2014 Avoided Energy and Capacity Cost Study

FINAL Report
2014 Avoided Energy and
Capacity Cost Study
Virgin Islands Water and Power Authority
April 30, 2014

This report has been prepared for the use of the client for the specific purposes identified in the
report. The conclusions, observations and recommendations contained herein attributed to
Leidos constitute the opinions of Leidos. To the extent that statements, information and
opinions provided by the client or others have been used in the preparation of this report, Leidos
has relied upon the same to be accurate, and for which no assurances are intended and no
representations or warranties are made. Leidos makes no certification and gives no
assurances except as explicitly set forth in this report.
© 2014 Leidos Engineering, LLC
All rights reserved.

2014 Avoided Energy and Capacity Cost Study
Virgin Islands Water and Power Authority
Table of Contents
Section 1 STUDY OVERVIEW ............................................................................... 1-1
Study Design ..................................................................................................... 1-1
Electric System Load ......................................................................................... 1-1
St. Thomas Existing Generation Facilities ........................................................ 1-2
St. Croix Existing Generation Facilities ............................................................ 1-3
Planning Reserve Requirements ........................................................................ 1-3
Existing Plant Configuration ............................................................................. 1-4
Planned Generating Additions ........................................................................... 1-4
Fuel Cost Projections ......................................................................................... 1-5
Avoided Capacity and Energy Cost Methodology ............................................ 1-5
Section 2 RESULTS .................................................................................................. 2-1
Avoided Energy Cost Results ............................................................................ 2-1
Section 3 PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS ................. 3-1
List of Tables
Table 2-1 5 MW 24x7 Avoided Costs ........................................................................ 2-1
Table 2-2 5 MW Solar Avoided Energy Costs ........................................................... 2-1
Table 3-1 St. Thomas Existing Resources .................................................................. 3-2
Table 3-2 St. Croix Existing Resources ...................................................................... 3-2
File: 00514100/3153305030

Section 1
STUDY OVERVIEW
The Virgin Islands Renewable and Alternative Energy Act of 2009 (“the Act”)
requires that the Virgin Islands Water and Power Authority (the “Authority”) shall
annually provide the Virgin Islands Public Service Commission (“PSC) with data
sufficient to enable cogenerators and small power producers to estimate the
Authority’s avoided capacity and energy costs. Leidos Engineering, LLC (“Leidos”)
has prepared an Avoided Capacity and Energy Study (“AC Study”) to evaluate the
projected avoided capacity and energy costs associated with new power supply options
on the islands of St. Thomas and St. Croix, for the period 2015-2034.
The remainder of this Section describes the Authority’s electrical system load and
generating facilities, and the methodology used to forecast the Authority’s avoided
capacity and energy costs.
Study Design
This AC Study includes only the existing and planned generating facilities described
below. The Authority is currently planning a long-term Integrated Resource Plan
(“IRP”), expected to be completed by October 2014. The IRP will include a thorough
examination of the Authority’s electrical system, including a detailed energy and
demand forecast, an assessment of the Authority’s current generating facilities and
their potential retirements, and a rigorous evaluation of potential future resource
additions to the Authority’s system.
The IRP will identify a reliable and sustainable resource plan for the Authority,
including both thermal and renewable resource additions, as well as potential energy
efficiency and Demand Side Management programs. A key component of the IRP
will be detailed avoided capacity and energy cost projections, which will be based on
the size, technology, and timing of the resource additions identified.
Leidos and the Authority have prepared this AC Study to satisfy the requirements of
the Act and to provide current estimates of the Authority’s avoided capacity and
energy costs. The Authority believes that the subsequent IRP in late 2014 will provide
a more rigorously developed and accurate projection of the Authority’s avoided costs.
Electric System Load
The Authority is planning to develop a detailed energy and demand forecast as a
component of the IRP study described above. Using the methodology described
below to develop this AC Study, an energy and demand forecast was not developed
for the purposes of this AC Study. Based on the recent loss of loads on the
Authority’s system and the existing and planned generating facilities described below,
and the small amount of expected load growth for the study period of 2015-2034, no
additional capacity is projected to be required to meet reserve requirements on
File: 00514100/3153305030

