017 + 20 MW $ 93,000 $ 93,000 

LNG Import Terminal & Gasification 

Facility3 2013 - 2018 - $ 212,000 $ 212,000 

TEMES CT Repower as Combined 

Cycl e4

 & LNG Conversion 2014 - 2018

+ 20 MW

(capacity 

increase)

 $ 81,000 $ 81,000 

New Combined Cycle4

 Units (2 Each) 2014 - 2018 + 120 MW

(2x 60MW) $ 256,800 $ 256,800 

Cabras 3 LNG Conversion 2014 - 2018 - $ 13,560 $ 13,560 

Cabras 4 LNG Conversion 2014 - 2018 - $ 13,560 $ 13,560 

MEC 8 LNG Conversion 2014 - 2018 - $ 13,711 $ 13,711 

MEC 9 LNG Conversion 2014 - 2018 - $ 13,711 $ 13,711 

Retire Cabras 1 & 2 - 132 MW 

(-2x66MW) $ - 

Retire Tanguisson 1 & 2 - 53 MW

(-2x26.5MW) $ - 

TOTAL: $ 26,900 $ 787,342 $ 20,152 $ 834,394

LNG Related Costs: $ 604,342

Renewable Costs: $ 183,000

NOTES:

1

2

3

4 Combined Cycle reference is a Combustion Turbine (CT) which ties in a Heat Recovery Steam Generator (HRSG) to its exhaust. The HRSG used in this 

reference is an additional 20 MW which increases plant efficiency since no additional fuel is used for power generated through the HRSG.

2018

2017

Peaking Units are the following diesel fueled combustion turbine and diesel engine units which are primarily used for peak hours or during maintenance of 

baseload units: Dededo CT 1&2, Macheche CT, Yigo CT, Marbo CT, Dededo Diesel Units 1-4, Tenjo Diesel Units 1-6, Talofofo Diesel Units 1-2, Manenggon 

Diesel Units 1-2 and Piti 7 (TEMES).

Baseload Plants refer to the high sulfur fuel oil fueled plants which primarily dispatched first due to fuel costs. These plants include Cabras 1&2, Cabras 

3&4, Piti 8&9 (MEC), and Tanguisson 1&2.

This is the total construction cost of the facility, however GPA will evaluate other contracting options to minimize cost impact.
TABLE OF CONTENTS

Guam Power Authority

2013 Integrated Resource Plan

i

TABLE OF CONTENTS

1 SITUATION ANALYSIS .................................................................................................................... 1-3

1.1 INTRODUCTION TO GPA............................................................................................................... 1-3

1.2 HISTORICAL PERIOD SINCE THE LAST INTEGRATED RESOURCE PLAN .......................................... 1-3

1.2.1 Looking Forward................................................................................................................. 1-4

1.3 STRATEGIC ISSUES ....................................................................................................................... 1-4

1.4 LOAD FORECAST .......................................................................................................................... 1-6

1.5 ENERGY CONVERSION AGREEMENTS ........................................................................................... 1-7

1.6 PERFORMANCE MANAGEMENT CONTRACTS ................................................................................ 1-8

1.7 NEAR-TERM GENERATION ADDITION .......................................................................................... 1-9

1.7.1 Long-Term Generation Reliability....................................................................................... 1-9

1.7.2 Environmental Constraints.................................................................................................. 1-9

1.7.3 Generation Mix and Load Shape ......................................................................................... 1-9

1.8 FUEL ISSUES............................................................................................................................... 1-11

1.8.1 Comprehensive Fuel Management Planning Requirement................................................ 1-12

1.8.2 Fuel Use by Type and the Associated Cost........................................................................ 1-12

1.9 GENERATION RETIREMENT ........................................................................................................ 1-14

1.10 RISK ........................................................................................................................................... 1-15

1.10.1 Planning Risk..................................................................................................................... 1-15

1.10.2 Financial Risk.................................................................................................................... 1-15

1.10.3 Regulatory Risk.................................................................................................................. 1-16

2 SCOPE OF WORK AND APPROACH................................................................................................. 2-1

2.1 SCOPE OF WORK........................................................................................................................... 2-1

2.2 APPROACH ................................................................................................................................... 2-2

2.2.1 Review Planning Environment......................................................................................... 2-2

2.2.2 Develop Inputs & Assumptions............................................................................................ 2-3

2.2.3 Ensure Adequate Load & Resource Balance....................................................................... 2-3

2.2.4 Define Candidate List.......................................................................................................... 2-3

2.2.5 Determine Effects on Reliability of the Retirement of Existing Generation Units............... 2-4

2.2.6 Determine Optimal Portfolio............................................................................................... 2-4

2.2.7 Determine Diversified Resource Mix................................................................................... 2-4

2.2.8 Select Preferred Portfolio.................................................................................................... 2-4

2.2.9 Stakeholder Process ............................................................................................................ 2-4

3 FUTURE POWER REQUIREMENTS .................................................................................................. 3-1

3.1 THE ECONOMETRIC MODEL ......................................................................................................... 3-1

3.2 SUMMARY OF LOAD FORECAST SCENARIOS................................................................................. 3-3

3.2.1 Baseline Forecast Assumptions........................................................................................... 3-4

3.2.2 Alternative Forecast Assumptions....................................................................................... 3-6

4 FUTURE FUEL COSTS & CHOICES FOR GPA..................................................................................... 4-1

5 ENVIRONMENTAL CONSIDERATIONS ............................................................................................ 5-1

5.1 NATIONAL AMBIENT AIR QUALITY STANDARD (NAAQS) .......................................................... 5-1

5.1.1 Sulfur Dioxide, SO2............................................................................................................. 5-1

5.1.2 Nitrogen Dioxide, NO2........................................................................................................ 5-2

5.1.3 Particulate Matter, PM........................................................................................................ 5-2

5.2 MAXIMUM ACHIEVABLE CONTROL TECHNOLOGY (MACT)........................................................ 5-2
TABLE OF CONTENTS

Guam Power Authority

2013 Integrated Resource Plan

ii

5.2.1 Steam Electric Generation, “Boiler MACT”....................................................................... 5-3

5.2.2 Reciprocating Internal Combustion Engines, “RICE MACT”............................................ 5-4

6 RELIABILITY ASSESSMENT.............................................................................................................. 6-2

6.1 OBJECTIVE ................................................................................................................................... 6-2

6.2 GENERATION UNIT RETIREMENT EFFECTS ON GENERATION SYSTEM RELIABILITY ..................... 6-2

6.2.1 PICES Analysis Results ....................................................................................................... 6-3

6.2.2 Increasing Generation Unit Availability versus Generation Capacity Addition ................. 6-4

6.3 RELIABLE DELIVERY OF POWER................................................................................................... 6-5

7 SUPPLY SIDE OPTIONS................................................................................................................... 7-1

7.1 INTRODUCTION............................................................................................................................. 7-1

7.2 EXISTING UNITS ........................................................................................................................... 7-3

7.2.1 Boiler/STG Units ................................................................................................................. 7-3

7.2.2 Slow Speed Reciprocating Units.......................................................................................... 7-7

7.2.3 Medium Speed Reciprocating Units .................................................................................. 7-12

7.2.4 Combustion Turbine Generators....................................................................................... 7-16

7.3 NEW UNITS................................................................................................................................ 7-22

8 DEMAND SIDE MANAGEMENT ...................................................................................................... 8-1

8.1 INTRODUCTION............................................................................................................................. 8-1

8.2 INTRODUCTION AND DESCRIPTION OF STUDY .............................................................................. 8-3

8.3 APPROACH AND METHODOLOGY.................................................................................................. 8-4

8.3.1 Technical Screening Assessment ......................................................................................... 8-4

8.3.2 Economic Screening Analysis.............................................................................................. 8-4

8.3.3 DSM Measure Assumptions................................................................................................. 8-5

8.3.4 GPA Cost Assumptions........................................................................................................ 8-6

8.3.5 DSM Benefit-Cost Tests....................................................................................................... 8-7

8.4 RESULTS....................................................................................................................................... 8-8

9 KEY RESULTS.................................................................................................................................. 9-1

9.1 KEY RESULTS............................................................................................................................... 9-1

9.2 NEW GENERATION PLANT SITING ....................................................................................................... 9-6

9.3 LNG/NATURAL GAS REDUNDANT STORAGE FACILITY CONSIDERATIONS ................................................... 9-7

9.4 RENEWABLES................................................................................................................................... 9-7

10 RECOMMENDATIONS .............................................................................................................. 10-1

11 NEXT STEPS.............................................................................................................................. 11-1

11.1 ROLE OF THE PUBLIC UTILITIES COMMISSION............................................................................ 11-1

11.2 ACQUISITION PROCESS............................................................................................................... 11-2

APPENDICES.............................................................................................................................................A

A LOAD FORECAST ..................................................................................................................................A

B ENVIRONMENTAL STRATEGIC PLAN.....................................................................................................B

C CAPACITY RESERVE ANALYSIS ............................................................................................................C

D DEMAND SIDE MANAGEMENT..............................................................................................................D

E IRP STRATEGIST SCENARIO ANALYSIS ................................................................................................E

F BIBLIOGRAPHY..................................................................................................................................... F

G ACKNOWLEDGEMENTS........................................................................................................................ G
SITUATION ANALYSIS

Guam Power Authority

2013 Integrated Resource Plan

1-3

1 Situation Analysis

1.1 Introduction to GPA

Guam Power Authority (GPA) is a public corporation and an enterprise fund of 

the Government of Guam. The Guam Power Authority Act of 1968 established GPA in 

May 1968. Guam Code 12 Chapter 8 sets the legal definitions, empowerments and 

limitations for GPA.

The Consolidated Commission on Utilities (CCU), a five member elected board 

of directors, administers GPA. The directors are elected for staggered four-year terms. 

Additionally, GPA is regulated by the Guam Public Utilities Commission (Guam PUC). 

GPA had 48,512 customers at the end of FY 2012. GPA’s fiscal year budgets for 

2012 and 2013 are $400.6 and $413.5 million, respectively. The fuel budget comprises 

about 76% of the total budget. GPA’s highest peak system demand is 281.5 MW. 

GPA is a full service electric utility. It generates, transmits, and distributes 

electric energy from its various power generation resources to individual customers. GPA 

has an installed generation capacity of 552 MW gross including 181 MW from 

Independent Power Producers (IPPs). GPA has organized 210 MW of its baseload 

capacity under two Performance Management Contracts (PMCs). These contracts 

provide private management using public employees to operate and maintain the plants. 

These contracts contain performance-based incentives for reducing plant operating costs. 

Furthermore, GPA has installed 663 miles of transmission and distribution lines and 

operates 29 substations throughout the island. 

Although, budgeted for 592 Full-Time Employees (FTE's) and 24 Apprentices in 

Fiscal Year 2012, GPA had filled only 542 full time employee billets as of October 1, 

2012. GPA has an apprenticeship program recognized and licensed by the U.S. Bureau of 

Labor. Apprentices do not count towards the FTE count.

1.2 Historical Period since the Last Integrated Resource Plan

In its Fiscal Year 2008 Integrated Resource Plan, GPA foresaw high near termeconomic growth due to the military buildup. Looking back since then, historical system 

peak and energy demand have actually decreased, due to the prolonged economic 

downturn, tourism declines related to the economy and to the March 2011 Japan 

earthquake and tsunami, and other various factors affecting usage. Recommendations 

made in the FY 2008 plan have been modified and updated based on the recent planning 

activities. 
SITUATION ANALYSIS

Guam Power Authority

2013 Integrated Resource Plan

1-4

1.2.1 Looking Forward

This IRP forms a significant part of GPA’s near- and long-term business planning 

activities. Most importantly, GPA’s planning activities look at strategic management 

decisions such as:

• Maintaining GPA as a financially stable, operationally efficient entity that can meet 

its customers’ needs and expectations to provide high quality energy services at 

affordable prices.

• From organizational, operational, and financial perspectives, understanding and 

planning for changes in future customer demand, sales, revenues

• Serving the people of Guam in an environmentally friendly manner that complies 

with the requirements of the U.S. Environmental Protection Agency (U.S. EPA) and 

Guam Environmental Protection Agency (GEPA).

1.3 Strategic Issues

GPA faces several issues affecting its ability to meet strategic long-term goals as 

an organization and provider of quality, affordable and reliable energy services to the 

people of Guam. The major strategic issues driving the development of this plan include 

the following:

GPA must increase its fuel diversity, mitigate fuel supply risk, and gain more 

renewable energy.

GPA must comply with existing and future United States Environmental 

Protection Agency requirements including but not limited to: EGU MACT, RICE 

MACT, new one-hour SO2 NAAQS and understand the financial and operational impacts 

associated with non-compliance.

GPA must support the electric power service requirements for the impending 

Department of Defense (DOD) build-up and its economic consequences. 

GPA must evaluate the economic feasibility of retiring or extending the life of its 

existing generation units.

GPA must work to reduce customer outages due to the instantaneous loss of 

generation. GPA must examine the operational and economic feasibility of using energy 

storage devices or requiring certain reliability enhancement characteristics for future 

generation additions. GPA must understand how the acquisition of new electric energy 

supply will affect human resource requirements and GPA’s business model.

Providing a resource mix that results in affordable, reliable, and environmentally 

responsible and cost-effective power drives this IRP effort. Along those lines, GPA 
SITUATION ANALYSIS

Guam Power Authority

2013 Integrated Resource Plan

1-5

considers increasing GPA’s generation fuel diversity of paramount importance. The 

rising and volatile cost of fuel oil impacts the affordability of electric energy and saps 

working capital from operations and capital investments into fuel inventory. Additionally, 

having a non-diversified fuel base places GPA’s customers at a higher risk for supply 

disruption. Furthermore, dollars spent by customers for fuel oil are almost entirely spent 

outside the local economy. As a result, this money does not result in a multiplicative 

effect within the Guam community, the way other local purchases on the island typically 

do. Finally, new environmental compliance requirements on oil-fired generation will 

require large capital outlays and increase operations and maintenance costs.

Renewable sources of energy may allow for more of these dollars to trickle into 

the local economy. As an island people, the results of greenhouse gases contributing to 

climate change are clearly evident in the shrinking coastlines of Guam and our island 

neighbors. Choosing resources that reduce pollution and are sustainable over the longterm seems to be the right choice for Guam. Beyond the issues of pollution and 

sustainability is the issue of cost. GPA is facing significant environmental regulation –

related costs if it continues to burn oil in the manner it currently does. GPA does not 

want to pass these costs on to customers when there may be a way to provide cleaner, 

more affordable power.

In addition to having a resource mix with greater fuel diversity and a better 

environmental impact, the generation resources must address changes to our local 

economy, demand patterns, and population growth. Tourism growth triggered the 

economic boom of the nineties. GPA grew from a 156 MW to a 281.5 MW peaking 

utility in less than a decade. The engine for next decade of economic growth on Guam 

will likely continue to be tourism but also there will be an impact related to the DOD 

build-up and its diverse consequences to the civilian community. GPA must have a plan 

in place that will work for a variety of military buildup possible outcomes. This plan must 

address changes in timing and level of infrastructure buildup while maintaining 

affordable, reliable power to its existing customers.

GPA’s current generation portfolio faces a series of challenges. Many of the units 

will require significant investment, care, and attention if they are going to continue to 

operate well into the future. GPA must evaluate the benefits and costs of keeping 

existing units operational or retiring them vs. adding new resources. 

GPA has a long-term goal of improving reliability and reducing outages. Any 

resource added to or removed from the system must not negatively impact GPA’s ability 

to provide reliable power. GPA also is evaluating the costs and benefits of system 

enhancements such as battery storage systems and devices to improve system inertia. In 

addition to these non-generating technologies, as GPA evaluates new units, it examines 

how these resources will affect system reliability and the costs associated with 

maintaining adequate reserves. 

Acquisition of new diversified electric energy supply has implication on human 

resource requirements and operation of the system. GPA staff is not familiar with many 
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of these new technologies. GPA must consider whether new electric supply assets will 

depend entirely on external labor sources or whether Guam needs to grow the labor pool 

necessary to support these operational requirements. Furthermore, GPA’s business model 

includes its own generation with internal staffing, independent power producers with 

external staffing, and performance management contracts with mixed staffing. 

Additionally, there are private sector advantages in execution and tax credit eligibility. 

Public sector advantages include Federal Emergency Management Agency (FEMA) and 

government grant eligibility and in general, lower costs of borrowing money. Using the 

business model to provide the greatest value for customers is a strategic concern.

1.4 Load Forecast

GPA’s baseline forecast indicates that Guam will not be leaving a period of flat 

economic growth for a number of years. Additionally, forecast scenarios considering the 

impacts of the military build-up consistent with today’s information show a much smaller 

impact on electric power demand than in the 2008 IRP. Figure 1-1 provides a graph 

illustrating the forecast scenarios.

P.L. Mangilao developed low and high tourism and infrastructure development 

economic scenarios. The resulting scenario forecasts include an “EPA Delay”, low 

tourism-high infrastructure (L&H), high tourism-low infrastructure (H&L), and high 

tourism-high infrastructure. These forecasts are discussed in Section 3, and in more detail 

in P.L. Mangilao’s report1.

