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NREL/TP-6A00-65544 December 2015

Jamaica National Net-Billing Pilot Program Evaluation

December 2015

Elizabeth Doris, Sherry Stout, Kimberly Peterson

National Renewable Energy Laboratory

Greening the Grid provides technical assistance to energy system planners, regulators, and grid 

operators to overcome challenges associated with integrating variable renewable energy into the grid.
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GREENING THE GRID

NOTICE

This manuscript has been authored by employees of the Alliance for Sustainable Energy, LLC (“Alliance”) 

under Contract No. DE-AC36-08GO28308 with the U.S. Department of Energy (“DOE”).

This report was prepared as an account of work sponsored by an agency of the United States 

government. Neither the United States government nor any agency thereof, nor any of their employees, 

makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, 

completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents 

that its use would not infringe privately owned rights. Reference herein to any specific commercial 

product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily 

constitute or imply its endorsement, recommendation, or favoring by the United States government or any 

agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect 

those of the United States government or any agency thereof.
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GREENING THE GRID

ACKNOWLEDGMENTS

This work was made possible through and in support of the goals of the U.S. Agency for 

International Development. The authors recognize the interest and support of Jeff 

Haeni, Jennifer Leisch, and Suzanne Ebert for project guidance and in-country support. 

We wish to thank representatives from the Office of Utilities Regulation; Jamaica Public 

Service Limited; solar installers; Ministry of Science, Technology, Energy and Mining; 

Jamaica Solar Energy Association; National Energy Council; commercial utility 

customers; Bureau of Standards of Jamaica; and Government Electrical Inspectorate 

for their time, effort, and interest in providing input through in-person interviews. We are 

appreciative of comments offered on early drafts from the Meister Consultants Group, in 

particular Wilson Rickerson and Christina Becker-Birk. Finally, we wish to thank our 

National Renewable Energy Laboratory colleagues for their reviews of the draft report: 

Andrea Watson, Jenny Heeter, Michael Elchinger, and Michael Coddington. Any 

remaining errors are the responsibility of the authors.
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GREENING THE GRID

LIST OF ACRONYMS

BSJ Bureau of Standards of Jamaica

DC direct current

DG distributed generation 

GEI Government Electrical Inspectorate 

Hz hertz

IEC International Electrotechnical Commission

IEEE Institute of Electrical and Electronics Engineers

IPP Independent Power Producer 

JPS Jamaica Public Service Company Limited 

JSEA Jamaica Solar Energy Association

kW kilowatt

kWh kilowatt-hour

MSTEM Ministry of Science, Technology, Energy and 

Mining

MW megawatt

NREL National Renewable Energy Laboratory

OUR Office of Utilities Regulation

PV photovoltaic 

QSTS quasi-static time series

RE renewable energy

SOC standard offer contract

USAID United States Agency for International 

Development

UL Underwriters Laboratories
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GREENING THE GRID

EXECUTIVE SUMMARY

In January 2015, the Office of Utilities Regulation in Jamaica requested that the United 

States Agency for International Development, supported by the National Renewable 

Energy Laboratory (NREL), assess the effectiveness of the Jamaica Public Service 

Company Limited’s Net-Billing Pilot Program. NREL collected and analyzed data from a 

wide range of stakeholders, conducted in-country research, and compared program 

elements to common interconnection practices to form programmatic recommendations 

for the Jamaica context. This work was presented in June 2015. Clarifying comments 

were incorporated into this final draft, and further comments are summarized or, if 

submitted in writing, reprinted in Appendix C of this report. 

NREL finds that the net-billing pilot program has successfully contributed to the support 

of the emerging solar market in Jamaica with the interconnection of 80 systems under 

the program for a total of 1.38 megawatts (MW) at the time of original analysis.1 To 

further improve the success of the program, NREL suggests:2

1. Separating interconnection and net billing, realigning various agency roles and 

responsibilities, shortening the timeline for interconnection and permitting, and 

adopting an expanded approved inverters list

2. Changing the renewable energy size cap for individual systems to further support 

the programmatic goal of electricity for self-use.