Section 1
St. Croix, and a small amount of additional capacity may potentially be required on
St. Thomas during the final 2-3 years of the study period. The Authority believes that
the IRP study and its associated demand and energy forecast will provide a more
accurate projection of the Authority’s expected future loads.
St. Thomas Existing Generation Facilities
The Authority has major electric generation facilities on the islands of St. Thomas and
St. Croix, and has limited backup generation facilities on the island of St. John.
Except for emergency situations, the electric power and energy requirements of the
island of St. John are generated on the island of St. Thomas and transmitted to the
island of St. John by means of two underwater cables. Because of the extreme water
depth between them, the islands of St. Thomas and St. Croix are not interconnected
electrically.
The Authority's generating facilities on the island of St. Thomas are located at the
Randolph E. Harley Generating Station (“Harley Station”) at Krum Bay, on the
southwestern end of the island. All electric generation for the islands of St. Thomas
and St. John, and the two smaller islands, Hassel Island and Water Island, are located
at this site, except for an emergency diesel-generating unit located on the island of
St. John. In addition to generation facilities, the Krum Bay site includes water
production, fuel oil unloading and storage, transportation, and warehouse facilities.
Harley Station currently includes Unit No. 25, a temporarily leased unit, expected to
be removed from the system on November 30, 2014. Additionally, the Authority is
expecting to purchase a 22-megawatt (“MW”) LM2500 combustion turbine unit
(“Unit 27”) to replace Unit 22, a similarly sized unit, which was irreparably damaged
in 2012 and has since been decommissioned.
Harley Station also includes a waste heat recovery steam generator (“HRSG”), also
referred to as a “waste heat boiler.” The HRSG was constructed to utilize the exhaust
gases from either or both combustion turbine Units No. 15 and No. 18 for the
production of steam for electric generation, using the steam turbine Units No. 11 and
No. 13. The HRSG is projected to be upgraded by March 2015 to increase the amount
of high-pressure steam available for combined-cycle operations.
St. Thomas also includes a substantial number of rooftop solar photovoltaic (“PV”)
installations ranging from 5 to 20 kilowatts (“kW”) each. These are connected to the
Authority’s system under its Net Energy Metering (“NEM”) tariff. The NEM program
currently is capped at 10 MW on St. Thomas, and the program is expected to reach the
10 MW limit by mid-2014.
In 2011, the Authority began converting its thermal desalination facilities for
production of potable water to facilities that use a reverse osmosis process. Currently,
both of the thermal desalination facilities on both St. Thomas and St. Croix are in a
reserve shutdown condition, and no longer using steam from the HRSGs on either
island. Additional information regarding the generating facilities on both islands is
contained in Section 3 of this AC Study.
1-2 Leidos Engineering, LLC FINAL 2014 VIWAPA Avoided Cost Study_04-30-14.docx