 1 The GPA Sales and Load Forecasting Process Documentation, 2012, P.L. Mangilao, LLC
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260

270

280

290

300

310

320

330

2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025

Demand (MW)

Fiscal Year

Forecast Scenarios: Peak Demand 

Actual

Baseline

EPA Delay

H&L

L&H

H&H

Figure 1-1, Load Forecast Scenarios

1.5 Energy Conversion Agreements

In FY 1997, GPA committed to Energy Conversion Agreements (ECA) with 

Hawaiian Electric Industries, Inc. (HEI), Marianas Electric Company (MEC), and Taiwan 

Electric and Mechanical Engineering Services (TEMES). HEI took over GPA’s 

Tanguisson Power Plant. MEC constructed the Piti 8&9 slow speed diesel plant. TEMES 

constructed Piti 7, a 40 MW combustion turbine. Ownership of the Tanguisson plant 

ECA has changed from HEI to Mirant and from Mirant to Pruvient. MEC ownership has 

changed from Tomen Bank and Enron to Osaka Gas and Arclight, and finally solely to 

Osaka Gas. TEMES ownership remains the same. These contracts are for twenty-year 

terms. Table 1-1 indicates nominal generation capacities, and the effective and 

termination dates for the ECA contracts. 

GPA is in an era of "contracted competition." GPA must measure its generation 

system performance against the performance and cost achieved by the ECA contractors. 
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1.6 Performance Management Contracts

GPA decided to use PMCs to improve baseload plant reliability and efficiency. 

GPA staff recognized that GPA did not have sufficient plant management, technical, and 

plant operation acumen resident at GPA to run its baseload facilities well. Keeping many 

of these skill sets full-time at GPA is economically prohibitive. Additionally, GPA 

already had difficulty recruiting to fill technical and professional positions. Also, 

GovGuam procurement does not support an operations environment well. GovGuam 

procurement issues often result in prolonged unit outages. Furthermore, GPA recognized 

the need for better, consistent training of its plant staff. Finally, staff foresaw that 

performance-based compensation would best drive exemplary performance and better 

protect the ratepayer from poor performance.

Using these salient points, GPA staff engaged management about the opportunity 

to use a contracted management team to manage, maintain, and operate its baseload 

plants. GPA worked with two consultants2 to flesh out the details of applying staff 

concepts and entered into a collaborative development of a PMC for Cabras 1&2 with the 

Guam Public Utilities Commission. All Authority baseload plants are now under the 

management of PMCs. These contracts have resulted in increased plant efficiencies and 

availabilities. A GPA whitepaper filed with the Guam Public Utilities Commission 

indicated that the PMC business model achieved a benefit-cost ratio of seven. 

Table 1-1, ECA Summary

Plant IPP

Plant 

Capacity 

(MW)

Contract 

Effective 

Date

Contract 

Termination 

Date

Piti Unit 7 (Combustion Turbine) TEMES 40 December 

1997

December 

2017

Piti Unit 8&9 (Slow Speed Diesel) MEC3 88 January 

1999

January

2019

Tanguisson Unit 1&2* (Steam) Pruvient4 53 August 

1997

August

2017

 2 Larry R. Noyes of New Energy Associates in Atlanta, Georgia and Dave L. Rogers of 

Information2Energy.

3 Contract was originally under Enron Development Piti Corporation which changed its name to Marianas 

Energy Company (MEC). 4 Contract has been reassigned two times. HEI (Hawaii Electric Industries Inc.) was the first IPP then 

Mirant.
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1.7 Near-Term Generation Addition

GPA must make prudent decisions for near-term generation additions in light of 

its expectation for electric demand. Uncertainties in DOD planning and approval of 

funding by Congress and the administration provide many elements of risk. 

1.7.1 Long-Term Generation Reliability

GPA has conducted this plan with reliability improvements in mind. All resource 

decisions, whether they include new resources or enhancement s to existing facilities 

must be made with reliability improvement as a goal. Existing resources have been 

examined and plans have been developed to improve performance, reduce outages, and 

extend expected service lives. Routine, comprehensive maintenance must be performed 

on all existing and new resource facilities to reap the full benefits of the investments to be 

made and provide the most value to GPA customers.

1.7.2 Environmental Constraints

GPA faces severe new environmental restrictions related to air emissions and 

other environmental constraints which affect its ability to add baseload capacity. 

The U.S. Environmental Protection Agency (EPA) has taken several actions to 

strengthen the National Ambient Air Quality Standards (NAAQS). These new standards 

will have significant effects on how GPA will be able to operate its units and the amount 

of air pollutants coming from its plants. Three primary pollutants: sulfur dioxide (SO2), 

nitrogen dioxide (NO2), and particulate matter (PM), will be the focus of the NAAQS 

compliance efforts for Guam. 

Three recently promulgated standards for Maximum Achievable Control 

Technology (MACT) applicable to GPA will have significant effects on how GPA will 

be able to operate its units and the amount of metals, chloride, and carbon monoxide 

emissions coming from its plants. Two primary types of generation, steam and 

reciprocating engine technologies will be the focus of the MACT compliance efforts for 

Guam. The impact on GPA’s operations and associated costs are discussed in more detail 

in the Environmental Considerations section of this report. For a comprehensive 

discussion of environmental compliance issues, please read GPA’s Environmental 

Strategic Plan. 

1.7.3 Generation Mix and Load Shape

All of GPA’s generation resources are oil-fired. This presents several strategic 

problems for GPA, concerning cost, volatility, and environmental impacts. While oilfired generation may have been a prudent choice in the past because oil was inexpensive

and environmental costs manageable, that is no longer the case.
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GPA has a mix of peaking, baseload, and intermediate generation units. Peaking 

unit technologies are relatively inexpensive and quick to install but expensive to operate. 

Therefore they are ideally operated only during system peak demand periods or as 

reserve units in the absence of reliable baseload capacity. Efficient baseload units require 

much longer permitting and construction lead times. However, they possess much higher

capital requirements for installation but are less expensive to operate. Intermediate units 

have unit characteristics between peaking and baseload. Table 1-2 describes the 

characteristics of these unit operating modes and technologies.

Table 1-2, Duty Cycles and Capacity Factors5

Generating 

Unit

Capacity Factor 

(%) Generic Characteristics

Duty Cycle Nominal Range Cost Performance Other

Baseload 65 50-85

Higher capital cost; 

lower fuel cost; lower 

maintenance cost

High 

availability; 

high efficiency

Long 

construction 

lead times

Intermediate 30 20 – 50

Intermediate-tohigher capital cost; 

intermediate fuel cost

Increased 

output 

flexibility

Generally long 

construction 

lead times

Peaking 10 1-20

Lower capital cost; 

higher fuel cost;

higher maintenance 

cost

Increased 

output 

flexibility; 

quick starting

Short 

construction 

lead time

GPA's current generation mix has substantial number of diesel-fired peaking 

plants stemming from the need to add capacity in the early 1990s. In the last few years, 

GPA has not relied heavily on diesel-fired generation to produce electric energy.

Guam's year-round tropical climate and tourism-based economy results in a 

relatively flat load shape with high load factor, meaning average load is relatively close

to peak load as compared to other utility systems. Such characteristics tend to favor 

baseload technology additions since operation near the peak is the norm. As an example, 

Figure 1-2 shows the GPA average demand hourly load shape for March 17, 2012 and

May 7, 2012. GPA’s FY 2012 system peak occurred on May 7, 2012. The smallest daily 

peak occurred on March 17, 2012. Note that GPA requires peaking capacity for only four 

hours for about 15 to 19 MW incremental peak. The system trough occurs between 3 am 

and 6 am. Beginning at noon through the late afternoon, the GPA system plateaus until 

the system peak. These features are fairly consistent throughout the year.

 5 1993 EPRI Technology Assessment Guide Volume 1: Electricity Supply. Table 2-1
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Figure 1-2, GPA Average Hourly Generation Requirements

1.8 Fuel Issues

Fuel choice and usage by GPA are complicated issues. Fuel costs are revenue 

neutral. GPA passes fuel costs through to customers in the Levelized Energy Adjustment 

Clause (LEAC) rate, Fuel costs, now comprises over two-thirds of residential electric 

power bills. Fuel issues facing GPA include:

Fuel price volatility;

Risk of fuel supply disruption;

Increasing fuel diversity;

Stiffening environmental regulations;

Fuel hedging; and

Prudent fuel use and inventory.

GPA has carefully considered these fuel issues in the development of this IRP. 

The IRP seeks to help GPA reach its strategic goals related to fuel diversification, 

environmental impacts of fuel use, and keeping costs down for its customers. 
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1.8.1 Comprehensive Fuel Management Planning Requirement

The CCU has directed management to plan for fuel purchases. This directive has 

the following challenges:

The availability of baseload generation impacts fuel use dramatically;

Generator failures are random; they can be analyzed statistically, but cannot 

necessarily be predicted;

Fuel purchase minimums must reflect expected unit dispatch but contain market 

and fuel management costs; and

Fuel purchase maximum must reflect agreed upon contingencies.

The fuel purchase planning process must be in alignment with the generation 

expansion plan. Fuel purchase planning must investigate fuel use under the assumption of 

expected or targeted operation modes as well as operation modes under various unit 

failure contingencies. GPA must plan for a bandwidth of operation and provide 

acceptable minimum and maximum fuel purchase limits.

1.8.2 Fuel Use by Type and the Associated Cost

GPA uses residual fuel oil and ultralow diesel in its power plants. Figure 1-3 

illustrates GPA historical fuel prices for high and low sulfur residual fuel oil and for 

ultra-low sulfur diesel. 

High sulfur fuel oil (HSFO) limits sulfur content to 2%. Low sulfur fuel oil 

(LSFO) limits sulfur content to 1.19%. The United States Environmental Protection 

Agency has granted GPA a 325 (a) waiver based upon installation and operation of the 

Cabras-Piti Area Intermittent Control Strategy (CPAICS). GPA switches to the more 

expensive low sulfur fuel whenever winds blow inland. 

In 2010, GPA facilitated a stakeholder process consisting of USEPA, GEPA, 

representatives from Guam’s transportation and heavy equipment industry, fuel 

providers, vehicle and equipment suppliers, the United States Navy, the Defense 

Logistics Agency, and others to support a move towards using low sulfur for Guam. GPA 

and this stakeholder group testified for a Guam Legislative Committee in support of a bill 

requiring Guam to move away from 5000 ppm diesel to ultralow sulfur 15 ppm diesel. 

Upon passage of this bill into law, GPA started using ultralow diesel fuel since January 

2011. Figure 1-3 illustrates historical fuel prices per barrel for each fuel type.
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Figure 1-3, Historical Fuel Prices for Diesel and Residual Fuel Oil (Blended HSFO & LSFO weighted average)
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1.9 Generation Retirement

GPA establishes its minimum generation reserve policy based upon an operational 

and planning criteria for achieving a one day in four and half years loss-of-load 

expectation (LOLE). GPA must balance the cost of building and maintaining installed 

capacity as reserve against not being able to serve load versus the cost of not being able 

to serve load. Critical to this balance is achieving high generation unit availability. GPA’s 

currently has a reserve margin of over 100% over its peak load. The IRP must prudently 

plan for generation unit retirements considering the low utilization of many reserve 

generation units. 

GPA operates and maintains several power plants that have very low capacity 

factors. Capacity factor is a measure of the utilization of generation units or plants. 

Annual average capacity factor is computed by dividing the energy produced by a 

generation unit or plant over a year by the product of the maximum continuous rated 

(MCR) output of the unit and the number of hours in the year. Because these units with 

low capacity factors are seldom used and require continued investment to keep them 

operable, the IRP should evaluate these facilities for potential retirement. 

GPA has identified Dededo Diesel and Marbo CT power plants as candidates for 

retirement at the beginning of FY 2014 and has considered them as being retired as part 

of the underlying assumptions for the FY 2012 Integrated Resource Plan. Table 1-3 

illustrates the historical actual capacity factor for each generation plant on the GPA grid. 

Table 1-3: Five-Year Historical GPA Generation Utilization

Capacity Factor (%)

Generation Plant FY 2007 FY 2008 FY 2009 FY 2010 FY 2011 FY 2012

5-yr 

Avg.

Cabras 1&2 57.0% 47.0% 48.5% 47.3% 46.3% 51.0% 48.0%

Cabras 3&4 60.1% 71.1% 72.1% 70.9% 73.0% 71.4% 71.7%

MEC (Piti 8&9) 76.2% 73.9% 81.6% 78.4% 78.2% 68.9% 76.2%

Tanguisson 1&2 31.9% 41.7% 29.3% 41.0% 33.9% 28.2% 34.8%

Dededo CT 0.8% 0.6% 0.3% 0.1% 0.0% - 0.2%

Macheche CT 2.8% 2.2% 0.8% 0.4% 1.1% 0.4% 1.0%

Marbo CT - - - - - - - 

TEMES CT (Piti 7) 11.3% 6.2% 1.9% 3.9% 2.4% 0.4% 3.0%

Yigo CT - - 0.4% 0.3% 0.4% 1.5% 0.5%

Dededo Diesel 0.1% - 0.1% 0.1% 0.1% - 0.1%

Manenggon (MDI) 0.4% 2.3% 1.7% 1.0% 2.9% 5.0% 2.6%

Talofofo Diesel 0.2% 1.1% 1.5% 0.8% 3.2% 4.3% 2.2%

Tenjo Vista 5.6% 12.2% 7.2% 3.7% 5.7% 7.3% 7.2%

Source: GPA Generation Division
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1.10 Risk

GPA must consider several risks to creating and executing upon the 

recommendations of the IRP including: planning risk, financial risk, and regulatory risk. 

GPA must institutionalize uncertainty and risk management throughout all its planning: 

operational, financial, medium-range, and long-range. 

1.10.1 Planning Risk

Long-term electric power supply planning must consider risk. As part of the 

planning process, the utility needs to forecast loads, sales, economic variables, and 

revenues. Additionally, it must forecast the capital, fixed, and variable costs for various

power supply candidates. The longer the forecast, the greater the risk for divergence from 

what may actually transpire.

In order to plan well, GPA needs to consider scenario planning. “Scenario 

planning, which considers adaptive behavior under alternative futures, is uniquely suited 

for identifying and categorizing unknown utility risks.”6

In addition to forecast risk, the volatility of fuel prices and tightening of supply 

for crude oil is of great concern and threatens the affordability of electricity on Guam. It 

is also having an enormous financial impact as free cash flows are being diverted to fuel 

inventory. This run-up on fuel price is pushing the drive to fuel diversity and the 

introduction of renewable energy.

1.10.2 Financial Risk

There are several chronic financial concerns that may affect GPA’s ability to meet 

its resource planning goals:

• Low cash on hand, low debt service coverage ratios and high debt to equity ratios;

• GPA's growing long-term Bond debt and associated financial obligations; and

• GPA’s credit rating.

GPA’s available cash on hand is much lower than the comparable utilities and 

generally does not follow standard industry practice. At the end of FY 12, GPA reported 

approximately 46 days of cash on hand. GPA would like to reach a long-term goal of 60 

days cash on hand. 

 6 Karyl B. Leggio, David L. Bodde, and Marilyn L. Taylor. “Managing Enterprise Risk: What the Electric 

Industry Experience Implies for Contemporary Business.” Oxford, U.K.: Elsevier Ltd. 2006. page 14.
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According to a report commissioned in 2009, GPA had an equity ratio at that 

time, based on equity to total capitalization calculation basis, of approximately 22% (a 

debt to total capitalization of 78%). “If GPA wishes to obtain consistent long-term 

investment-grade ratings and reduce its financial risk profile, it is incumbent on the utility 

to increase its system equity level as part of its capital funding needs. A higher level of 

system equity will benefit GPA and its customers by reducing debt and associated debt 

service costs needed to fund capital expansion and system improvements over the longrun.”7

 

As GPA’s long-term fixed debt obligations continue to grow, GPA will have less 

financial flexibility to deal with unexpected occurrences, such as equipment failures, 

weather events, etc., while at the same time continuing to execute on its capital 

improvement plans, including resource planning activities. As more money is tied up 

with fixed debt service obligations, less money is available for unexpected occurrences 

and programs and projects get delayed or abandoned. Executing on its capital 

improvement planning in a timely, consistent manner has been a challenge for GPA over 

the years, due to a lack of financial and personnel resources. 

Meeting GPA’s stated goals of improving debt service coverage ratios, increasing 

cash on hand, and lowering its debt to equity ratios will move GPA towards its strategic 

goal of obtaining secure investment-grade credit ratings, which will enable GPA both to 

better access financial markets and to lower its future debt costs. If GPA is unable to 

fulfill its debt service coverage obligations, its credit rating will fall further, and it may be 

in default of its bond covenants. 

1.10.3 Regulatory Risk

Federal and local legislation regarding environmental and utility policy may have 

a large impact upon the choice of competing planning portfolios. The concerns are well 

founded and fundamentally affect the economics of the addition of certain types of 

generation. Also, the ability of GPA to recover its operational and future investment costs 

through rates set by the Guam PUC is of concern. Without sufficient rate-based 

revenues, GPA cannot make necessary investments to improve reliability and customer 

service, mitigate environmental impacts, and lower fuel costs, among other strategic 

goals. 