3. Changing the deposit and fee structure for the net billing program to include cost 

recovery for the investment of investing stakeholders

4. Studying and determining programmatic next steps in advance of when the 2% (12 

MW) net- billing program cap is reached, which includes: 

o Establishing clear goals for both net billing and DG in the context of 

Jamaica’s larger renewable energy goals. 

o Creating, through amnesty or registration, a full understanding of the 

current DG

o on the electric grid, for the purpose of longer-term planning

If the Government of Jamaica prioritizes the benefits reaped by increased DG by 

streamlining programmatic timing and increasing programmatic transparency, it is likely 

that demand for the net-billing program will increase. To support safe and reliable 

integration of DG, NREL suggests the development of an integrated resource plan that 

provides scenario analysis.

 1 As of May 26, 2015, 336 applications had been received and 120 systems had been interconnected for a total of 1.4 

MW. Because of the time frame in which it was completed, the analysis here-in summarizes data through Jan. 21, 

2015.

2 Full recommendations are summarized in Table 2of this report .
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GREENING THE GRID

TABLE OF CONTENTS

1.1 Purpose and Objectives..................................................................................................1

1.2 Scope and Methodology .................................................................................................1

2.1 In-Person Interview Summary and Results.....................................................................3

2.1.1 Customer Comments ....................................................................................................... 4

2.1.2 Net-Billing Pilot Program Comments from All Stakeholders ............................................ 5

2.1.3 Technical Comments........................................................................................................ 6

2.1.4 Regulatory Environment Comments ................................................................................ 6

2.1.5 Education and Training Comments.................................................................................. 6

2.1.6 Non-categorized Comments............................................................................................. 7

3.1 Practice 1: Increase Transparency by Improving Process...........................................10

3.1.1 Separate Interconnection and Net-Billing Process......................................................... 10

3.1.2 Realign Agency Roles .................................................................................................... 12

3.1.3 Shorten Timeline ............................................................................................................ 12

3.1.4 Adopt an Expanded Approved Inverters List.................................................................. 15

3.2 Practice 2: Change Renewable Energy Size Cap for Individual Systems ....................16

3.3 Practice 3: Change Deposit and Fee Structure ............................................................16

3.4 Practice 4: Designing the Next Phase of Distributed Generation Policy.......................18

4.1 Steady-State Analysis...................................................................................................20

4.2 Dynamic Grid Simulation ..............................................................................................20

4.3 Transient Studies..........................................................................................................20

4.4 Fault or Short-Circuit Studies........................................................................................20

4.5 Quasi-Static Time Series Analysis................................................................................21

4.6 Study Recommendations..............................................................................................21

References................................................................................................................................................. 23

Appendix A. Best Practice Resources for Stakeholders (Annotated Bibliography).......................... 25

Appendix B. Summary of Stakeholder Comments on Draft Versions of Report................................ 27

Appendix C. Specific Submitted Written Comments from Stakeholders............................................ 29
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LIST OF FIGURES

Figure 1: Recommended interconnection process for DG systems .............................. 11

Figure 2: Suggested net-billing flow for a new DG system............................................ 15

LIST OF TABLES

Table 1. Stakeholder Comments on Net Billing and Interconnection .............................. 4

Table 2. Summary of Net-Billing Programmatic Best Practices....................................... 8

Table 3. Customer Paid Fees in Jamaican Net Billing .................................................. 17
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Net Billing and Net Metering

At its most basic, net metering 

allows electric customers who 

generate their own electricity to 

supply excess electricity back to the 

grid at a prescribed compensation 

rate. This compensation can range 

from a percentage of the retail rate 

or avoided cost up to full retail value 

for each kilowatt-hour. In the United 

States, compensation mechanisms 

vary across states and even across 

utilities within states. Lawmakers 

and utility regulators typically set the 

parameters for net metering and 

customer compensation. 

The Jamaican Net-Billing Pilot 

Program allows self-generating 

customers to sell limited amounts of 

electricity back to the utility at the 

avoided generation cost plus a 15% 

premium. This defines the net billing 

program as a type of net billing 

program. As such, most international 

net metering best practices apply to 

the Jamaican context. 