STUDY OVERVIEW
St. Croix Existing Generation Facilities
All of the Authority’s existing generation facilities on the island of St. Croix
(114 MW) are located at the Estate Richmond site on the north shore of the island in
Christiansted. In addition to generation facilities, the Estate Richmond site includes
water production, fuel oil unloading and storage, and warehouse facilities.
There are two HRSGs at the Estate Richmond site on St. Croix, converting
combustion turbine Units No. 16 and No. 20 from simple-cycle operation to
combined-cycle operation. The dual HRSGs reduce fuel costs through improved
efficiencies and improved generating reliability by increasing the amount of
generating reserves on the island of St. Croix.
St. Croix also includes a number of rooftop solar PV installations. These are
connected to the Authority’s system under its NEM tariff. The NEM program
currently is capped at 5 MW on St. Croix, and the program is expected to reach the
5 MW limit by mid-2014.
The Authority’s four steam-generating units range in age from 38 to 43 years. The
Authority’s 10 combustion turbine units range in age from 7 to 40 years. Although
some of the generating units have exceeded their normal life expectancy, the Authority
has refurbished or reconditioned many of its units to extend their useful lives. At this
time, the Authority has not established expected retirement dates for its existing steam
and combustion turbine generating facilities. It is assumed that the Authority will
continue to perform normal maintenance and repairs of its existing facilities in
accordance with normal prudent utility practice.
Planning Reserve Requirements
The Authority operates two isolated electric generation and distribution systems, and
the Authority's demand and energy requirements do not deviate significantly by
season. Like other isolated electric systems, the Authority is required to maintain a
higher level of generating reserves than interconnected electric systems to ensure
reliability while allowing for scheduled maintenance and forced outages. To reduce
the potential for service interruptions and to improve the quality of service, the
Authority’s established planning criteria for generating reserves calls for the Authority
to have sufficient generating capacity on each island to meet its respective electric
load requirements with its two largest units out of service. The use of these planning
criteria was originally approved by the PSC in 1991 and has been affirmed in
subsequent orders.
On the island of St. Thomas, the two largest units are Unit No. 13, a steam turbine
generator with a reported net continuous capacity rating of approximately 36.9 MW,
and Unit No. 23, a combustion turbine generator with a reported net continuous rating
of approximately 39 MW. Excluding the combined capacity of Units No. 13 and
No. 23, the balance of the generating units on St. Thomas has a combined nameplate
File: 00514100/3153305030 Leidos Engineering, LLC 1-3

Section 1
rating of approximately 90 MW 1 , which assumes that Unit No. 22 is replaced by a new
LM2500 similar to Unit No. 25 (GE lease unit) 2 . Given the uncertainties contained in
the demand forecast for St. Thomas, it is difficult to forecast exactly when additional
generating capacity will be required on St. Thomas; however, the Authority believes
that no additional generating capacity will be required for reliability requirements in
the near term.
The two largest units on the island of St. Croix are Unit No. 19 and Unit No. 20, two
combustion turbine generators, each with a reported net continuous capacity rating of
approximately 22 MW. Excluding the combined capacity of Units No. 19 and No. 20,
the balance of the generating units on St. Croix have a combined rating of
approximately 73 MW. Given the uncertainties contained in the demand forecast for
St. Croix, it is difficult to forecast exactly when additional generating capacity will be
required on St. Thomas; however, the Authority believes that no additional generating
capacity will be required for reliability requirements in the near term. The Authority
believes that the IRP study and its associated demand and energy forecast will provide
a more accurate projection of the Authority’s future capacity needs.
Existing Plant Configuration
The generating systems on the islands of St. Thomas and St. Croix involve multi-unit
configurations operating in combined-cycle operation. The Authority has identified to
Leidos that the preferred configuration on the island of St. Thomas assumes that
combustion turbine Unit No. 15 or Unit No. 18 are supplying waste heat to the HRSG.
Unit No. 11 is driven by steam from the HRSG and Unit No. 13 will be driven by
steam from Unit No. 21, once it is upgraded. Unit No. 23 and Unit No. 27 are
operated if needed to produce electricity. The configuration described above
represents the most efficient mode for the system to meet load requirements.
The assumed configuration on the island of St. Croix assumes that combustion turbine
Unit No. 16 and Unit No. 20 supply waste heat to the HRSG Unit No. 24. Unit No. 10
and Unit No. 11 are supplied by steam from the HRSGs Unit No. 21 and Unit No. 24.
As a backup, Unit No. 17 supplies waste heat to the HRSG Unit No. 21 to generate
steam to drive the steam turbines. Unit No. 19 is operated if needed to produce
electricity in simple-cycle mode.
Planned Generating Additions
The Authority has entered into agreements to purchase power from four additional
generating facilities. Two facilities on St. Thomas include the Main Street Power
5 MW-PV facility with an expected Commercial Operation Date (“COD”) of
January 2015, and a 1.5 MW-landfill gas facility, also with an expected COD of
January 2015. Additional generating facilities on St. Croix include the 7 MW-biomass
1 Both St. Thomas and St. Croix generating capacity totals include the planned generating facilities
described herein.
2 See Table 3-1 for a list of St. Thomas Existing Resources.
1-4 Leidos Engineering, LLC FINAL 2014 VIWAPA Avoided Cost Study_04-30-14.docx