 7 Working Capital and Cash Reserve Financial Analysis, R. W. Beck, Inc., December 2009, page 1-2.
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2 Scope of Work and Approach

2.1 Scope of Work

This IRP study is part of a regular cycle of overall utility and strategic planning. 

As part of the IRP, GPA has investigated the following issues related to critical near-term 

and potential long-term strategic decisions:

• The need for future generation capacity or the need to change to a different mix of 

generation resource options;

• Effects of generation retirements singly and in combination;

• Effects of compliance with new requirements of the United States Environmental 

Protection Agency;

• Benefits and costs of potential demand side management (DSM) options including 

sea water air conditioning/cooling;

• Effects of meeting the required renewable portfolio standards

• Analysis of the efficacy of energy storage devices to ameliorate the impact of 

intermittent renewable energy additions and known existing system stability issues; 

and

• Identify an optimized short- and long-term generation expansion plan which 

considers reliability, cost, and diversification goals.

In preparing this report, GPA and its consultants have made certain assumptions 

with respect to the conditions which may exist or events which may occur in the future. 

While we believe these assumptions to be reasonable for the purpose of this study, they 

are dependent upon future events, and actual conditions may differ from those assumed. 

In addition, we have relied upon certain information provided to us by others. While we 

believe the use of such information and assumptions to be reasonable for the purposes of 

this study, we offer no other assurances with respect thereto, and some assumptions may 

vary significantly due to unanticipated events and circumstances. To the extent that 

actual future conditions differ from those assumed herein or provided to us by others, the 

actual results will vary from those projected herein. 
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GPA has combined a comprehensive analytical approach and stakeholder input 

and direction in its development of this IRP. 

2.2 Approach

As part of the analytical approach, GPA completed the following tasks:

• Reviewed planning environment and established parameters to guide analysis;

• Developed planning, scenario, and modeling inputs and assumptions;

• Ensured adequate load and resource balance by comparing demand forecast and 

current and future resource assumptions;

• Defined candidate resource options, including supply-side and demand-side 

management options;

• Explored and characterized the effects to reliability of generation retirement 

singly and in combination using the Probabilistic Investigation of Capacity and 

Energy Shortages (PICES) tool;

• Used the capacity expansion optimization tool STRATEGIST to determine the 

optimal portfolio of least cost options that eliminates annual capacity deficits 

according to capacity reserve margin requirements;

• Used scenario analyses to help determine a diversified resource mix that is robust 

across the range of alternative demand and fuel price outcomes;

• Selected a preferred portfolio using evaluation criteria: Cost, risk, system 

reliability, and environmental impact.

2.2.1 Review Planning Environment

GPA considers several of its long-term stated strategic goals, including fuel 

diversification and meeting renewable portfolio standards, in this IRP by including both 

conventional thermal and renewable generation options as candidate resources, as well as 

considering alternative fuel types. In addition to the option of adding various types of 

renewables in the future, such as biomass, solar, wind, and ocean thermal energy 

conversion, GPA is in the process of acquiring approximately 40 MW of long-term 

renewable power, both solar and wind resources, and those resources are included as part 

of the study beginning in year 2013. GPA also focused on evaluating options that might 

help it meet its strategic goal of fuel diversification. Liquefied Natural Gas (LNG) was 

considered as an alternative fuel type for both GPA’s existing oil-fired resources (which 

would be converted to burn natural gas) as well as new combined cycle options. These 
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strategic goals of diversification and renewable standards helped define and shape the 

options evaluated and the options chosen to represent the optimal portfolio. 

2.2.2 Develop Inputs & Assumptions

GPA uses a software tool STRATEGIST to determine an optimal expansion plan 

based on lowest system costs and meeting reliability parameters. With that, critical 

information is input such as operational costs (fixed and variable costs, production 

efficiencies, etc.), anticipated load requirements, seasonal use, and 

availability/maintenance scheduling, to name a few. For new resources, construction 

timelines and capital/construction cost assumptions are also applied.

In addition to these inputs, GPA must consider impacts of changes in capital 

costs, current and anticipated environmental legislation, and uncertainties in Guam’s

economic growth and fuel availability and pricing. Assumptions regarding these topics 

are typically made and various scenarios are developed in order to evaluate their impact 

on portfolio choices.

2.2.3 Ensure Adequate Load & Resource Balance

As the sole power utility on Guam, GPA must ensure reliable power is available 

to its customers. System availability and reliability are factors in determining when to 

bring in the next resource. System reserve margins ensure that the system is capable to 

serve its customers when a unit or several units are not operational due to planned 

maintenance or unplanned forced outages. R.W. Beck consultants recommended that a 

50-60% reserve margin is appropriate for Guam based on the idea that the system should 

be able to withstand two large generators being out of commission at the same time. GPA 

validated this recommendation using PICES.

2.2.4 Define Candidate List

The selection of potential generation resources options, known as “supply side 

options,” can have a serious effect on the results of an IRP and eventually on the islandwide power system itself. Inappropriate unit selection may affect system reliability and 

may put the system at risk for system blackouts. Additional considerations must include 

land requirements, local and federal regulation restrictions, environmental impacts, 

availability of fuel resources, and fuel diversification. GPA carefully considered these 

influences and impacts when selecting which supply side options to include as potential 

resources.

GPA must also consider “demand side options”—or options for the customer

side. These are typically referred to Demand-Side Management (DSM) programs. They 

may be in the form of rebate program that promotes energy efficient appliances or 

displacing electricity use by an alternate source such as ocean water cooling for large 

hotel air conditioning systems. GPA evaluated potential DSM options as part of the IRP.
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2.2.5 Determine Effects on Reliability of the Retirement of Existing Generation Units

GPA explored and characterized the effects of generation retirement singly and in 

combination using the Probabilistic Investigation of Capacity and Energy Shortages 

(PICES) tool. The key metrics relevant to this investigation include generation system 

loss of load expectation (LOLE), system peak load carrying capability (PLCC), and 

reserve margin (RM).

2.2.6 Determine Optimal Portfolio

In order to determine the optimal portfolio, the modeling software program 

STRATEGIST for resource expansion optimization was used. This software analyzes 

demand requirements, candidate unit operational costs, and financing/bond requirements 

to determine the most economical resource plan for a study period. GPA licensed 

STRATEGIST to perform this task. 

2.2.7 Determine Diversified Resource Mix

The STRATEGIST software was used to determine the most economical plans 

across a variety of demand and fuel price scenarios. GPA believes that the most 

economic plans will have substantial benefits in addition to being the least cost option 

and will help meets GPA’s long-term strategic goal of fuel diversification.

2.2.8 Select Preferred Portfolio

After all the modeled scenarios were run, a preferred portfolio was selected that 

incorporates a least cost optimal plan and provides for reliability, renewable portfolio 

requirements, and fuel diversification.

2.2.9 Stakeholder Process

GPA uses a stakeholder process in an effort to involve the community affected by 

the choices and outcomes of the IRP in its development. This process allowed GPA to 

provide the community progress reports on the plan and also initiated dialogue on 

assumptions and risk considerations being used for new resource candidates, fuel 

forecasts and availability, and local and federal regulations. 

GPA selected representatives from different areas in the community and held 

three public meetings that presented progress information on the current state of GPA, 

anticipations of the IRP, information used in the IRP, and the modeling results. GPA 

held stakeholder meetings in April 2012 and October 2012.

GPA initiated the stakeholder process by selecting and inviting people from the 

community which represent the following areas:

• Department of Defense (DOD);
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• Hotel Industry (Guam Hotel & Restaurant Association);

• Construction Industry (Guam Contractors Association);

• Financial Institution (Bank of Guam);

• Governor of Guam;

• Guam Legislature;

• Government Agencies (Guam Energy Office, Guam Chamber of Commerce, Port 

Authority of Guam, Civilian Military Task Force/DPW, Guam Environmental 

Protection Agency);

• Environmental;

• Public Utilities Commission of Guam (Guam PUC); and

• Consolidated Commission on Utilities (CCU).

GPA completed three public meetings during the development of the IRP. The 

initial meeting on April 25, 2012 provided an overview of GPA and its objectives relative 

to the IRP as well as preliminary data acquired. The meeting also discussed the key 

assumptions being used. The second meeting on April 27 allowed stakeholders to 

consider information from the first meeting and provide feedback. The third meeting 

provided results and afforded the stakeholders an opportunity to discuss the outcomes of 

the IRP.
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3 Future Power Requirements 

GPA and PL Mangilao Energy, LLC worked to prepare baseline energy sales and 

load forecast8 founded upon a conservative view of Guam’s economic prospects. Guam –

and the US – is enduring a protracted period of slow growth as the Great Recession draws 

to a close. Mangilao has relied upon the Moodys Analytics (formerly Economy.com) 

outlook for Guam, supplemented with GPA’s knowledge and experience of the local 

economy. GPA used this baseline forecast for its Financial Management Plan, FY 2012 

base rate case. Therefore, there is a consistent set of forecasts used throughout GPA’s 

regulatory and financial activities.

Additionally, Mangilao developed forecast scenarios considering assumptions on 

a proposed military build-up on Guam as well as known, budgeted Department of 

Defense projects. These scenarios are based on local research on construction, labor, 

tourism, and anticipated DOD growth. The levels of growth due to DOD buildup present 

significant construction and employment opportunities. Ultimately, this affects Guam’s 

economic outlook. Potential infrastructure spending due to primarily DOD contracts and 

subsequent infrastructure growth will impact the GPA electrical system due to energy 

requirements necessary to support new load and the capability of the system to meet 

energy demand.

3.1 The Econometric Model

There are several variables that go into an econometric model. Economic 

forecasts for Guam and Japan by Moody’s are used to provide the basis for tourism and 

construction assumptions for Guam. Additional information that will affect construction 

activities, such as DOD buildup, is provided through the Department of Defense 

Quadrennial Report and meetings with DOD representatives. Historical weather and 

peak load data is also used to develop patterns for energy use (sales). 

GPA uses the latest E-view program version to run its forecasting model. This is 

a Windows-based forecasting package developed by QMS (Quantitative Micro 

Software). Figure 3-1 illustrates the GPA Forecast Model. 

 8 The GPA Sales and Load Forecasting Process Documentation, 2012, P.L. Mangilao, LLC.
DEMAND FORECAST

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2013 Integrated Resource Plan

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Figure 3-1, Econometric Model9

 9 The GPA Sales and Load Forecasting Process Documentation, 2012, P.L. Mangilao, LLC., p. 29
ENVIRONMENTAL CONSIDERATIONS

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2013 Integrated Resource Plan

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3.2 Summary of Load Forecast Scenarios

The current consensus on the military build-up differs greatly the plans made by the 

Department of Defense represented in the FY 2008 Integrated Resource Plan. The current ideas 

for military buildup will not have as dramatic an effect on GPA’s peak demand and energy 

production requirements. Figure 3-2 and 3-3 shows the peak demand and energy sales forecasts 

P.L. Mangilao developed for GPA. GPA used the “EPA Delay” and Baseline forecasts in its IRP 

analysis. 

P.L. Mangilao developed low and high tourism and infrastructure development economic 

scenarios. The resulting scenario forecasts include a “EPA Delay”, low tourism-high 

infrastructure (L&H), high tourism-low infrastructure (H&L), and high tourism-high 

infrastructure.

260

270

280

290

300

310

320

330

2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025

Demand (MW)

Fiscal Year

Forecast Scenarios: Peak Demand 

Actual

Baseline

EPA Delay

H&L

L&H

H&H

Figure 3-2, Integrated Resource Plan Peak Demand Forecast Scenarios
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 1,300,000

 1,400,000

 1,500,000

 1,600,000

 1,700,000

 1,800,000

 1,900,000

 2,000,000

 2,100,000

 2,200,000

 2,300,000

2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

Sales (MWH)

Fiscal Year

Forecast Scenarios: Sales

Actual

Baseline

EPA Delay

H&L

L&H

H&H

Figure 3-3, Integrated Resource Plan Energy Sales Scenarios

3.2.1 Baseline Forecast Assumptions

The primary determinant of this modest growth is an increase in employment and real 

household income over the next few years as currently budgeted capital expenditures for the 

development of civilian and military infrastructure projects are completed over the next few 

years. The GPA forecast is both a budget forecast and a planning forecast that represents a 

consensus view developed in a consultative process involving both SPORD and GPA senior 

management. As such, it is not simply raw model output – instead, it reflects the collective 

understanding and best ideas of all of the participants in the budgeting and planning process, and 

the unique business risks that GPA’s most senior management deem to be most important to the 

future of GPA

First, GPA and its consulting partners made several important assumptions in preparing 

the forecast. First, GPA assumed the actual weather recorded at the international airport, as 

reported by the National Weather Service, as representative for Guam. In the forecast period, 

normal weather was assumed to be the average weather observed over the past 30 years.
ENVIRONMENTAL CONSIDERATIONS

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2013 Integrated Resource Plan

3-5

Second, GPA and its consulting partners assumed GPA’s retail price of electricity, taken 

as average revenue per kWh inclusive of all fuel costs, utility taxes and surcharges, would 

increase with the general rate of inflation as measured by the Guam Consumer Price Index (CPI) 

published by the Guam Bureau of Labor Statistics. This assumption of constant real prices is 

commonly used in utility budget forecasting. This is equivalent to assuming that on average all 

of the items purchased by GPA – labor, materials, and supplies and fuel – have cost escalation at 

approximately the same rate as general inflation. In a long-term forecast, this is usually a 

reasonable assumption.

The forecasting process is designed to utilize the Moody’s Analytics (formerly 

Economy.com) economic forecast for Guam. The Moody’s forecast used in this work was 

prepared in August 2011, the most current forecast available at that time. This forecast calls for 

Guam Civilian, Non-Agricultural Total Employment to grow at 3.24% annually over the period 

2010-2015. However, based upon fieldwork on Guam, P.L. Mangilao observes that Mainland 

analysts underestimate Guam’s opportunities for long-run economic growth because Mainland 

analyst forecasts do not take into account two important factors. They do not recognize that 

Guam’s tourism industry may grow, and they do not take into account that there are significant 

infrastructure and military construction projects that are either under way or have been given 

clear schedules as budgeted capital expenditures. We have not taken these expectations for more 

rapid growth into account in this forecast. Those expectations are more appropriately taken into 

consideration in alternative planning scenarios.

The earthquake, tsunami and the ensuing nuclear disaster were a tragedy for the Japanese 

people. Over the spring and early summer of 2011 Japanese tourism suffered a decline that has 

severely hurt Guam’s hospitality related businesses. Japanese tourist visitation is recovering, 

however, and in recent months visitation has been improving at double-digit rates. The base 

forecast allows for this temporary decline in tourism during the upcoming budget period in an 

appropriate manner. By the end of the forecast period, there will be no lingering ill-effects on 

Guam’s hospitality industry.

Expectations regarding sales to the U.S. Navy (Navy) are made econometrically, after 

discussion with the Navy and GPA management and staff. Sales to the Navy were 361.5 gWh in 

2010/11. Navy sales grew at an average rate of +2.02% over the period 2005 through 2010, and 

are expected to grow at an average annual rate of 0.81% over the period 2010 through 2015.

Based upon dozens of interviews with subject experts that Mangilao has conducted since 

2005, the timing and magnitude for the military build out on Guam is completely uncertain. It 

seems that increasing the military presence on Guam is most probable, but it also seems that 

almost none of the important decisions have been taken as of yet by the U.S. government. 

Because of this uncertainty, the military build out must be addressed in scenarios. The baseline

forecast includes only those military and infrastructure projects for which funds are currently

obligated.
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3.2.2 Alternative Forecast Assumptions

The Moody’s Analytics (formerly Economy.com) economic forecast for Guam tends to 

be statistical, and extrapolates existing trends. It does not contain information for the proposed 

Military build-up. Therefore, GPA and Mangilao created an alternative forecast considering the 

impacts of the proposed military buildup. GPA made the assumption that the military would 

begin no earlier than two years from the start of the forecasting period. This assumes that the 

Department of Defense requires between two to five additional years to complete a new 

Environmental Impact Study (EIS). Furthermore, based on news articles and other local and 

national sources of information, Mangilao developed a civilian and military project list and 

timetable for use in the forecast.10 GPA’s “EPA Delay Scenario” forecast or the Alternative 

forecast used in the Integrated Resource Plan refers to P.L. Mangilao’s Low Tourism/Low 

Infrastructure case with appropriate time delay for the development of a new EIS.11

The “EPA Delay Scenario” forecast assumes a 1% growth as an arbitrary middle ground 

to characterize the historical experience of Guam tourism industry since 1993. Several reviewers 

of the GPA forecast have pointed out that in real life the industry would go through capital 

spending cycles in which it periodically overbuilt (boom/bust cycles or business cycles), but 

those cycles are really problematic to model. Although, GPA’s does believe that boom/bust 

cycles are more typical of the tourism/hospitality industry, the Alternative forecast simply 

assumes that the industry continues to build at a steady, prudent level just sufficient to serve 

growth in tourism. The “EPA Delay Scenario” forecast assumes a $12.1 billion of civilian and 

military construction projects ending 2025. These projects include projects identified in civilian 

and military budgets as well as speculative buildup projects.