1 Introduction 

1.1 Purpose and Objectives

In January 2015, the Office of Utilities Regulation (OUR) in Jamaica requested that the 

United States Agency for International Development (USAID), supported by the National 

Renewable Energy Laboratory (NREL), assess the effectiveness of the Jamaica Public 

Service Company Limited (JPS) Net-Billing Pilot Program. NREL collected and 

analyzed data from a wide range of stakeholders, 

conducted in-country research, and compared 

program elements to common interconnection 

practices to form programmatic recommendations 

for the Jamaica context. This evaluation is limited to 

the net-billing 

1.2 Scope and Methodology 

NREL completed a desktop analysis of the program 

with data provided by OUR, JPS customers, and 

JPS. The information provided was expanded and 

confirmed with a site-visit and interviews with a wide 

variety of stakeholders. These stakeholders included 

the OUR, customers, JPS, Government Electrical 

Inspectorate (GEI); Ministry of Science, Technology, 

Energy and Mining (MSTEM); Bureau of Standards 

of Jamaica (BSJ);Jamaica Solar Energy Association 

(JSEA); and the National Energy Council Renewable 

Energy Sub-Committee. The findings indicate that 

the program participation is commensurate with 

other programs of similar structure and duration, 

with 326 applications filed and 80 systems 

interconnected during the pilot period (as of Jan. 21, 

2015), for a total programmatic capacity of 1.38 

megawatts (MW) (approximately 0.15% of total 

generation capacity). The initial pilot period was to 

run from May 2012 through May 2014; however, 

applications were accepted through May 1, 2015.3

 

Despite different perspectives on the program, 

broad stakeholder comments followed common themes: 

• Complexity, length of time to interconnect, and opaque nature of the 

interconnection process

 3 As of May 26, 2015, 336 applications had been received and 120 systems had been interconnected for a total of 1.4 

MW. Because of the time frame in which it was completed, the analysis here-in summarizes data through Jan. 21, 

2015. 
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GREENING THE GRID

• Lack of clear interconnection, equipment, inspection and installer standards and 

codes

• Insufficient GEI staff to handle the volume of system inspections

• Lack of clarity about what happens at the end of the 5-year net-billing period

• Concerns about the renewable energy system size caps of 10 kilowatt (kW) 

residential and 100 kW commercial

• Cost and benefit disproportionalities between stakeholder groups

• Equity concerns related to the net-billing rate.

This report summarizes programmatic suggestions that—based on international, U.S., 

and Caribbean experiences—are designed to further facilitate renewable energy on the 

Jamaican electricity grid. Suggestions are drawn from these experiences due to the 

long experience (since the 1980s) and wide variety of net-billing and net-metering 

structures implemented in a wide variety of states and regions. The suggestions 

include: 

• Separating interconnection and net billing, realigning various agency roles and 

responsibilities, shortening the timeline for interconnection and permitting, and 

adopting an expanded approved inverters list

• Changing the renewable energy size cap for individual systems

• Changing the deposit and fee structure for the net-billing program

• Studying and determining programmatic next steps in advance of when the 2% 

(12 MW) net-billing program cap is reached such that there is no unexpected gap 

in programming to support Jamaican policy goals. These actions could include: 

o Establishing clear goals for both net billing and distributed generation (DG) 

in the context of the countries larger renewable energy goals 

o Creating, through amnesty or registration, a full understanding of the 

current DG on the electric grid, for the purpose of longer-term planning.

o The report also describes recommendations for a policy and program 

environment to support safe, reliable, and cost-effective DG in Jamaica. 

Overall, NREL finds the pilot program to have been a key part of successfully 

developing the DG market (as defined by a growing installer industry and increased DG 

interconnection relative to prior structure). If the Government of Jamaica prioritizes the 

benefits reaped by increased DG by streamlining programmatic timing and increasing 

programmatic transparency, it is likely that demand for the net-billing program will 
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GREENING THE GRID

increase. To support safe and reliable integration of DG, NREL suggests the 

development of an integrated resource plan that provides scenario analysis. 

2 Data Analysis and Programmatic Achievements 

The JPS Net-Billing Pilot Program, initiated by the OUR in response to Jamaica’s policy 

goal of having a generation mix of 20% renewable energy by 2030, began on May 1, 

2012. Eligible systems included renewable energy systems of up to 10 kW for 

residential installations and up to 100 kW for commercial installations. The program 

compensated customers for excess energy at the short run avoided cost of generation 

rate (which is the electricity system’s total monthly fuel cost in a given month divided by 

the net generation in that month) plus 15% premium. The average avoided cost of 

generation over the pilot period was J$20.3/kilowatt-hour (kWh) or US$ 0.18/kWh (JPS 