STUDY OVERVIEW
facility developed by Tibbar, with an expected COD of January 2016, and the Toshiba
5 MW-PV facility, expected online by late 2014.
In addition to the above-described planned generating additions, the Authority is
evaluating other additions, including potential thermal generators on St. Thomas and
St. Croix. These potential additions are not yet finalized and are not considered in this
AC Study; however, the Authority expects to evaluate these potential additions in the
upcoming IRP.
Fuel Cost Projections
The Authority is in the process of converting both the Harley Station and Estate
Richmond Station generating facilities to burn Liquid Propane Gas (“LPG”) in
addition to diesel oil, their current fuel. This conversion is expected to be completed
by December 2014, with the expectation that by 2015, both facilities will primarily
burn LPG. While it is possible that there will remain some generation produced by
burning diesel oil at both facilities, it is expected that this will be a very small amount
of fuel use compared to the LPG use. For the purposes of this AC Study, the
Authority assumes that all generation at both facilities will be produced using LPG.
The Authority has entered into a five-year agreement to purchase LPG based on price
projections the Mt. Belvieu LPG pricing hub. This agreement calls for the Authority’s
delivered LPG price to consist of the Mt. Belvieu price, plus an additional U.S. Virgin
Island (“USVI”) delivery premium. While the LPG delivery contract is for a five-year
period with an optional two-year renewal period, the Authority assumes that the
delivery premium represents a reasonable delivery premium, which would be paid to
an alternate supplier and, thus, assumes this delivery premium will be included in the
total LPG price for the entire study period.
Leidos and the Authority developed a Mt. Belvieu pricing hub forecast using a
combination of the United States (“U.S.”) Energy Information Administration’s
(“EIA”) 2014 Annual Energy Outlook (“AEO”) and historical pricing data. Because
the AEO does not explicitly forecast a Mt. Belvieu LPG price, the forecast calculated
such a price by estimating the amount of delivery premium incorporated into the
AEO’s West South Central historical regional LPG forecasts for commercial users,
and subtracting that premium from the 2014 West South Central regional forecast.
Finally, the USVI delivery premium was added to the forecast to project a delivered
LPG price to the Authority. The annual LPG forecast is presented in Section 3 below.
Avoided Capacity and Energy Cost Methodology
This AC Study explicitly includes only the above described existing and planned
generating facilities. As stated previously, no additional capacity requirements are
projected for St. Croix through the remainder of the study period, and a small amount
of additional capacity may be required on St. Thomas near the end of the study period.
For the purposes of this AC Study, the Authority projects there is no avoided cost
associated with capacity.
File: 00514100/3153305030 Leidos Engineering, LLC 1-5

Section 1
With respect to avoided energy costs, due to the lack of a current long-term resource
plan with identified resource additions, Leidos and the Authority have developed a
methodology to project avoided energy costs. This methodology assumes the
Authority’s system average heat rates in January 2015 will be consistent with those
assumed in the most recent Levelized Energy Adjustment Clause and Rate Financing
Mechanism filings with the PSC. These system average heat rates were calculated
using the projected St. Croix system average heat rates for the months of April-
September 2014, and the projected St. Thomas system average heat rates for the
months of April-September 2015 for St. Thomas. The 2015 projected system average
heat rates were used for St. Thomas to account for the expected impact of the HRSG
upgrade described above.
For the purposes of this AC Study, the system average heat rates were assumed to be
held constant from 2015-2019. Beginning in 2020, a 10 percent reduction to the
system average heat rates was applied to represent potential improvements or more
efficient resource additions to the Authority’s generating system. Beginning in 2025,
a further five percent reduction to the system average heat rates was assumed, and in
2030, another five percent reduction was assumed. The Authority recognizes that the
system average heat rates assumed for the purposes of this AC Study may be
substantially different from those identified in the expected IRP and its associated
avoided cost projections.
The AC Study first projects the avoided energy costs associated with increasing the
Authority’s generating capacity by 5 MW in all hours. The avoided energy cost is
calculated by multiplying the total generation associated with the increased capacity
by the assumed system average heat rates and the projected LPG price. The energy
cost based on this calculation represents the average avoided energy cost for the
generation associated with a non-dispatchable, baseloaded 5 MW resource that the
Authority may purchase.
This AC Study also projects the avoided energy costs associated with the Authority
purchasing the output from a potential 5 MW solar facility. The potential solar facility
is assumed to have an annual capacity factor of 24 percent, with the majority of its
generation during on peak hours. The system on-peak heat rates are assumed to be
3 percent lower than the system average heat rates, due to the more efficient loading
levels of the combined cycle operations during hours of higher loads. The projected
on-peak heat rates avoided by the potential solar facility were calculated by comparing
the system average heat rates to the system on-peak heat rates for the June 2012 to
June 2013 time period. The avoided energy cost of the potential solar facility is
calculated by multiplying the total generation associated with the potential facility by
the assumed system on-peak heat rates and the projected LPG price. The energy cost
based on this calculation represents the avoided energy cost for the non-dispatchable
intermittent energy generated by a 5 MW solar resource that the Authority may
purchase.
Avoided energy costs for the 5 MW 24x7 resource and the 5 MW solar resource were
calculated for each year over the period 2015 – 2034.
1-6 Leidos Engineering, LLC FINAL 2014 VIWAPA Avoided Cost Study_04-30-14.docx