 10 The GPA Sales and Load Forecasting Process Documentation, 2012, P.L. Mangilao, LLC., Table 3, p. 16 11 The GPA Sales and Load Forecasting Process Documentation, 2012, P.L. Mangilao, LLC., p. 10
ENVIRONMENTAL CONSIDERATIONS

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4-1

4 Future Fuel Costs & Choices for GPA

GPA contracted SAIC to develop the fuel price forecasts for Residual Fuel Oil (RFO), 

Diesel Oil (Diesel), and Liquefied Natural Gas (LNG). Following is a summary of the forecast 

methodology and prices: 

• In the current forecast (August 2012), the global oil price is expected to increase from 

$79/barrel in 2010 to $92/barrel (2011$) in 2015, and thereafter prices are expected to 

grow at an annual average rate of 1.1%. Continued decline in conventional sources of 

production (for example, Iran) and threat of supply disruptions due to global disturbances 

continue to pose substantial threat to future oil supply; however potential new sources of 

oil recovery due to technological advancement (for e.g., light tight oil/ shale oil) and 

reduced demand due to slower than expected economic recovery, political disturbances in 

the European Union (EU) and reduced growth rates in India and China prevent near-term 

oil prices from rising substantially.

• In the medium to longer-term, it is expected global oil prices will continue to rise, 

however at a slower rate of 1.1% average annually beyond 2015 mostly due to 

expectation of demand growth being lower than anticipated before, and new supply 

sources and increasing fuel competition over time.

• The views on oil prices reflect recent trends in other published forecasts which were 

reviewed. In addition, there has been an observed substantial drop (about 10%) in Brent 

futures for 2015 between May-2011 and June-2012.

• Guam delivered prices are calculated assuming similar contract terms as in current 

contracts. After adjusting for the fixed formula adders in the contracts, Guam delivered 

HSFO price for 2015 is $13.03/MMBtu (in 2011$).
ENVIRONMENTAL CONSIDERATIONS

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60

70

80

90

100

110

120

2012201320142015201620172018201920202021202220232024

2025

2026202720282029203020312032203320342035

2011 Forecast HSFO Delivered Price

(2011$/Barrel)

2012 Forecast Delivered Guam HSFO Price 

(2011$/MMBtu)

Source: R. W. Beck (an SAIC Company)

Figure 4-1, HSFO Delivered Price to Guam Forecast Comparison (2012 with 2011)

Delivered LNG Price Forecast:

• It is expected that Asian LNG prices will generally continue to experience linkage to oil 

prices. Recently some sporadic examples introduced Henry Hub-based LNG pricing for 

Asian shipments. However, the final outcome of these contracts and actual delivered 

future prices under these terms are highly uncertain. In addition, these contracts often 

represent large potential buyers with strong negotiating power to acquire ownership in 

upstream liquefaction projects.

• In the Base Case forecast for LNG delivered to Guam, the continued assumption is the 

LNG price is linked by indexation of approximately 11% to Japanese crude oil prices 

(“JCC” and JCC is assumed to continue to trade at a small discount to Brent as it has 

historically). We also continue to assume that Guam, due to its geographical location 

compared to Japan, will be able to realize a fixed $0.30/MMBtu discount compared to the 

JCC-indexed price that primarily reflects a LNG price delivered to Japan. 

• For Low and High Cases, it is assumed an annual average 11% and 15% indexation to 

JCC prices respectively. Figure 4-2 shows LNG price sensitivities.
ENVIRONMENTAL CONSIDERATIONS

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0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

201220132014201520162017201820192020202120222023202420252026202720282029203020312032203320342035

Base Case Guam LNG Landed Price (2011$ per 

MMBtu)

High Case Guam LNG Landed Price (2011$ per 

MMBtu)

Low Case Guam LNG Landed Price (2011$ per 

MMBtu)

Source: R. W. Beck (an SAIC Company)

Figure 4-2, LNG Prices– Base, Low and High Cases (2011$/MMBtu) (Land Infrastructure 

Premiums Excluded)

Table 4-1 presents SAIC’s updated fuel price forecasts for Guam. Table 4-2 presents 

LNG price sensitivities.
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Table 4-1, Fuel Price Forecasts for Guam

Delivered 

Price for 

LNG 

(2011$/ 

MMBtu)

HSFO LSFO HO LNG HSFO LSFO HO 

2012 96 99 139 12.72 15.27 15.84 24.15

2013 91 94 131 12.06 14.48 15.05 22.83

2014 86 90 124 11.57 13.74 14.31 21.58

2015 82 85 117 10.84 13.03 13.60 20.40

2016 83 87 119 10.92 13.23 13.80 20.73

2017 84 88 121 11.00 13.43 14.00 21.07

2018 86 89 123 11.09 13.64 14.20 21.41

2019 87 90 125 11.17 13.84 14.41 21.75

2020 88 92 127 11.34 14.05 14.62 22.11

2021 89 92 128 11.43 14.17 14.74 22.31

2022 90 93 129 11.53 14.30 14.86 22.51

2023 91 94 131 11.62 14.42 14.99 22.72

2024 91 95 132 11.72 14.54 15.11 22.92

2025 92 96 133 11.81 14.67 15.23 23.13

2026 93 96 134 11.91 14.79 15.36 23.33

2027 94 97 135 12.00 14.91 15.48 23.54

2028 94 98 136 12.10 15.03 15.60 23.75

2029 95 99 138 12.19 15.16 15.73 23.96

2030 96 99 139 12.29 15.28 15.85 24.17

2031 97 100 140 12.39 15.42 15.99 24.39

2032 98 101 141 12.49 15.55 16.12 24.61

2033 98 102 143 12.60 15.69 16.26 24.84

2034 99 103 144 12.70 15.82 16.39 25.07

2035 100 104 145 12.81 15.96 16.53 25.30

 

Fuel Oil Delivered Price

(2011$/Barrel)

Fuel Oil Delivered Price

(2011$/MMBtu)

Guam Delivered Fuel Price Forecast (Base Case)

NOTE: Delivered LNG price excludes infrastructure premium
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Table 4-2, LNG Price Sensitivities

Guam Delivered LNG Price: Sensitivity

Base Case 

Guam LNG 

Landed Price 

(2011$ per 

MMBtu)

High Case 

Guam LNG 

Landed Price 

(2011$ per 

MMBtu)

Low Case 

Guam LNG 

Landed Price 

(2011$ per 

MMBtu)

2012 12.72 13.58 11.96

2013 12.06 13.51 11.17

2014 11.57 13.06 10.59

2015 10.84 13.37 9.73

2016 10.92 13.59 9.89

2017 11.00 13.82 10.05

2018 11.09 14.05 10.22

2019 11.17 14.28 10.39

2020 11.34 14.52 10.56

2021 11.43 14.65 10.66

2022 11.53 14.79 10.76

2023 11.62 14.92 10.86

2024 11.72 15.06 10.97

2025 11.81 15.20 11.07

2026 11.91 15.34 11.17

2027 12.00 15.48 11.27

2028 12.10 15.62 11.37

2029 12.19 15.76 11.47

2030 12.29 15.90 11.58

2031 12.39 16.05 11.69

2032 12.49 16.20 11.80

2033 12.60 16.35 11.91

2034 12.70 16.50 12.02

2035 12.81 16.66 12.13

NOTE: Delivered LNG price excludes infrastructure premium
ENVIRONMENTAL CONSIDERATIONS

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2013 Integrated Resource Plan

5-1

5 Environmental Considerations

This section discusses the environmental regulations facing GPA, associated compliance 

challenges, and the impacts to operations and costs. It is not an exhaustive discussion of all 

environmental efforts underway, but focuses instead on those regulations directly affection the 

resource options considered and proposed in the IRP. The IRP relies on information GPA’s 

Environmental Strategic Plan (ESP) developed with TRC Companies, Inc.

5.1 National Ambient Air Quality Standard (NAAQS)

The U.S. Environmental Protection Agency (EPA) has taken several actions to strengthen 

the NAAQS. These new standards will have significant effects on how GPA will be able to 

operate its units and the amount of air pollutants coming from its plants. Three primary 

pollutants: sulfur dioxide (SO2), nitrogen dioxide (NO2), and particulate matter (PM), will be the 

focus of the NAAQS compliance efforts for Guam.

5.1.1 Sulfur Dioxide, SO2

For SO2, the new ambient air standards consist of 196 micrograms per cubic meter (μ/m3

) 

averaged over a one hour period, 1,300 (μ/m3) over a 3 hour period, 365 (μ/m3) over a 24 hour 

period, and 80 (μ/m3) annually. These new regulations will be 6 to 7 times more restrictive than 

current regulations on the amount of SO2 GPA is allowed to release. 

Cabras and Tanguisson power plants provide a majority of GPA’s power. Recent 

monitoring shows that GPA’s Cabras and Tanguisson plants do not comply with the new 

NAAQS SO2 standards, however further monitoring will be required to confirm this. Piti and 

Tanguisson areas already are designated as non-attainment areas under the old standard. 

Monitoring activities and revisions to the State Implementation Plans will cost approximately 

$4.2 million over the next four years.

The one hour SO2 standard must be met by June 2017. Options to achieve compliance 

include construction and operation of SO2 scrubbers at affected plants, reducing the sulfur 

content of fuel oil being burned at affected plants, or switching from oil to natural gas through 

the importation of liquefied natural gas (LNG). All of these options will cost several hundred 

million dollars and they are being economically and operationally evaluated as part of the IRP 

process. For SO2, the new ambient air standards consist of 196 micrograms per cubic meter 

(μ/m3) averaged over a one hour period, 1,300 (μ/m3) over a 3 hour period, 365 (μ/m3) over a 24 

hour period, and 80 (μ/m3

) annually. These new regulations will be 6 to 7 times more restrictive 

than current regulations on the amount of SO2 GPA is allowed to release. 

Cabras and Tanguisson power plants provide a majority of GPA’s power. Recent 

monitoring shows that GPA’s Cabras and Tanguisson plants do not comply with the new 
ENVIRONMENTAL CONSIDERATIONS

Guam Power Authority

2013 Integrated Resource Plan

5-2

NAAQS SO2 standards, however further monitoring will be required to confirm this. Piti and 

Tanguisson areas already are designated as non-attainment areas under the old standard. 

Monitoring activities and revisions to the State Implementation Plans will cost approximately 

$4.2 million over the next four years.

The one hour SO2 standard must be met by June 2017. Options to achieve compliance 

include construction and operation of SO2 scrubbers at affected plants, reducing the sulfur 

content of fuel oil being burned at affected plants, or switching from oil to natural gas through 

the importation of liquefied natural gas (LNG). All of these options will cost several hundred 

million dollars and they are being economically and operationally evaluated as part of the IRP 

process.

5.1.2 Nitrogen Dioxide, NO2

For NO2, the new ambient air standard requires no more than 100 parts per billion 

concentration averaged over a one hour period for any area. It is likely that many major sources 

of NO2 emissions, including all of GPA’s power plants, will find it difficult to demonstrate 

compliance.

GPA does not currently know if it meets this new standard at locations near its generating 

facilities. GPA proposes to employ continuous air monitoring to determine NO2 at representative 

sites in the vicinity of the GPA facilities.

5.1.3 Particulate Matter, PM

For particulate matter designated as “fine particles” (2.5 micrometers or smaller), PM2.5, 

the new ambient air standard requires no more than 35 (μ/m3) averaged over a 24 hour period 

and 15 (μ/m3) on average annually. 

GPA does not currently know if it meets these new standards at locations near its 

generating facilities. GPA proposes to employ continuous monitoring to determine PM2.5 at 

representative sites in the vicinity of the GPA facilities.

5.2 Maximum Achievable Control Technology (MACT)

Three recently promulgated standards for MACT that apply to GPA. These new 

standards will have significant effects on how GPA will be able to operate its units and the 

amount of metals, chloride, and carbon monoxide emissions coming from its plants. Two 

primary types of generation, steam and reciprocating engine technologies will be the focus of the 

MACT compliance efforts for Guam.
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5.2.1 Steam Electric Generation, “Boiler MACT”

The Boiler MACT standards promulgated by the U.S. EPA in December 2011 apply to 

four of GPA’s larger units: Cabras 1 and 2 and Tanguisson 1 and 2. The standards call for a 

significant reduction in metal and chloride emissions. 

Recent testing shows that GPA will have to modify the operation of Cabras 1 to control 

for metal emissions. All four units may have to be modified to control for acid gases. Fuel and 

stack testing will need to be done to verify their compliance status. During the last quarter of 

calendar year 2012, discussions with US EPA uncovered issues regarding the temperature at 

which the emission tests were conducted. GPA scheduled another test for Cabras 1 for the first 

quarter of calendar year 2013 at the temperature US EPA indicated to be correct. Results from 

this test will confirm if limits have been exceeded.

The Boiler MACT standard must be met by May 2015, however there is a possibility to 

receive an extension of the initial compliance date.

Electrostatic Precipitators (ESPs) installed on each unit would enable achievement of the 

Boiler MACT compliance requirements, however, these are costly and scrubbers would still need 

to be installed in order to meet the NAAQS requirements. Because scrubbers alone could 

address compliance for NAAQS and Boiler MACT, GPA has assumed that it would install 

scrubbers, without the need for ESPs, and have the scrubbers operational one month prior to the 

NAAQS compliance date of May 2017. This scenario would require agreement by the EPA for a 

full two-year extension beyond the original Boiler MACT initial compliance date. 

The cost to install scrubbers is estimated to be between $220 to $362 million and testing 

costs of $200,000 per year for all four steam units. The Boiler MACT standards promulgated by 

the U.S. EPA in December 2011 apply to four of GPA’s larger units: Cabras 1 and 2 and 

Tanguisson 1 and 2. The standards call for a significant reduction in metal and chloride 

emissions. 

Recent testing shows that GPA will have to modify the operation of Cabras 1 to control 

for metal emissions. All four units may have to be modified to control for acid gases. Fuel and 

stack testing will need to be done to verify their compliance status. During the last quarter of 

calendar year 2012, discussions with US EPA uncovered issues regarding the temperature at 

which the emission tests were conducted. GPA scheduled another test for Cabras 1 for the first 

quarter of calendar year 2013 at the temperature US EPA indicated to be correct. Results from 

this test will confirm if limits have been exceeded.

The Boiler MACT standard must be met by May 2015, however there is a possibility to 

receive an extension of the initial compliance date.

Electrostatic Precipitators (ESPs) installed on each unit would enable achievement of the 

Boiler MACT compliance requirements, however, these are costly and scrubbers would still need 

to be installed in order to meet the NAAQS requirements. Because scrubbers alone could 
ENVIRONMENTAL CONSIDERATIONS

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2013 Integrated Resource Plan

5-4

address compliance for NAAQS and Boiler MACT, GPA has assumed that it would install 

scrubbers, without the need for ESPs, and have the scrubbers operational one month prior to the 

NAAQS compliance date of May 2017. This scenario would require agreement by the EPA for a 

full two-year extension beyond the original Boiler MACT initial compliance date. 

The cost to install scrubbers is estimated to be between $220 to $362 million and testing 

costs of $200,000 per year for all four steam units.

5.2.2 Reciprocating Internal Combustion Engines, “RICE MACT”

GPA is subject to RICE MACT standards for all 14 medium speed diesel units located at 

the Dededo Diesel Plant (4), Talofofo Diesel Plant (2), Manenggon Diesel Plant (2) and the 

Tenjo Vista Power Plant (6). The RICE MACT also applies to the Cabras 3 and 4 and MEC’s 

Piti 8 and 9 slow speed diesel units. The RICE MACT standards call for a significant reduction 

of carbon monoxide (CO) emissions. 

Recent emissions testing shows that GPA will have to modify the medium speed diesel 

units to control for CO emissions. Testing will need to be done to verify compliance status of 

these units.

The RICE MACT compliance deadline is May 2013. GPA has filed a request for a one 

year extension for all 14 medium speed diesel units burning ultra-low sulfur diesel because there 

is not enough time to comply; extension approval is still pending. The RICE MACT compliance 

is expected to cost $2.2 M in capital costs and $300,000 per year. 

In the same filing, GPA requested exemption for the slow speed diesel units burning residual 

fuel oil (Cabras 3 and 4 and Piti 8 and 9) because compliance would require either changing fuel 

or the installation of compliance equipment. Either option would cost several hundred million 

dollars to implement ($100 to $400 million in capital costs or $70 million per year in increased 

fuel and unit maintenance costs). It is not known if EPA will allow for this exemption.
RELIABILITY ASSESSMENT

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2013 Integrated Resource Plan

6-2

6 Reliability Assessment

6.1 Objective

This section analyzes generation system reliability, reserve margin, and the impacts of 

unit retirements on generation system reliability.