2014).4 The pilot program duration was set at 2 years; however, applications were 

accepted through May 1, 2015.5

As of Jan. 21, 2015,6 JPS had received 326 applications for the net-billing program, and 

80 of these systems had been successfully interconnected to the grid. As of January 21, 

2015, six applications had been suspended and 240 were still listed as in process by 

JPS. The program received roughly equal numbers of residential and commercial 

applications. However, the total generating capacity of connected commercial facilities 

was roughly 10 times that of connected residential facilities (1.25 MW and 0.12 MW 

respectively). This difference is due to the larger commercial system sizes (the average 

system size being 24.6 kW) relative to the residential systems (4.2-kW average size) as 

well as a greater number of interconnected commercial customers (51) relative to 

residential customers (29). There is 1.38 MW of officially net-billed capacity comprising 

0.2% of Jamaica’s total generation capacity—well below the programmatic cap of 2%. 

There is an unknown capacity of interconnected systems that do not participate in the 

net-billing program. 

JPS reported a total program cost of J$14,277,726.80 (approximately US$125,000) 

(JPS 2014). This total includes administrative costs, procurement costs, testing, 

standards documents, and connection and inspection costs. JPS also reported 

J$3,098,442.40 (approximately US$26,900) in costs recovered through charges (JPS 

2014). These charges, according to JPS, include the direct program cost and meter,7

feature key upgrades, and utility disconnect switch payments. JPS reports that this 

equates to J$11.2M (approximately US$97,000) in unrecovered costs to the utility.

2.1 In-Person Interview Summary and Results 

NREL staff completed structured, in-country interviews with multiple stakeholders 

including six of the 80 net-billing participants. The intention was to be inclusive of a 

 4 The exchange rate of J$114.70 to US$1 (as of 4/7/2015) is used throughout this report. 5 Applications received prior to May 1, 2015, will continue to be processed. 6 As of May 26, 2015, 336 applications had been received and 120 systems had been interconnected for a total of 1.4 

MW. Because of the time frame in which it was completed, the analysis here-in summarizes data through Jan. 21, 

2015.

7 Comments on versions of the paper by different stakeholders had conflicting views about whether the utility or the 

consumer paid for the meter installation. 
4

GREENING THE GRID

variety of views, not to be a scientific sampling for the purpose of quantitative 

evaluation. These stakeholders represented the breadth of the program participants 

including regulators, policymakers, installers, residential and commercial customers, 

JSEA, GEI, and BSJ. A summary characterizing stakeholder comments is included in 

Table 1. 

Table 1. Stakeholder Comments on Net Billing and Interconnection

Stakeholder Net-Billing Pilot 

Program

Technical Regulatory Education/Training Other

OUR    

JPS    

BSJ     

JSEA   

GEI     

Installers   

Commercial 

Customers

   

Note: Some stakeholders were also residential customers, but were classified by area of greatest involvement in the 

net-billing program

2.1.1 Customer Comments

Customers were asked about the process and experience with the entirety of the 

process of the net-billing program, and their responses spanned both programmatic 

process and impact on their bills: 

• Customers reported a reduction in the cost of their electric bills up to about 30%. 

• Commercial customers stated that they were more competitive in their markets 

due to electricity cost reductions achieved by their solar systems. 

• Customers suggested that the program helped Jamaica diversify the nation’s 

energy mix—thus increasing resiliency and reducing dependency on imported 

fuels. 

• Customers with multiple systems noted that the application system improved 

over the net-billing pilot period. 

While questions and responses were focused on the net-billing program, other concerns 

were revealed by interviewees. NREL categorized the responses as net-billing pilot 

program, technical, program, regulatory environment, education/training, and noncategorized to aid in the analysis. All responses are aggregated to protect the 

anonymity of the interviewees and are summarized below.
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GREENING THE GRID

2.1.2 Net-Billing Pilot Program Comments from All Stakeholders

• Length of interconnection times, as reported by JPS, ranged from 10-18 months.8

Reasons cited for the extended timeline include:

o Lack of transparency and standardization in the licensing process

o Lack of direct current (DC) system training for electrical inspectors

o Lack of prior testing of inverters to satisfy BSJ requirements

o The process burden of multiple stakeholder interactions throughout the 

process and the corresponding soft costs

o Lack of transparency in billing practices between system installation and 

signing of the standard offer contract (SOC). The time lag is resulting in 

systems operating prior to JPS approval. Customers suggested that the 

excess energy should be valued during this time period. 