Section 2
RESULTS
Avoided Energy Cost Results
Based on the above methodology and principal considerations and assumptions
contained herein, we have prepared the Avoided Energy Costs Tables 2-1 and 2-2:
Table 2-1
5 MW 24x7 Avoided Costs
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
System Average Heat Rate Btu/kWh (1) 12,326 12,326 12,326 12,326 12,326 11,737 11,737 11,737 11,737 11,737
Total Generation MWh (2) 43,800 43,800 43,800 43,920 43,800 43,800 43,800 43,920 43,800 43,800
Total Avoided Cost $000 8,199 8,895 9,360 9,779 10,033 9,773 10,086 10,397 10,618 10,906
Total Avoided Cost $/MWh 187 203 214 223 229 223 230 237 242 249
LPG Cost $/MMBtu (3) 15.19 16.48 17.34 18.06 18.59 19.01 19.62 20.17 20.65 21.21
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
System Average Heat Rate Btu/kWh 11,150 11,150 11,150 11,150 11,150 10,593 10,593 10,593 10,593 10,593
Total Generation MWh 43,800 43,920 43,800 43,800 43,800 43,920 43,800 43,800 43,800 43,920
Total Avoided Cost $000 10,672 10,991 11,261 11,539 11,848 11,593 11,890 12,248 12,645 13,203
Total Avoided Cost $/MWh 244 250 257 263 271 264 271 280 289 301
LPG Cost $/MMBtu 21.85 22.44 23.06 23.63 24.26 24.92 25.63 26.40 27.26 28.38
(1) British thermal unit (“Btu”) per kilowatt-hour (“kWh”).
(2) Megawatt (1,000 kilowatt)-hours (“MWh”).
(3) Million (1,000,000) British thermal units (“MMBtu”).
Table 2-2
5 MW Solar Avoided Energy Costs
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
Solar Avoided Heat Rate Btu/kWh 11,956 11,956 11,956 11,956 11,956 11,385 11,385 11,385 11,385 11,385
Total Generation MWh 10,512 10,512 10,512 10,541 10,512 10,512 10,512 10,541 10,512 10,512
Total Avoided Cost $000 1,909 2,071 2,179 2,277 2,336 2,275 2,348 2,420 2,472 2,539
Total Avoided Cost $/MWh 182 197 207 216 222 216 223 230 235 242
LPG Cost $/MMBtu 15.19 16.48 17.34 18.06 18.59 19.01 19.62 20.17 20.65 21.21
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
Solar Avoided Heat Rate Btu/kWh 10,816 10,816 10,816 10,816 10,816 10,275 10,275 10,275 10,275 10,275
Total Generation MWh 10,512 10,541 10,512 10,512 10,512 10,541 10,512 10,512 10,512 10,541
Total Avoided Cost $000 2,484 2,559 2,621 2,686 2,758 2,699 2,768 2,851 2,944 3,074
Total Avoided Cost $/MWh 236 243 249 256 262 256 263 271 280 292
LPG Cost $/MMBtu 21.85 22.44 23.06 23.63 24.26 24.92 25.63 26.40 27.26 28.38
File: 00514100/3153305030