The Guam Power Authority (GPA), the Consolidated Commission on Utilities, and the 

Guam Public Utilities Commission established operational and planning criteria for GPA 

generation system reliability. This criteria establishes a minimum of a one-day in four and a half 

(4.5) years loss-of-load-expectation for the GPA generation system. This does not include 

transmission and distribution system reliability or unreliability. This adopted standard means that 

GPA must use a combination of maintaining prudent generation unit availabilities and prudent 

installed reserve capacity so that the expectation of not being able to serve loads because of an 

insufficiency of generation is less than once in four and a half years. Using this methodology, 

GPA requires a minimum reserve margin policy of 54% to meet the criteria. GPA sets up a 

minimum reserve margin requirement of 54% for Strategist Proview runs. If GPA reserve margin 

falls below this criterion, new generation is brought in. 

Even with many units on long-term shutdown such as Marbo CT and the Dededo CT 

units, GPA’s computed LOLE performance has been steady at one day in ten years. On paper, 

GPA has an installed reserve margin of over 100% given current system peaks. This reserve 

margin is almost twice the minimum required. Since keeping a large reserve margin is expensive, 

GPA needs to prudently consider unit retirements and improvements in generation unit reliability 

to prudently navigate the trade-offs between costs and generation system reliability. 

GPA uses the Probability Investigation of Capacity and Energy Shortages (PICES) 

application to determine system LOLE and reserve margins. However, the Guam Power 

Authority (GPA) engaged R. W. Beck to assist in evaluating which of the GPA generating units 

are candidates for ongoing operations and which units are candidates for retirement considering 

other analytical methods to strengthen our understanding of this complex issue.

6.2 Generation Unit Retirement Effects on Generation System Reliability

The generation system daily loss-of-load-expectation (LOLE) and installed reserve 

margin requirements are evaluated using the state-of the-art Probabilistic Investigation of 

Capacity and Energy Shortages (PICES) software tool. PICES is a public domain computer 

program developed (circa 1981) as a mainframe program by Oak Ridge National Laboratory for 

the Department of Energy. Since then, it has been ported to the Personal Computer (PC). GPA 

uses the PC version. The methodology for using PICES to calculate Daily LOLE and installed 

reserve margin is described in the Guam Power Authority Reliability Procedures Manual. GPA 

will use the two-state unit representation for all its analyses.
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Using the procedures found in the reliability manual, GPA computed the generation 

system daily loss-of-load-expectation reliability. Additionally, it computed the installed reserve 

margin for a generation LOLE of one day in four and a half years. Finally, GPA computed the N2 reserve margin requirement. GPA computed these statistics for the following cases:

• GPA units retired at the end of their expected life

• GPA units retired singly and in combination in each year of the study. 

The inputs to PICES include:

• Generator Unit Name;

• Unit Output Capacity;

• Weeks Required For Planned Maintenance;

• Forced Outage Rate.

6.2.1 PICES Analysis Results

This section summarizes PICES calculations relating to the effects of unit retirement on 

Generation system reliability. GPA has analyzed the impact of retirement on generation system 

reliability for the following groups of units:

• Cabras 1 and 2;

• Cabras 3 and 4;

• Combustion Turbines (CT’s);

• Small Diesels.

Tables 6-1 through 6-2 provide the summary of the reliability impact of different 

generator retirement choices. Table 6-1 gives the impact of retirement of single or closely related

units; Table 6-2 gives the impact of various combinations of combustion-turbine unit retirement 

and Table 6-3 gives the impact of various combinations of small diesel unit retirement. The 

strongest indicator of unit contribution to generation system reliability is the last line in the entry 

for each generator unit. This gives the incremental load carrying capacity (ILCC). Incremental 

Load Carrying Capacity provides a measure of reliability impact per megawatt retired. The 

impact depends on the size of the units, weeks allotted for planned maintenance and forced 

outage rate.

System Peak Load Carrying Capability is an indication of the maximum peak that the 

generation system can support at a specified loss of load expectation (LOLE). In Tables 6-1 

through 6-3, peak load carrying capability is expressed as a peak (MW). The system load 

carrying capability is the percent ratio between the maximum peak and the installed capacity. 

This percent ratio is a metric of the reliability efficiency of the installed generation system. With 

the same LOLE criteria, the system with the higher load carrying capability represents a more 
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efficient use of installed generation: greater portion of total installed generation supports the 

peak rather than supporting reserve commitments.

The system reserve margin requirement is computed for the system at its peak load 

carrying capability (PLCC). This is simply the ratio of the difference between installed capacity 

and the peak load carry capability.

Increasing a unit's size, scheduled maintenance time or forced outage rate all contribute to 

lowering the incremental load carrying capability of a unit. Therefore, these increases will lower 

the reliability impact of a unit's retirement. However, over the range of GPA's unit 

characteristics, regression analysis indicates that increases in unit size have significantly greater 

impact than increases in either forced outage rate or scheduled maintenance size. Thus, the 

granularity of the unit size plays a very significant part in GPA's overall generation system 

reliability.

This effect can be seen when comparing the load carrying capabilities of Cabras 3&4 

versus Cabras 1&2 (Table 6-1). The Per MW reliability impact of retiring Cabras 3&4 is 

substantially greater than that of Cabras 1&2.

Consideration of reliability in the above manner comes with this caveat: the analysis 

considers reliability performance in the average and does not consider the variability (variance) 

inherent in its stochastic nature. Short-term system reliability performance may be better or 

worse than the average. Additionally, it does not consider operational costs. GPA must make 

prudent trade-offs in considering generation retirements and additions. 

Although Strategist results indicate that fuel burn limits do not come into play under 

current levels of output, the load carrying capacity estimates may over-estimate the actual 

reliability under greater output or under lower system capacity. GPA evaluated the maximum 

impact of the fuel burn limits on reliability in its 1999 Integrated Resource Plan. This work 

indicates that fuel burn limits increase reserve margin requirements by about five percent. 

However, using a two-state versus three-state generation model provides a conservative five to 

six percent increase in reserve margin requirement estimates. 

6.2.2 Increasing Generation Unit Availability versus Generation Capacity Addition

Figure 6-1 illustrates analysis performed by GPA for the US Navy on GPA’s generation 

system ability to serve expanding load requirements for the military buildup on Guam.12 Figure 

6-1 shows the peak load carrying capability of the GPA generation system if GPA maintained 

equivalent availability factor (EAF) for each generation units at the minimum Guam Public 

Utility Commission EAF class standard. 

 12 Analysis of Current and Future GPA Generation Reliability. Power Point Presentation to the U.S. Navy on 

January 27, 2009.
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This graph illustrates that obtaining a specific generation system reliability target 

involves a trade-off between system capacity additions and improvements to individual 

generation unit reliability. Improving generation unit reliabilities may most likely prove the 

least-cost option to system capacity additions.

6.3 Reliable Delivery of Power

 

R. W. Beck has conducted a capacity reserve analysis, in coordination with GPA, to 

assist GPA in deciding which units are needed to provide reliable power to meet system demand, 

either actively or in a reserve role, versus those units that could be retired. The capacity reserve 

is the difference between the dependable capacity available and the anticipated peak demand. 

The analysis included a review of the size and reliability of GPA’s primary energy producing 

units and an assessment of the combination of units that provide for the most efficient reserve 

capacity.

R. W. Beck in coordination with GPA developed a list of the GPA units based on 

operating costs, a dispatch stack to identify the existing units that should be dispatched to meet 

system demand in the most cost effective manner. This analysis included a review with GPA to 

identify any unit or system drivers or constraints that would result in adjustment to the stack, 

such as operating limits in the permits, or units that supply voltage support to the grid. Of the 

units that did not actively dispatch to meet system demand, we evaluated which were operable, 

which could be the most efficient resources for reserve capacity, and which units could be useful 

for other reasons, such as voltage support. 

Of the units shown to be the best candidates for reserve and reliability purposes, the team 

assessed the need for any significant maintenance, repairs, renewals, upgrades, or enhancements 

to help ensure the units meet industry standards of operability and be expected to provide for 

adequate, long-term reliability.

R. W. Beck and GPA performed a second iteration of the analysis after conducting the 

modeling of the long-term resource planning to determine if any proposed generating options 

resulted in adjustment to the analysis described above for the existing units.

The results of this non-stochastic analysis indicate that the GPA should consider the 

following units for retirement:

 

• Marbo CT

• Dededo Diesels

• Dededo CT 1

• Dededo CT 2.
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However, if the military buildup becomes a reality, GPA will have to keep both Dededo CT units 

to meet reserve LOLE requirements. GPA could then reconsider these retirements after the 

military buildup construction phase post-2019.

Furthermore, a review of the availability and forced outage data shows that the 

availability of the baseload units were trending upward, which should work to mitigate service 

disruptions.13 However, the two largest baseload units have the highest forced outage rates when 

averaged over several years. Therefore, units that provide the reserve capacity need to have high 

availability and low forced outage rates. Should the Cabras 1 and 2 units be out of service, then 

the Tanguisson units, the reciprocating engine units, and a CT unit would be needed to meet the 

system demand.

Note, officially “retiring” units typically has more relevance in large competitive markets 

with multiple participants, including independent system operators and independent power 

producers, with capacity and energy markets. GPA operates in an island system and is the only 

power provider on the system. Therefore, the retirement decision and associated actions do not 

have a mandated deadline and may need to be deferred until the generating resources identified 

by the long-term resource planning study are in service.

 13 Cabras 3 is on extended force outage due to catastrophic rotor damage.
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Table 6-1, System Reliability Impact of Single Units and Plant Retirement

Sets of Unit Retired

Maximum Net 

Generaton Capacity 

Retired

System Capacity After 

Retirements

System Peak Load 

Carrying Capacity 

(Net) at One Day in 

4.5 Years LOLE

Reserve Margin For 

One Day in 4.5 Years 

LOLE

MW MW (MW) % System Incremental

None 0.0 524.0 339 54.26 64.69 N/A

Cabras Steam Turbine 1 62.0 462.0 292 58.11 63.20 75.81

Cabras Steam Turbine 2 59.0 465.0 293 58.93 63.01 77.97

Cabras 1&2 Steam Plant 121.0 403.0 257 56.8 63.77 67.77

Cabras Slow Speed Diesel 3 35.0 489.0 298 64.02 60.94 117.14

Cabras Slow Speed Diesel 4 36.0 488.0 297 64.32 60.86 116.67

Cabras 3&4 Diesel Plant 71.0 453.0 263 72.01 58.06 107.04

Tanguisson 1 25.0 499.0 310 61.21 62.12 116.00

Tanguisson 2 25.0 499.0 310 61.21 62.12 116.00

Tanguisson 1 & 2 50.0 474.0 287 65.45 60.55 104.00

Tenjo Diesel (2 Units) 8.0 516.0 324 59.39 62.79 187.50

Tenjo Diesel (4 Units) 16.0 508.0 316 60.59 62.20 143.75

Tenjo Diesel (6 Units) 24.0 500.0 308 62.1 61.6 129.17

Talofofo Diesel Units 8.0 516.0 324 59.39 62.79 187.50

MDI Units 10.0 514.0 324 59.39 63.04 150.00

Macheche CT 22.0 502.0 311 61.16 61.95 127.27

Yigo CT 22.0 502.0 311 61.16 61.95 127.27

Dededo CT 1 23.0 501.0 311 61.24 62.08 121.74

Dededo CT 2 22.0 502.0 311 61.16 61.95 127.27

Dededo CT 1&2 45.0 479.0 292 64.22 60.96 104.44

Dededo Diesel Units 8.0 516.0 324 59.39 62.79 187.50

Marbo CT 16.0 508.0 317 60.47 62.40 137.50

Load Carrying Capability, Net (%)
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Table 6-2, System Reliability Impact of Multiple Combustion Turbine Plant Retirement

Sets of Unit Retired

Maximum Net 

Generaton Capacity 

Retired

System Capacity After 

Retirements

System Peak Load 

Carrying Capacity 

(Net) at One Day in 

4.5 Years LOLE

Reserve Margin For 

One Day in 4.5 Years 

LOLE

MW MW MW % System Incremental

None 0 524 339 54.26 64.69 N/A

Dededo and Marbo CT Plants 61 463 278 66.60 60.04 100.00

Dededo and Macheche CT Plants 67 457 273 67.30 59.74 98.51

Dededo and Yigo CT Plants 67 457 273 67.30 59.74 98.51

Dededo, Marbo and Macheche CT Plants 83 441 258 70.59 58.50 97.59

Dededo, Marbo and Yigo CT Plants 83 441 258 70.59 58.50 97.59

Marbo and Macheche CT Plants 38 486 297 63.48 61.11 110.53

Marbo and Yigo CT Plants 38 486 297 63.48 61.11 110.53

Macheche and Yigo CT Plants 44 480 293 63.95 61.04 104.55

All GPA CT Plants 105 419 240 74.84 57.28 94.29

Load Carrying Capability, Net (%)

Table 6-3, System Reliability Impact of Multiple Small Diesel Plant Retirement

Sets of Unit Retired

Maximum Net 

Generaton Capacity 

Retired

System Capacity After 

Retirements

System Peak Load 

Carrying Capacity 

(Net) at One Day in 

4.5 Years LOLE

Reserve Margin For 

One Day in 4.5 Years 

LOLE

MW MW MW % System Incremental

None 0 524 339 54.26 64.69 N/A

Dededo and Talofofo Diesel Plants 16 508 316 60.52 62.20 143.75

Dededo and Pulantat Diesel Plants 18 506 315 60.89 62.25 133.33

Dededo and Tenjo Diesel Plants 32 492 302 63.13 61.38 115.63

Dededo, Talofofo and Tenjo Diesel Plants 40 484 294 64.53 60.74 112.50

All GPA Diesel Plants 50 474 285 66.23 60.13 108.00

Load Carrying Capability, Net (%)
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Figure 6-1, Peak Load Carrying Capability (Gross) of GPA Generation System at PUC EAF Standards

0

1

2

3

4

5

6

7

8

9

10

11

268 300 325 350 375 400 425 450 475 500

Peak MW

1/LOLE Years Per Day

4.5 years per day

10 years per day

@268MW, 945 years per day

@300MW, 100 years per day

@325MW, 17 years per day

4 years per day

1.1 years per day

0.34 year per day

348MW

0

1

2

3

4

5

6

7

8

9

10

11

268 300 325 350 375 400 425 450 475 500

Peak MW

1/LOLE Years Per Day

4.5 years per day

10 years per day

@268MW, 945 years per day

@300MW, 100 years per day

@325MW, 17 years per day

4 years per day

1.1 years per day

0.34 year per day

348MW
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7 Supply Side Options

7.1 Introduction

The Guam Power Authority (GPA) engaged R. W. Beck to assist in the preparation of an 

integrated resource plan (IRP). In coordination with GPA, R. W. Beck developed unit 

characteristics, including performance, capital cost, and operation and maintenance (O&M) cost 

projections for both the existing power generating units as well as potential new generating 

resources. All costs are in 2012$. O&M costs are non-fuel production related costs and do not 

include owner costs, such as taxes and insurance. For the development of the unit 

characteristics, R. W. Beck visited the existing assets to assess the current state of operational 

readiness and estimate the needs of the units in the future to maintain operational reliability, 

efficiency, and environmental compliance. The existing assets, which include boiler and steam 

turbine generators (STGs), slow speed reciprocating (SSR) engines, combustion turbine 

generators (CTGs), and medium speed reciprocating (MSRs) engines, are listed in the table 

below.

The unit characteristics developed for the existing units included the following scenarios.

• Existing units as-is

• Existing units with capital expenditures in the future to improve efficiency and/or extend 

operating life, excluding the addition of air quality control systems (AQCS)

• Existing units with capital expenditures in the future to improve efficiency and/or extend 

operating life, including the addition of AQCS

• Certain existing units converted to fire natural gas, excluding capital expenditures, to 

coincide with potential natural gas availability by the end of 2017

• Certain existing units converted to fire natural gas with capital expenditures in the future 

to improve efficiency and/or extend operating life, excluding the addition of AQCS

• The addition of new power generating units.

The unit characteristics developed for the installation of new generating resources 

included the following.

• Repower Piti 7 to a combined-cycle plant firing on natural gas 

• New combined-cycle plant utilizing a GE LM6000 combustion turbine firing natural gas

• Small modular nuclear reactor (SMR)

• Bio-mass plant firing on wood pellets

• Stationary photovoltaic solar plant

• On-shore wind farm
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• Ocean thermal energy conversion plant

• Sea water air conditioning plant

• Geothermal plant

• Municipal solid waste plant.

Table 7-1

Summary of GPA Generation Resources

Unit Technology Fuel Net Capacity, MW (1) COD

Cabras 1 (2) Boiler/STG HS/LS RFO (3) 62.5 1974

Cabras 2 (2) Boiler/STG HS/LS RFO 59.2 1975

Cabras 3 (4) SSR HS/LS RFO 37.7 1996

Cabras 4 (4) SSR HS/LS RFO 37.7 1996

Dededo CT 1 CTG ULSD (5) 22.0 1992

Dededo CT 2 CTG ULSD 22.0 1994

Dededo Recip 1-4 MSR ULSD 2.45 each/9.8 total 1972

Macheche CT CTG ULSD 19.0 1993

Marbo CT CTG ULSD 16.0 1993

Manenggon Recip 1 & 2 MSR ULSD 5.2 each/10.4 total 1993

Piti 7 (6) CTG ULSD 39.3 1997

Piti 8 (7) SSR HS/LS RFO 43.2 1999

Piti 9 (7) SSR HS/LS RFO 43.2 1999

Talofofo Recip 1 & 2 MSR ULSD 4.3 each/8.6 total 1994

Tanguisson 1 (8) Boiler/STG HS RFO 24.8 1976

Tanguisson 2 (8) Boiler/STG HS RFO 24.8 1976

Tenjo Recip 1-6 MSR ULSD 4.3 each/25.9 total 1994

Yigo CT CTG ULSD 19.0 1993

_______________________

(1) Based on current expectation of maximum net capacity.