Section 3
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
1. No assumption has been made to reflect any changes in existing federal or
Territorial laws and/or regulations to reflect, among other things, more
stringent environmental requirements increased competition for electric service
and customers, and changes in existing tax laws and the imposition of new tax
laws.
2. The oil price forecast used in the AC Study was developed using the 2015
futures price for the Mt. Belvieu LPG pricing hub, to which the delivery
premium adjustment of $0.33 per gallon was added. The 2015 futures are then
blended to the developed 2016-2034 Mt. Belvieu LPG pricing hub forecast
based on the 2014 EIA Annual Energy Outlook, which has also been adjusted
for the delivery premium as a flat value in every year, i.e., not inflated.
3. The technologies, fuel type, rated capacity, availability, heat rate data,
condition, and in service date associated with the Authority’s existing
generating resources are based on information provided by the Authority.
Modeled heat rates for the Authority’s generating units were benchmarked
against historical production data. Tables 3-1 and 3-2 present the primary
modeling assumptions for the Authority’s existing generation resources.
4. The Authority’s planning criteria for generating reserves, assuming the
existing isolated electric systems, is the requirement to have sufficient
generating capacity on each island to meet its respective load requirement with
its two largest units out of service.
5. It is assumed that after January 1, 2014, steam will no longer be supplied to the
desalination plants on both islands.
6. The assumed generating configurations on the islands of St. Thomas and
St. Croix assume that the Authority will continue to meet recognized reliability
constraints that include the requirement that each plant be capable of handling
steam and electrical demand over a full range of demands with the largest unit
down for maintenance concurrent with the forced outage of the next largest
unit.
7. The projects evaluated herein are assumed to be designed, constructed and
operated in compliance with applicable existing environmental air quality
rules. To the extent emissions exceed the allowable Prevention of Significant
Deterioration (“PSD”) increment at a given site, offsetting nitrogen oxide
(“NO X ”) or sulfur dioxide (“SO 2 ”) emission reductions will be obtained in
sufficient amounts to classify the new generating addition as a minor source
pursuant to existing environmental law. No cap-and-trade program is assumed
for NO X and SO 2 since the U.S. Virgin Islands are not subject to the Clean Air
Interstate Rule, which establishes such programs.
File: 00514100/3153305030

Section 3
Unit Number Unit Type Fuel
Table 3-1
St. Thomas Existing Resources
Max Capacity
(MW)
Full Load Heat Rate
(Btu/kWh)
U7 IC #2 Oil 2.5 15,000
U11 ST Steam 23.5 NA
U13 ST Steam 36.9 NA
U15 CT LPG 20 15,000
U18 CT LPG 22 13,500
U21 HRSG Waste Heat NA NA
U23 CT LPG 39 13,500
U27 (1) CT LPG 22 9,750
Distributed Rooftop PV Solar 5 NA
Main St. Power Central PV Solar 5 NA
Landfill Gas IC NG 2 NA
(1) Proposed LM2500 replacement unit for Unit No. 22.
Unit Number Unit Type Fuel
Table 3-2
St. Croix Existing Resources
Max Capacity
(MW)
Full Load Heat Rate
(Btu/kWh)
U10 ST Steam 10 12,000
U11 ST Steam 20 12,000
U16 CT LPG 21 14,000
U17 CT LPG 22 14,000
U19 CT LPG 22 17,500
U20 CT LPG 22 14,000
U21 HRSG Waste Heat NA NA
U24 HRSG Waste Heat NA NA
Tibbar ST Bio Fuel 7 NA
Distributed Rooftop PV Solar 5 NA
Toshiba Central PV Solar 4 NA
3-2 Leidos Engineering, LLC FINAL 2014 VIWAPA Avoided Cost Study_04-30-14.docx