(2) Operated by GPA and TEMES pursuant to a performance management contract (PMC) expiring in September 2015.

(3) High sulfur (HS) or low sulfur (LS) No. 6 residual fuel oil (RFO), less than 2 percent or 1.2 percent sulfur, respectively.

(4) Operated by GPA and KEW pursuant to a PMC expiring in June 2015.

(5) Ultra low sulfur No. 2 diesel (ULSD) fuel oil, less than 0.0015 percent sulfur.

(6) Operated by TEMES pursuant to a build-own-operate-transfer (BOOT) Agreement expiring in December 2017.

(7) Operated by MEC pursuant to a BOOT Agreement expiring in January 2019.

(8) Operated by Pruvient pursuant to a BOOT Agreement expiring in August 2017.

The section below summarizes the unit characteristic assumptions utilized as inputs for the 

computer modeling of the IRP.
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7.2 Existing Units

7.2.1 Boiler/STG Units

Our projections of the performance of the boiler/STG units are based on performance test 

data and historical operating data, with adjustment for the various scenarios, as applicable. 

Similarly our capital expenditure and O&M cost projections are based on historical O&M data, 

including cost data, in addition to our experience with other units of similar vintage utilizing 

similar technology. We note TRC, GPA’s environmental consultant, reported that the 

boiler/STG units must comply with Boiler MACT and National Ambient Air Quality Standards 

(NAAQS) by no later than 2015 and 2017, respectively. Without obtaining an exemption or the 

addition of air quality control systems (AQCS) the units could be subject to shut down by the 

Environmental Protection Agency (EPA). Performance and cost information related to the 

AQCS was provided by TRC. An electrostatic precipitator (ESP) would need to be installed to 

meet Boiler MACT and a scrubber would need to be installed to meet NAAQS for each of the 

boiler/STG units. While TRC reported that a wet scrubber or a dry scrubber with an ESP/ 

baghouse could be installed to meet NAAQS, for the purposes of the IRP we have assumed that 

the potential AQCS addition would consist of a limestone forced oxidation wet flue gas 

desulfurization (wet FGD) unit, due to its lower capital costs and smaller footprint requirements. 

To that end, TRC projected that the water consumption, lime consumption, and waste disposal, 

and subsequently the O&M costs, would be slightly higher for the wet FGD versus the dry 

scrubber. We have also estimated the cost to convert the units to fire on natural gas, which TRC 

reported would eliminate the need to add AQCS equipment. The cost estimate for the natural 

gas conversion includes only the labor and materials associated with new equipment and 

modifications to existing equipment on-site to support firing on natural gas.

7.2.1.1 Cabras 1 and 2

The Cabras 1 and 2 units, each with a nominal net capacity rating of 60 MW are located 

near Apra Harbor and fire on either high sulfur (HS) or low sulfur (LS) residual fuel oil (RFO) 

depending on the wind direction. LS RFO is utilized during periods of time when the wind 

direction is toward the island to minimize the impact of emissions on Guam. Additionally waste 

oil from the island is blended into the HS RFO fuel supply to avoid treatment or off-island 

disposal. The units entered commercial operation over 35 years ago.

At the time of our site visit, both units were operational. Based on data provided for the 

units and our observations the performance of both units is suffering due to the cleanliness of the 

condensers and the performance of the air heaters. Capital expenditures going forward are 

needed to repair or replace the control systems, motor control centers (MCCs), fans and fan 

motors, air heaters, feedwater heaters, major motors and pumps, condensers, tanks, water 

treatment equipment, and the structure containing the units itself. GPA reported that some 

controls upgrades were in progress, including new burner management systems. While the 

suggested renewals and replacements are expected to result in only a minor improvement in 

performance of the units, the renewals and replacements are expected to improve the reliability 

and extend the life of the units. The “As-is” and “As-is with Capital Expenditures” scenarios 

have limited life expectancy (2017) due to the pending NAAAQS regulations, if AQCS are not 
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installed. Similarly, the “LNG” scenario also has a limited life expectancy without capital 

expenditures due to the need for renewals and replacements described above. The tables below 

present the unit characteristics for Cabras 1 and 2 for the scenarios previously described.

Table 7-2

Cabras 1 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS LNG LNG+Capex

Fuel Type HS/LS RFO HS/LS RFO HS/LS RFO LNG LNG

Net Capacity-Max, MW 62.5 64.0 63.0 61.5 63.0

Net Capacity-Min, MW 15.6 16.0 15.8 15.4 15.8

Heat Rate-100%, Btu/kWh 11,700 11,466 11,641 12,000 11,810

Heat Rate-75%, Btu/kWh 11,612 11,380 11,554 11,910 11,721

Heat Rate- 50%, Btu/kWh 11,911 11,672 11,851 12,216 12,023

Heat Rate-Min, Btu/kWh 14,226 14,138 14,353 14,796 14,562

Forced Outage, % 6.0 6.0 6.0 6.0 6.0

Scheduled Outage, % 6.0 6.0 6.0 6.0 6.0

Availability, % 88.0 88.0 88.0 88.0 88.0

VOM, $/MWh 5.00 5.00 7.19 4.75 4.75

FOM, $/kW-yr 56.00 56.00 56.00 53.20 53.20

MM, $/MWh (1) 2.12 2.12 2.12 2.12 2.12

Capex, million$/yr (2) N/A 3.5 3.5 N/A 3.5

AQCS, million$ (3) N/A N/A 80.0 N/A N/A

LNG Conversion, million$ (4) N/A N/A N/A 12.0 12.0

Retirement Date, yr 2017 2017 >25 yrs 2020 >25 yrs

_______________________

(1) The projected major maintenance cycle (MM) includes boiler outages every other year and STG outages every five years. 

(2) Levelized annual expenditures through 2019 with $2.0 million annually thereafter.

(3) One time expenditure with timing to comply with NAAQS by 2017.

(4) One time expenditure with timing consistent with the availability of LNG. Excludes pipeline installation cost.
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Table 7-3

Cabras 2 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS LNG LNG+Capex

Fuel Type HS/LS RFO HS/LS RFO HS/LS RFO LNG LNG

Net Capacity-Max, MW 59.2 60.7 59.8 58.2 59.7

Net Capacity-Min, MW 14.8 15.2 14.9 14.6 14.9

Heat Rate-100%, Btu/kWh 11,400 11,172 11,342 11,639 11,507

Heat Rate-75%, Btu/kWh 10,754 10,539 10,699 10,979 10,855

Heat Rate- 50%, Btu/kWh 11,223 10,999 11,166 11,459 11,329

Heat Rate-Min, Btu/kWh 14,421 14,133 14348 14,723 14,557

Forced Outage, % 6.0 6.0 6.0 6.0 6.0

Scheduled Outage, % 6.0 6.0 6.0 6.0 6.0

Availability, % 88.0 88.0 88.0 88.0 88.0

VOM, $/MWh 5.00 5.00 7.58 4.75 4.75

FOM, $/kW-yr 56.00 56.00 56.00 53.20 53.20

MM, $/MWh (1) 2.12 2.12 2.12 2.12 2.12

Capex, million$/yr (2) N/A 3.5 3.5 N/A 3.5

AQCS, million$ (3) N/A N/A 80.0 N/A N/A

LNG Conversion, million$ (4) N/A N/A N/A 12.0 12.0

Retirement Date, yr 2017 2017 >25 yrs 2020 >25 yrs

_______________________

(1) The projected major maintenance cycle includes boiler outages every other year and STG outages every five years. 

(2) Levelized annual expenditures through 2019 with $2.0 million annually thereafter.

(3) One time expenditure with timing to comply with NAAQS by 2017.

(4) One time expenditure with timing consistent with the availability of LNG. Excludes pipeline installation cost.

7.2.1.2 Tanguisson 1 and 2

The Tanguisson 1 and 2 units, each with a nominal net capacity rating of 26.5 MW are 

located north of Apra Harbor on the western coast and fire on HS RFO. The units entered 

commercial operation over 35 years ago.

At the time of our site visit, both units were operational. Based on data provided for the 

units and our observations, the performance of both units has degraded slightly relative to the 

nameplate rating due to normal wear and tear. Capital expenditures going forward are needed to

repair or replace the control systems, motor control centers (MCCs), fans and fan motors, 

ductwork, air heaters, feedwater heaters, major motors and pumps, sea water heat exchangers, 

and insulation. The control system is dated and procurement of replacement parts and service 

are likely to become more challenging in the future. While the suggested renewals and 

replacements are expected to result in only a minor improvement in performance of the units, the 

renewals and replacements are expected to improve the reliability and extend the life of the units. 

The “As-is” and “As-is with Capital Expenditures” scenarios have limited life expectancy 

(2017) due to the pending NAAAQS regulations, if AQCS are not installed. Similarly, the 

“LNG” scenario also has a limited life expectancy without capital expenditures due to the need 
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for renewals and replacements described above. The tables below present the unit characteristics 

for Tanguisson 1 and 2 for the scenarios previously described.

Table 7-4

Tanguisson 1 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS LNG LNG+Capex

Fuel Type HS RFO HS RFO HS RFO LNG LNG

Net Capacity-Max, MW 24.8 24.9 24.6 24.0 24.1

Net Capacity-Min, MW 6.2 6.2 6.1 6.0 6.0

Heat Rate-100%, Btu/kWh 13,400 13,350 13,550 13,802 13,751

Heat Rate-75%, Btu/kWh 13,200 13,151 13,348 13,698 13,648

Heat Rate- 50%, Btu/kWh 13,925 13,873 14,081 14,184 14,132

Heat Rate-Min, Btu/kWh 16,550 16,488 16,735 16,858 16,796

Forced Outage, % 4.0 4.0 4.0 4.0 4.0

Scheduled Outage, % 8.0 8.0 8.0 8.0 8.0

Availability, % 88.0 88.0 88.0 88.0 88.0

VOM, $/MWh 5.00 5.00 6.75 5.00 5.00

FOM, $/kW-yr 52.00 52.00 52.00 52.00 52.00

MM, $/MWh (1) 1.67 1.67 1.67 1.67 1.67

Capex, million$/yr (2) N/A 1.83 1.83 N/A 1.83

AQCS, million$ (3) N/A N/A 30.0 N/A N/A

LNG Conversion, million$ (4) N/A N/A N/A 6.6 6.6

Retirement Date, yr 2017 2017 >25 yrs 2020 >25 yrs

_______________________

(1) The projected major maintenance cycle includes boiler and STG outages every six years. 

(2) Levelized annual expenditures through 2019 with $1.0 million annually thereafter.

(3) One time expenditure with timing to comply with NAAQS by 2017.

(4) One time expenditure with timing consistent with the availability of LNG. Excludes pipeline installation cost.
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Table 7-5

Tanguisson 2 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS LNG LNG+Capex

Fuel Type HS RFO HS RFO HS RFO LNG LNG

Net Capacity-Max, MW 24.8 24.9 24.6 24.0 24.1

Net Capacity-Min, MW 6.2 6.2 6.1 6.0 6.0

Heat Rate-100%, Btu/kWh 13,400 13,350 13,550 13,802 13,751

Heat Rate-75%, Btu/kWh 13,200 13,151 13,348 13,698 13,648

Heat Rate- 50%, Btu/kWh 13,925 13,873 14,081 14,184 14,132

Heat Rate-Min, Btu/kWh 16,550 16,488 16,735 16,858 16,796

Forced Outage, % 4.0 4.0 4.0 4.0 4.0

Scheduled Outage, % 8.0 8.0 8.0 8.0 8.0

Availability, % 88.0 88.0 88.0 88.0 88.0

VOM, $/MWh 5.00 5.00 6.75 5.00 5.00

FOM, $/kW-yr 52.00 52.00 52.00 52.00 52.00

MM, $/MWh (1) 1.67 1.67 1.67 1.67 1.67

Capex, million$/yr (2) N/A 1.83 1.83 N/A 1.83

AQCS, million$ (3) N/A N/A 30.0 N/A N/A

LNG Conversion, million$ (4) N/A N/A N/A 6.6 6.6

Retirement Date, yr 2017 2017 >25 yrs 2020 >25 yrs

_______________________

(1) The projected major maintenance cycle includes boiler and STG outages every six years. 

(2) Levelized annual expenditures through 2019 with $1.0 million annually thereafter.

(3) One time expenditure with timing to comply with NAAQS by 2017.

(4) One time expenditure with timing consistent with the availability of LNG. Excludes pipeline installation cost.

7.2.2 Slow Speed Reciprocating Units

Our projections of the performance of the SSR units are based on performance test data 

and historical operating data, with adjustment for the various scenarios, as applicable. Similarly 

our capital expenditure and O&M cost projections are based on historical O&M data, including 

cost data, in addition to our experience with other units of similar vintage utilizing similar 

technology. TRC reported that AQCS need to be added to the SSR units to maintain 

environmental compliance with Reciprocating Internal Combustion Engines (RICE) Maximum 

Achievable Control Technology (MACT) by no later than 2014, if an exemption cannot be 

obtained. Without obtaining an exemption or the addition of AQCS the units could be subject to 

shut down by the EPA. Performance and cost information related to the AQCS was provided by 

TRC. If an exemption is not obtained the units will require either i) the installation of an 

oxidation catalyst and a switch to burning a residual fuel oil with a much lower sulfur content of 

500-600ppm or to entirely ULSD, which would have minimal capital cost, but would add 

significant incremental fuel cost relative to the “As-is” scenario, or ii) the installation of a dry 

scrubber, baghouse and oxidation catalyst. GPA reported difficulty in sourcing a supply of ULS 

RFO and TRC reported that it is not aware of a reciprocating engine currently installed including 

a dry scrubber and baghouse. Either case would result in an incremental fuels cost increase 

relative to the “As-is” scenario and, in the case of adding a dry scrubber and baghouse, the O&M 

costs would be higher as well. For the purposes of the IRP, the SSRs are modeled with dry 

scrubber installations to process stack exhaust for the use of oxidation catalysts to control carbon 
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monoxide. The installation would have to be completed by 2014 to support compliance with 

both RICE MACT by 2014 and NAAQS due by 2017. We have also estimated the cost to 

convert the units to fire on natural gas. The cost estimate for the natural gas conversion includes 

only the labor and materials associated with new equipment and modifications to existing 

equipment on-site to support firing on natural gas.

7.2.2.1 Cabras 3 and 4

The Cabras 3 and 4 units, each with a nominal net capacity rating of 37.7 MW are located 

near Apra Harbor and fire on either HS or LS RFO depending on the wind direction. LS RFO is 

utilized during periods of time when the wind direction is toward the island to minimize the 

impact of emissions on Guam. The units entered commercial operation over 15 years ago.

At the time of our site visit, Cabras 3 was in outage and Cabras 4 was operational. Based 

on data provided for the units and our observations the performance of both units has degraded 

slightly relative to the nameplate rating due to normal wear and tear. Capital expenditures going 

forward are needed to repair or replace the control system, cooling systems, sea water coolers, 

building and stack structural components, investigate and remedy potential foundation issues, 

and to add a turbocharger cleaning system. While the suggested renewals and replacements are 

expected to result in only a minor improvement in performance of the units, the renewals and 

replacements are expected to improve the reliability and extend the life of the units. The “As-is” 

and “As-is with Capital Expenditures” scenarios have limited life expectancy (2014) due to the 

pending RICE MACT regulations, if AQCS are not installed. Similarly, the “LNG” scenario 

also has a limited life expectancy without capital expenditures due to the need for renewals and 

replacements described above. The tables below present the unit characteristics for Cabras 3 and 

4 for the scenarios previously described.
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Table 7-6

Cabras 3 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS LNG LNG+Capex

Fuel Type HS/LS RFO HS/LS RFO RFO LNG LNG

Net Capacity-Max, MW 37.7 37.7 37.2 36.7 36.7

Net Capacity-Min, MW 19.0 19.0 19.0 19.0 19.0

Heat Rate-100%, Btu/kWh 9,130 9,130 9,250 9,380 9,380

Heat Rate-75%, Btu/kWh 9,221 9,221 9,343 9,474 9,474

Heat Rate- 50%, Btu/kWh 9,221 9,221 9,343 9,474 9,474

Heat Rate-Min, Btu/kWh 9,221 9,221 9,343 9,474 9,474

Forced Outage, % 2.5 2.5 2.5 2.5 2.5

Scheduled Outage, % 8.0 8.0 8.0 8.0 8.0

Availability, % 89.5 89.5 89.5 89.5 89.5

VOM, $/MWh 5.00 5.00 10.38 5.00 5.00

FOM, $/kW-yr 40.00 40.00 40.00 40.00 40.00

MM, $/MWh (1) 3.44 3.44 3.44 3.44 3.44

Capex, million$/yr (2) N/A 1.14 1.14 N/A 1.14

AQCS, million$ (3) N/A N/A 3.1/60 N/A 3.1

LNG Conversion, million$ (4) N/A N/A N/A 13.5 13.5

Retirement Date, yr 2014 2014 >25 yrs 2020 >25 yrs

_______________________

(1) The projected major maintenance cycle includes a major overhaul every other year. 

(2) Levelized annual expenditures through 2019 with $1.0 million annually thereafter.

(3) One time expenditure with timing to comply with RICE MACT by 2014.

(4) One time expenditure with timing consistent with the availability of LNG. Excludes pipeline installation cost.
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Table 7-7

Cabras 4 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS LNG LNG+Capex

Fuel Type HS/LS RFO HS/LS RFO RFO LNG LNG

Net Capacity-Max, MW 37.7 37.7 37.2 36.7 36.7

Net Capacity-Min, MW 19.0 19.0 19.0 19.0 19.0

Heat Rate-100%, Btu/kWh 9,130 9,130 9,250 9,380 9,380

Heat Rate-75%, Btu/kWh 9,221 9,221 9,343 9,474 9,474

Heat Rate- 50%, Btu/kWh 9,221 9,221 9,343 9,474 9,474

Heat Rate-Min, Btu/kWh 9,221 9,221 9,343 9,474 9,474

Forced Outage, % 2.5 2.5 2.5 2.5 2.5

Scheduled Outage, % 8.0 8.0 8.0 8.0 8.0

Availability, % 89.5 89.5 89.5 89.5 89.5

VOM, $/MWh 5.00 5.00 10.38 5.00 5.00

FOM, $/kW-yr 40.00 40.00 40.00 40.00 40.00

MM, $/MWh (1) 3.44 3.44 3.44 3.44 3.44

Capex, million$/yr (2) N/A 1.14 1.14 N/A 1.14

AQCS, million$ (3) N/A N/A 3.1/60 N/A 3.1

LNG Conversion, million$ (4) N/A N/A N/A 13.5 13.5

Retirement Date, yr 2014 2014 >25 yrs 2020 >25 yrs

_______________________

(1) The projected major maintenance cycle includes a major overhaul every other year. 

(2) Levelized annual expenditures through 2019 with $1.0 million annually thereafter.

(3) One time expenditure with timing to comply with RICE MACT by 2014.

(4) One time expenditure with timing consistent with the availability of LNG. Excludes pipeline installation cost.

7.2.2.2 Piti 8 and 9

The Piti 8 and 9 units, each with a nominal net capacity rating of 43.2 MW are located 

near Apra Harbor and fire on either HS or LS No. 6 RFO depending on the wind direction. LS 

RFO is utilized during periods of time when the wind direction is toward the island to minimize 

the impact of emissions on Guam. The units entered commercial operation over 10 years ago.

At the time of our site visit, both units were operational. However, Piti 8 was utilizing 

the Piti 7 generator step-up (GSU) transformer due to damage to the Piti 8 GSU. Based on data 

provided for the units and our observations, the performance of both units has degraded slightly 

relative to the nameplate rating due to normal wear and tear. Capital expenditures going forward 

are needed to repair or replace the GSU. While the suggested renewals and replacements are 

expected to result in only a minor improvement in performance of the units, the renewals and 

replacements are expected to improve the reliability and extend the life of the units. The “As-is” 

and “As-is with Capital Expenditures” scenarios have limited life expectancy (2014) due to the 

pending RICE MACT regulations, if AQCS are not installed. Similarly, the “LNG” scenario for 

Piti 8 and 9 also has a limited life expectancy due to the need for renewals and replacements 

described above. The tables below present the unit characteristics for Piti 8 and 9 for the 

scenarios previously described.
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Table 7-8

Piti 8 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS LNG LNG+Capex

Fuel Type HS/LS RFO HS/LS RFO RFO LNG LNG

Net Capacity-Max, MW 43.2 43.2 42.6 42.2 42.2

Net Capacity-Min, MW 21.0 21.0 21.0 21.0 21.0

Heat Rate-100%, Btu/kWh 8,690 8,690 8,804 8,896 8,896

Heat Rate-75%, Btu/kWh 8,777 8,777 8,892 8,985 8,896

Heat Rate- 50%, Btu/kWh 8,777 8,777 8,892 8,985 8,985

Heat Rate-Min, Btu/kWh 8,777 8,777 8,892 8,985 8,985

Forced Outage, % 2.0 2.0 2.0 2.0 2.0

Scheduled Outage, % 5.0 5.0 5.0 5.0 5.0

Availability, % 93.0 93.0 93.0 93.0 93.0

VOM, $/MWh 5.00 5.00 9.78 5.00 5.00

FOM, $/kW-yr 100.00 100.00 100.00 100.00 100.00

MM, $/MWh (1) 2.64 2.64 2.64 2.64 2.64

Capex, million$/yr (2) N/A 0.2 0.2 0.2 0.2

AQCS, million$ (3) N/A N/A 3.4/60 N/A 3.4

LNG Conversion, million$ (4) N/A N/A N/A 13.5 13.5

Retirement Date, yr 2014 2014 >25 yrs 2020 >25 yrs

_______________________

(1) The projected major maintenance cycle includes a major overhaul every other year. 

(2) Levelized annual expenditures.

(3) One time expenditure with timing to comply with RICE MACT by 2014.

(4) One time expenditure with timing consistent with the availability of LNG. Excludes pipeline installation cost.
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Table 7-9

Piti 9 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS LNG LNG+Capex

Fuel Type HS/LS RFO HS/LS RFO RFO LNG LNG

Net Capacity-Max, MW 43.2 43.2 42.6 42.2 42.2

Net Capacity-Min, MW 21.0 21.0 21.0 21.0 21.0

Heat Rate-100%, Btu/kWh 8,690 8,690 8,804 8,896 8,896

Heat Rate-75%, Btu/kWh 8,777 8,777 8,892 8,985 8,896

Heat Rate- 50%, Btu/kWh 8,777 8,777 8,892 8,985 8,985

Heat Rate-Min, Btu/kWh 8,777 8,777 8,892 8,985 8,985

Forced Outage, % 2.0 2.0 2.0 2.0 2.0

Scheduled Outage, % 5.0 5.0 5.0 5.0 5.0

Availability, % 93.0 93.0 93.0 93.0 93.0

VOM, $/MWh 5.00 5.00 9.78 5.00 5.00

FOM, $/kW-yr 100.00 100.00 100.00 100.00 100.00

MM, $/MWh (1) 2.64 2.64 2.64 2.64 2.64

Capex, million$/yr (2) N/A 0.2 0.2 0.2 0.2

AQCS, million$ (3) N/A N/A 3.4/60 N/A 3.4

LNG Conversion, million$ (4) N/A N/A N/A 13.5 13.5

Retirement Date, yr 2014 2014 >25 yrs 2020 >25 yrs

_______________________

(1) The projected major maintenance cycle includes a major overhaul every other year. 

(2) Levelized annual expenditures.

(3) One time expenditure with timing to comply with RICE MACT by 2014.

(4) One time expenditure with timing consistent with the availability of LNG. Excludes pipeline installation cost.

7.2.3 Medium Speed Reciprocating Units

Our projections of the performance of the MSR units are based on performance test data 

and historical operating data, with adjustment for the various scenarios, as applicable. Similarly 

our capital expenditure and O&M cost projections are based on historical O&M data, including 

cost data, in addition to our experience with other units of similar vintage utilizing similar 

technology. TRC reported that AQCS may need to be added to the MSR units to maintain 

environmental compliance with RICE MACT by no later than 2014, if an exemption cannot be 

obtained. Without obtaining an exemption or the addition of AQCS the units could be subject to 

shut down by the EPA. Performance and cost information related to the AQCS was provided by 

TRC. If an exemption is not obtained, then the units will require the installation of an oxidation 

catalyst. We have also estimated the cost to convert the Tenjo units to fire on natural gas. The 

cost estimate for the natural gas conversion includes only the labor and materials associated with 

new equipment and modifications to existing equipment on-site to support firing on natural gas.

7.2.3.1 Dededo 1 -4

The four Dededo MSR units, with a total nominal net capacity rating of 9.8 MW are 

located near Dededo and fire ULSD. The units entered commercial operation over 35 years ago.
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At the time of our site visit, Dededo 1 was in outage for turbocharger repairs and the 

remaining units were operational. Based on data provided for the units and our observations the 

performance of units has degraded slightly due to normal wear and tear. No significant capital 

expenditures are foreseen at this time, with the exception of the installation of the AQCS. 

However, certain levels of capital expenditures have been forecasted to maintain the 

performance and reliability, as well as to extend the life of the units. The “As-is” and “As-is 

with Capital Expenditures” scenarios have limited life expectancy (2014) due to the pending 

RICE MACT regulations, if AQCS are not installed. The tables below present the unit 

characteristics for the Dededo MSR units for the scenarios previously described.

Table 7-10

Dededo 1-4 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS

Fuel Type ULSD ULSD ULSD

Net Capacity-Max, MW (1) 9.8 9.8 9.8

Net Capacity-Min, MW 1.2 1.2 1.2

Heat Rate-100%, Btu/kWh 10,900 10,900 10,900

Heat Rate-75%, Btu/kWh 11,067 11,067 11,067

Heat Rate- 50%, Btu/kWh 11,718 11,718 11,718

Heat Rate-Min, Btu/kWh 11,718 11,718 11,718

Forced Outage, % 4.0 4.0 4.0

Scheduled Outage, % 4.0 4.0 4.0

Availability, % 92.0 92.0 92.0

VOM, $/MWh 8.00 8.00 8.00

FOM, $/kW-yr 55.00 55.00 55.00

MM, $/MWh (2) 7.50 7.50 7.50

Capex, million$/yr (3) N/A 0.4 0.4

AQCS, million$ (4) N/A N/A 0.4

Retirement Date, yr 2014 2014 >25 yrs

_______________________

(1) Total capacity of all four units.

(2) The projected major maintenance cycle includes a major overhaul every 20,000 operating hours.

(3) Levelized annual expenditures.

(4) One time expenditure with timing to comply with RICE MACT by 2014. 

7.2.3.2 Manenggon 1 and 2

The Manenggon 1 and 2 units, with a nominal net capacity rating of 10.4 MW are located 

on the southeast side of the island and are leased by GPA from a resort. The units fire on ULSD. 

The units entered commercial operation over 15 years ago.

At the time of our site visit, both units were operational, but derated due to the need for 

radiator repairs. Based on data provided for the units and our observations, the performance of 

both units has degraded slightly due to normal wear and tear. No significant capital expenditures 

are foreseen at this time, with the exception of the installation of the AQCS. However, certain 

levels of capital expenditures have been forecasted to maintain the performance and reliability, 

as well as to extend the life of the units. The “As-is” and “As-is with Capital Expenditures” 
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scenarios have limited life expectancy (2014) due to the pending RICE MACT regulations, if 

AQCS are not installed. The tables below present the unit characteristics for the Manenggon 

MSR units for the scenarios previously described.

Table 7-11

Manenggon 1 and 2 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS

Fuel Type ULSD ULSD ULSD

Net Capacity-Max, MW (1) 10.4 10.4 10.4

Net Capacity-Min, MW 2.6 2.6 2.6

Heat Rate-100%, Btu/kWh 9,290 9,290 9,290

Heat Rate-75%, Btu/kWh 9,430 9,430 9,430

Heat Rate- 50%, Btu/kWh 9,990 9,990 9,990

Heat Rate-Min, Btu/kWh 9,990 9,990 9,990

Forced Outage, % 4.0 4.0 4.0

Scheduled Outage, % 4.0 4.0 4.0

Availability, % 92.0 92.0 92.0

VOM, $/MWh 8.00 8.00 8.00

FOM, $/kW-yr 55.00 55.00 55.00

MM, $/MWh (2) 3.61 3.61 3.61

Capex, million$/yr (3) N/A 0.4 0.4

AQCS, million$ (4) N/A N/A 0.35

Retirement Date, yr 2014 2014 >25 yrs

_______________________

(1) Total capacity of both units.

(2) The projected major maintenance cycle includes a major overhaul every 20,000 operating hours.

(3) Levelized annual expenditures.

(4) One time expenditure with timing to comply with RICE MACT by 2014.

7.2.3.3 Talafofo 1 and 2

The Talafofo 1 and 2 units, with a nominal net capacity rating of 8.6 MW are located on 

the southeast side of the island and are leased by GPA from a resort. The units fire on ULSD. 

The units entered commercial operation over 15 years ago.

At the time of our site visit, both units were operational. Based on data provided for the 

units and our observations the performance of both units has degraded slightly due to normal 

wear and tear. No significant capital expenditures are foreseen at this time, with the exception of 

the installation of the AQCS. However, certain levels of capital expenditures have been 

forecasted to maintain the performance and reliability, as well as to extend the life of the units. 

The “As-is” and “As-is with Capital Expenditures” scenarios have limited life expectancy (2014) 

due to the pending RICE MACT regulations, if AQCS are not installed. The tables below 

present the unit characteristics for the Talafofo MSR units for the scenarios previously described.
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Table 7-12

Talafofo 1 and 2 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS

Fuel Type ULSD ULSD ULSD

Net Capacity-Max, MW (1) 8.6 8.6 8.6

Net Capacity-Min, MW 2.1 2.1 2.1

Heat Rate-100%, Btu/kWh 9,770 9,770 9,770

Heat Rate-75%, Btu/kWh 9,920 9,920 9,920

Heat Rate- 50%, Btu/kWh 10,500 10,500 10,500

Heat Rate-Min, Btu/kWh 10,500 10,500 10,500

Forced Outage, % 4.0 4.0 4.0

Scheduled Outage, % 4.0 4.0 4.0

Availability, % 92.0 92.0 92.0

VOM, $/MWh 8.00 8.00 8.00

FOM, $/kW-yr 55.00 55.00 55.00

MM, $/MWh (2) 7.10 7.10 7.10

Capex, million$/yr (3) N/A 0.4 0.4

AQCS, million$ (4) N/A N/A 0.35

Retirement Date, yr 2014 2014 >25 yrs

_______________________

(1) Total capacity of both units.

(2) The projected major maintenance cycle includes a major overhaul every 20,000 operating hours.

(3) Levelized annual expenditures.

(4) One time expenditure with timing to comply with RICE MACT by 2014.

7.2.3.4 Tenjo 1-6

The Tenjo MSR units, with a total nominal net capacity rating of 25.9 MW are located on 

the southwest side of the island and fire on ULSD. The units entered commercial operation over 

15 years ago.

At the time of our site visit, all six units were operational, but derated due to generator 

and cooler limitations. Based on data provided for the units and our observations, the 

performance of the units have degraded slightly due to normal wear and tear and been further 

impacted by the generator and cooler limitations. Capital expenditures going forward are needed 

to repair or replace the stacks and address the generator and cooler limitations. While the 

suggested renewals and replacements are expected to result in only a minor improvement in 

performance of the units, the renewals and replacements are expected to improve the reliability 

and extend the life of the units. The “As-is” and “As-is with Capital Expenditures” scenarios 

have limited life expectancy (2014) due to the pending RICE MACT regulations, if AQCS are 

not installed. The tables below present the unit characteristics for the Tenjo MSR units for the 

scenarios previously described.
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Table 7-13

Tenjo 1-6 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS LNG LNG+Capex

Fuel Type ULSD ULSD ULSD LNG LNG

Net Capacity-Max, MW (1) 25.9 26.4 26.4 18.6 18.6

Net Capacity-Min, MW 2.2 2.2 2.2 1.6 1.6

Heat Rate-100%, Btu/kWh 9,600 9,600 9,600 10,080 10,080

Heat Rate-75%, Btu/kWh 9,740 9,740 9,740 10,227 10,227

Heat Rate- 50%, Btu/kWh 10,320 10,320 10,320 10,836 10,836

Heat Rate-Min, Btu/kWh 10,320 10,320 10,320 10,836 10,836

Forced Outage, % 2.5 2.5 2.5 2.5 2.5

Scheduled Outage, % 4.0 4.0 4.0 4.0 4.0

Availability, % 93.5 93.5 93.5 93.5 93.5

VOM, $/MWh 8.00 8.00 8.00 7.60 7.60

FOM, $/kW-yr 55.00 55.00 55.00 52.25 52.25

MM, $/MWh (2) 7.10 7.10 7.10 7.10 7.10

Capex, million$/yr (3) N/A 0.6 0.6 N/A 0.6

AQCS, million$ (4) N/A N/A 1.05 N/A N/A

LNG Conversion, million$ (5) N/A N/A N/A 6.0 6.0

Retirement Date, yr 2014 2014 >25 yrs 2020 >25 yrs

_______________________

(1) Total capacity of all six units.

(2) The projected major maintenance cycle includes a major overhaul every 20,000 operating hours.

(3) Levelized annual expenditures.

(4) One time expenditure with timing to comply with RICE MACT by 2014.

(5) One time expenditure with timing consistent with the availability of LNG. Excludes pipeline installation cost.

7.2.4 Combustion Turbine Generators

Our projections of the performance of the CTG units are based on performance test data 

and historical operating data, with adjustment for the various scenarios, as applicable. Similarly 

our capital expenditure and O&M cost projections are based on historical O&M data, including 

cost data, in addition to our experience with other units of similar vintage utilizing similar 

technology. TRC reported that AQCS may need to be added to the CTG units in the event that 

capital expenditures trigger CTG MACT. This would require the addition of an oxidation 

catalyst and potentially a selective catalytic reduction (SCR) system. Without obtaining an 

exemption or the addition of AQCS the units could be subject to shut down by the EPA. 

Performance and cost information related to the AQCS was provided by TRC. We have also 

estimated the cost to convert the CTG units to fire on natural gas, which would eliminate the 

need to add AQCS equipment if the total emissions are reduced. The cost estimate for the 

natural gas conversion includes only the labor and materials associated with new equipment and 

modifications existing equipment on-site to support firing on natural gas.
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7.2.4.1 Dededo 1and 2

The two Dededo CTG units, each with nominal net capacity rating of 22.0 MW are 

located in the north central part of the island near Dededo and fire on ULSD. The units entered 

commercial operation over 15 years ago.

At the time of our site visit, neither unit was operational due to generator failures. Based 

on data provided for the units and our observations the performance of units can only be 

estimated as the units have not operated for several years. With regard to capital improvements, 

in addition to the need to repair the generators, other equipment was in need of repair or 

replacement including the control system, stacks, the fin fan coolers, the black start diesel 

generator, and the water injection skids. The control system is dated and procurement of 

replacement parts and service are likely to become more challenging in the future. While the 

suggested renewals and replacements are expected to result in only a minor improvement in 

performance of the units, the renewals and replacements are expected to improve the reliability 

and extend the life of the units. The “As-is” and “LNG” scenarios have limited life expectancy 

(2012) due to the need to replace the generators and make other repairs. The tables below 

present the unit characteristics for the Dededo MSR units for the scenarios previously described.

Table 7-14

Dededo 1 and 2 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS LNG LNG+Capex

Fuel Type ULSD ULSD ULSD LNG LNG

Net Capacity-Max, MW (1) 22.0 22.0 22.0 22.0 22.0

Net Capacity-Min, MW 11.0 11.0 11.0 11.0 11.0

Heat Rate-100%, Btu/kWh 13,280 13,280 13,280 13,280 13,280

Heat Rate-75%, Btu/kWh 14,340 14,340 14,340 14,340 14,340

Heat Rate- 50%, Btu/kWh 15,670 15,670 15,670 15,670 15,670

Heat Rate-Min, Btu/kWh 15,670 15,670 15,670 15,670 15,670

Forced Outage, % 3.0 3.0 3.0 3.0 3.0

Scheduled Outage, % 6.0 6.0 6.0 6.0 6.0

Availability, % 91.0 91.0 91.0 91.0 91.0

VOM, $/MWh 6.00 6.00 6.00 6.00 6.00

FOM, $/kW-yr 12.50 12.50 12.50 12.50 12.50

MM, $/MWh (2) 7.05 7.05 7.05 7.05 7.05

Capex, million$/yr (3) N/A 10.0 10.0 N/A 10.0

AQCS, million$ (4) N/A N/A 1.8 N/A N/A

LNG Conversion, million$ (5) N/A N/A N/A 2.0 2.0

Retirement Date, yr 2012 >25 yrs >25 yrs 2012 >25 yrs

_______________________

(1) Capacity of each unit.

(2) The projected major maintenance cycle is based on a 50% capacity factor or 200 starts per year.

(3) Needed to ready units for operation followed by $0.4 million annually thereafter.

(4) One time expenditure with timing to comply with CTG MACT.

(5) One time expenditure with timing consistent with the availability of LNG. Excludes pipeline installation cost.
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7.2.4.2 Macheche

The Macheche CTG unit, with nominal net capacity rating of 19.0 MW is located in the 

north central part of the island near Macheche and fires on ULSD. The unit entered commercial 

operation over 15 years ago.

At the time of our site visit, the unit was operational. Based on data provided for the 

units and our observations, the performance of the unit is limited on blade path spread due to a 

faulty variable stator vane (VSV) adjustment mechanism. With regard to capital improvements, 

in addition to the need to repair the VSV adjustment mechanism, other equipment was in need of 

repair or replacement including the control system, water treatment skid, water injection skid, 

and the black start diesel generator. The control system is dated and procurement of replacement 

parts and service are likely to become more challenging in the future. While the suggested 

renewals and replacements are expected to result in only a minor improvement in performance of 

the units, the renewals and replacements are expected to improve the reliability and extend the 

life of the units. The “As-is” and “LNG” scenarios have limited life expectancy due to the need 

to the needed renewals and replacements discussed above. Table 7-14 presents the unit 

characteristics for the Macheche CTG for the scenarios previously described.

7.2.4.3 Piti 7

The Piti 7 CTG unit, with nominal net capacity rating of 39.3 MW is located near Apra 

Harbor and fires on ULSD. The unit has been operational for over 15 years.

At the time of our site visit, the unit was operational, but unavailable to interconnect with 

the grid because the GSU was being utilized by Piti 8. The performance of the unit has degraded 

slightly relative to the nameplate rating due to normal wear and tear. This conclusion is bsed on 

data provided for the units and our observations. It excludes the fact that the GSU was being 

utilized by Piti 8. Regarding capital improvements, the control system needs to be upgraded as it 

is dated and procurement of replacement parts and service are likely to become more challenging 

in the future. While the suggested renewals and replacements are expected to result in only a 

minor improvement in performance of the units, the renewals and replacements are expected to 

improve the reliability and extend the life of the units. Table 7-16 presents the unit 

characteristics for the Piti 7 CTG for the scenarios previously described.
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Table 7-15

Macheche Unit Characteristics

Scenario As-is +Capex +Capex+AQCS LNG LNG+Capex

Fuel Type ULSD ULSD ULSD LNG LNG

Net Capacity-Max, MW 19.0 19.0 19.0 19.0 19.0

Net Capacity-Min, MW 10.0 10.0 10.0 10.0 10.0

Heat Rate-100%, Btu/kWh 10,500 10,500 10,500 10,500 10,500

Heat Rate-75%, Btu/kWh 11,340 11,340 11,340 11,340 11,340

Heat Rate- 50%, Btu/kWh 12,390 12,390 12,390 12,390 12,390

Heat Rate-Min, Btu/kWh 12,390 12,390 12,390 12,390 12,390

Forced Outage, % 3.0 3.0 3.0 3.0 3.0

Scheduled Outage, % 5.0 5.0 5.0 5.0 5.0

Availability, % 92.0 92.0 92.0 92.0 92.0

VOM, $/MWh 6.00 6.00 6.00 6.00 6.00

FOM, $/kW-yr 13.00 13.00 13.00 13.00 13.00

MM, $/MWh (1) 7.75 7.75 7.75 7.75 7.75

Capex, million$/yr (2) N/A 0.82 0.82 N/A 0.82

AQCS, million$ (3) N/A N/A 0.9 N/A N/A

LNG Conversion, million$ (4) N/A N/A N/A 1.8 1.8

Retirement Date, yr 2020 >25 yrs >25 yrs 2020 >25 yrs

_______________________

(1) The projected major maintenance cycle is based on a 50% capacity factor or 200 starts per year.

(2) Levelized annual expenditures through 2019 with $0.2 million annually thereafter.

(3) One time expenditure with timing to comply with CTG MACT.

(4) One time expenditure with timing consistent with the availability of LNG. Excludes pipeline installation cost.
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Table 7-16

Piti 7 Unit Characteristics

Scenario As-is +Capex +Capex+AQCS LNG LNG+Capex

Fuel Type ULSD ULSD ULSD LNG LNG

Net Capacity-Max, MW 39.3 39.3 39.3 39.3 39.3

Net Capacity-Min, MW 20.0 20.0 20.0 20.0 20.0

Heat Rate-100%, Btu/kWh 11,800 11,800 11,800 11,800 11,800

Heat Rate-75%, Btu/kWh 12,750 12,750 12,750 12,750 12,750

Heat Rate- 50%, Btu/kWh 13,900 13,900 13,900 13,900 13,900

Heat Rate-Min, Btu/kWh 13,900 13,900 13,900 13,900 13,900

Forced Outage, % 3.0 3.0 3.0 3.0 3.0

Scheduled Outage, % 6.0 6.0 6.0 6.0 6.0

Availability, % 91.0 91.0 91.0 91.0 91.0

VOM, $/MWh 6.00 6.00 6.00 6.00 6.00

FOM, $/kW-yr 98.00 98.00 98.00 98.00 98.00

MM, $/MWh (1) 3.88 3.88 3.88 3.88 3.88

Capex, million$/yr (2) N/A 0.4 0.4 N/A 0.4

AQCS, million$ (3) N/A N/A 1.8 N/A N/A

LNG Conversion, million$ (4) N/A N/A N/A 2.0 2.0

Retirement Date, yr >25 yrs >25 yrs >25 yrs >25 yrs >25 yrs

_______________________

(1) The projected major maintenance cycle is based on a 50% capacity factor or 200 starts per year.

(2) Levelized annual expenditures through 2019 with $0.2 million annually thereafter.

(3) One time expenditure with timing to comply with CTG MACT.

(4) One time expenditure with timing consistent with the availability of LNG. Excludes pipeline installation cost.

7.2.4.4 Yigo

The Yigo CTG unit, with nominal net capacity rating of 19.0 MW is located in the northeastern 

part of the island near Yigo and fires on ULSD. The units entered commercial operation over 15 

years ago.

At the time of our site visit, the unit was operational. Based on data provided for the 

units and our observations, the performance of the unit is limited on blade path spread due to a 

faulty variable stator vane (VSV) adjustment mechanism similar to Macheche. With regard to 

capital improvements, in addition to the need to repair the VSV adjustment mechanism other 

equipment was in need of repair or replacement including the control system, water treatment 

skid, water injection skid, and the black start diesel generator. The control system is dated and 

procurement of replacement parts and service are likely to become more challenging in the 

future. Further, the CTG package itself and the building housing the water treatment equipment 

need replacement due to severe corrosion. While the suggested renewals and replacements are 

expected to result in only a minor improvement in performance of the units, the renewals and 

replacements are expected to improve the reliability and extend the life of the units. The “As-is” 

and “LNG” scenarios have limited life expectancy due to the need to the needed renewals and 
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replacements discussed above. The tables below presenst the unit characteristics for the Yigo 

CTG for the scenarios previously described.

Table 7-17

Yigo Unit Characteristics

Scenario As-is +Capex +Capex+AQCS LNG LNG+Capex

Fuel Type ULSD ULSD ULSD LNG LNG

Net Capacity-Max, MW 19.0 19.0 19.0 19.0 19.0

Net Capacity-Min, MW 10.0 10.0 10.0 10.0 10.0

Heat Rate-100%, Btu/kWh 10,500 10,500 10,500 10,500 10,500

Heat Rate-75%, Btu/kWh 11,340 11,340 11,340 11,340 11,340

Heat Rate- 50%, Btu/kWh 12,390 12,390 12,390 12,390 12,390

Heat Rate-Min, Btu/kWh 12,390 12,390 12,390 12,390 12,390

Forced Outage, % 3.0 3.0 3.0 3.0 3.0

Scheduled Outage, % 5.0 5.0 5.0 5.0 5.0

Availability, % 92.0 92.0 92.0 92.0 92.0

VOM, $/MWh 6.00 6.00 6.00 6.00 6.00

FOM, $/kW-yr 13.00 13.00 13.00 13.00 13.00

MM, $/MWh (1) 7.75 7.75 7.75 7.75 7.75

Capex, million$/yr (2) N/A 12.0 12.0 N/A 12.0

AQCS, million$ (3) N/A N/A 0.9 N/A N/A

LNG Conversion, million$ (4) N/A N/A N/A 1.8 1.8

Retirement Date, yr 2014 >25 yrs >25 yrs 2014 >25 yrs

_______________________

(1) The projected major maintenance cycle is based on a 50% capacity factor or 200 starts per year.

(2) Needed as soon as possible followed by $0.2 million annually thereafter.

(3) One time expenditure with timing to comply with CTG MACT.

(4) One time expenditure with timing consistent with the availability of LNG. Excludes pipeline installation cost.
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7.3 New Units

The table below presents the unit characteristics developed for the potential new generating resources to support modeling 

against the various scenarios of the existing units in the IRP.

Table 7-18

New Resource Unit Characteristics

Scenario Repower New CC SMR Biomass Solar Wind OTEC SWAC Geothermal MSW

Fuel Type Natural 

Gas

Natural 

Gas Uranium Wood Sunlight Wind Seawater Seawater N/A MSW

Capital Cost, $000 81,000 128,400 858,000 78,600 45,000 93,000 150,000 144,600 52,200 84,600

Capital Cost, $/kW NA 2,140 9,533 7,860 4,500 4,650 15,000 12,050 5,220 8,460

Permitting Duration, Months 16 16 60 24 12 12 36 36 36 24

Start of Eng to COD, Months 24 28 48 30 24 24 24 18 24 30

Total Duration, Months 34 38 96 48 30 30 48 42 48 48

COD (1) Apr-17 Aug-17 Jun-22 Jun-18 Dec-16 Dec-16 Jun-18 Dec-17 Jun-18 Jun-18

Net Capacity-Max, MW 60 60 90 10 10 20 10 12 10 10

Net Capacity-Min, MW 40 40 30 5 N/A N/A N/A N/A N/A 5

Heat Rate-100%, Btu/kWh 8,400 8,350 N/A 17,500 N/A N/A N/A N/A N/A N/A

Heat Rate-75%, Btu/kWh 8,650 8,600 N/A 18,000 N/A N/A N/A N/A N/A N/A

Heat Rate- 50%, Btu/kWh 8,950 8,900 N/A 19,000 N/A N/A N/A N/A N/A N/A

Heat Rate-Min, Btu/kWh 8,950 8,900 N/A 20,000 N/A N/A N/A N/A N/A N/A

Forced Outage, % 2.0 2.0 2.0 6.0 1.0 2.0 6.0 1.0 4.0 6.0

Scheduled Outage, % 6.0 6.0 8.0 8.0 2.0 2.0 2.0 2.0 6.0 8.0

Availability, % 92.0 92.0 90.0 86.0 25.0 25.0 92.0 97.0 90.0 86.0

VOM, $/MWh 5.00 5.00 1.50 12.00 N/A N/A 11.00 2.00 8.00 12.00

FOM, $/kW-yr 42.00 42.00 200 400.00 40.00 50.00 290.00 80.00 100.00 400.00

_______________________

(1) Assumes Project is initiated in June 1, 2014
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7.3.1.1 Repower Piti 7

Unit characteristics were developed for the potential repowering of the Piti 7 GE Frame 

6B CTG into a combined-cycle unit by converting the CTG to fire on natural gas, adding a heat 

recovery steam generator (HRSG), a STG, a condenser, heat rejection systems and associated 

pumps, piping, electrical and control equipment and interconnection to the grid. It would likely 

require the relocation of the existing control room and use of property to the north and east of the 

existing Piti 7 plant site. Additionally, it would likely require the use of the existing sea water 

intake structure for the abandoned Piti 4 and 5 units, or municipal water supply to provide makeup to a cooling tower.

7.3.1.2 New Combined-Cycle

Unit characteristics were developed for the potential installation of a new combined-cycle 

unit based on the use of a GE LM6000 CTG firing on natural gas. The plant would include an 

HRSG, a STG, a condenser, heat rejection systems and associated pumps, piping, electrical and 

control equipment, an interconnection to the grid. It would likely require the relocation of the 

existing control room. The unit could likely be installed in the location around the abandoned 

Piti 4 and 5 units. However, demolition and asbestos remediation costs to remove the existing 

structures, if necessary, have not been included in the cost estimate. Additionally, it would likely 

require the use of the existing sea water intake structure for the abandoned Piti 4 and 5 units, or 

municipal water supply to provide make-up to a cooling tower. Another alternative siting

strategy GPA should consider is siting of a new combined-cycle combustion turbine in northern 

Guam to reduce system technical losses.

7.3.1.3 Small Modular Reactor

Unit characteristics were developed for the potential installation of a small modular 

nuclear reactor (SMR) based on information provided by others. SMR technology is in the 

development stages and assumptions relating to project development timelines and costs are 

likely to change in the future. The cost assumptions were for the infrastructure to support 6 x 45 

MW of reactors with only two 45 MW reactors being installed. This would allow for on-site 

storage of spent fuel within the containment structure through at least three refueling cycles for 

each unit. Refueling was assumed to occur every four years with the average annual fuel cost of 

$30 million, including disposal after 10 years. 

7.3.1.4 Biomass

Unit characteristics were developed for the potential installation of a biomass project. 

This project was assumed to utilize wood pellets sourced off-island as the fuel source for a 

bubbling fluidized bed or stoker type boiler in combination with a STG. Coordination of fuel 

supply and the disposal of ash would need to be investigated further prior to moving forward 

with this project.