• All interviewed stakeholders suggested that the system size restraints of 10 kW 

for residential customers and 100 kW for commercial customers be reconsidered. 

There were differing opinions as to how to restructure these limits. Some 

stakeholders wanted to remove the size constraints or increase the total capacity 

limits. Other stakeholders suggested limiting the size of interconnected systems 

to a percentage of normal customer electrical consumption.

• Several stakeholders expressed concern over the deposit equivalent to 3 months 

of historical billing. These stakeholders believed that this deposit made net-billed 

renewable energy systems cost-prohibitive to most of the Jamaican population. 

There is limited transparency for customers as to whether or not the deposit is in 

fact equally required of all customers. There is also a lack of information on how 

JPS may use the customer’s deposit and the process and time frame for it to be 

returned. 

• Several related concerns about the buy-back rate were discovered. Some 

stakeholders thought that the avoided cost plus the 15% premium was too high 

as it did not account for grid costs while others thought that the rate did not 

accurately account for the benefits they provided to the grid. Concerns over the 

accuracy of accounting for the energy sold back to the grid were voiced, as were 

opinions that net-billing customers should be compensated for the value of the 

electricity they produced before the SOC went into effect. 

• Lack of consistency in quality and service across installations was mentioned as 

another concern.

• Confusion regarding the licensing and approval protocol for adding capacity to 

existing systems was highlighted.

• There was concern that increased programmatic costs without corresponding 

recapture methods would decrease utility profit.

 8 Mean reported interconnection time in U.S. jurisdictions range from 60-74 days depending on system size (Ardani et 

al. 2015).
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GREENING THE GRID

• Lack of clarity for what happens at the end of the 5-year SOC creates market 

uncertainty and financial risk for system owners according to some interviewees.

2.1.3 Technical Comments

The following technical issues and concerns were expressed:

• The impact of variable renewables on power quality, grid stability, grid security, 

and increased grid intelligence was mentioned as a concern.

• Several stakeholders cited the lack of completed standardized lists of approved 

equipment and lack of understanding of the equipment needed to interconnect 

renewable energy systems with limited negative impacts to the grid.

• Similarly, these same stakeholders noted the technical challenges of finding and 

properly inspecting grid-tied, non-net-billed systems. 

• Safety concerns for utility line workers were also cited. 

• Nontechnical transmission and distribution losses and the lack of capital required 

to address the losses were noted.

• Concerns over large systems (1-2 MW) interconnecting at the distribution level 

were voiced. 

2.1.4 Regulatory Environment Comments

The following regulatory issues and concerns were expressed:

• Multiple stakeholders said the lack of an overarching policy for all 

interconnections to the grid was a concern. 

• The lack of separate processes for net billing and interconnection without intent 

to sell excess generation leaves non-net billed systems in a gray area according 

to some interviewees.

• A lack of clear overall Jamaican energy goals and policies was cited as creating 

regulatory uncertainty.

2.1.5 Education and Training Comments

The following educational issues were brought up by some of the stakeholders:

• Many stakeholders expressed the need for consumer education campaigns to 

support the net-billing program and for better education for system owners to 

understand their photovoltaic (PV) systems’ production and functionality.

• Standardized training for installers and DC training for inspectors was requested.
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GREENING THE GRID

2.1.6 Non-categorized Comments 

The following stakeholder comments did not correspond to the above categories:

• Timeliness and consistency in the inspection process for installed systems was 

cited.

• Grid defection by large electricity consumers was mentioned.

• Quality of installation, service and supply chain of products for the Jamaican 

market was highlighted as a constraint.

3 Aligning the Net-Billing Program with Best 

Practices

Jamaica’s National Energy Plan 2009-2030 calls for 20% of the country’s energy mix to 

be supplied by renewables by 2030, but does not specify the mix of renewable energy 

technologies or set targets for utility-scale and distributed projects. NREL research 

finds that some form of valuation of excess energy sold to the grid (e.g., net billing) and 

interconnection policies are foundational market enabling policies for U.S. states to 

support solar PV markets and increase the effectiveness of subsequent market 

development policies (Krasko and Doris 2012).

In-country interviews with stakeholders revealed that the perceived goals of the netbilling pilot program included:

• Facilitating renewable energy on the grid

• Increasing democratization of power such that Jamaicans could produce their 

own, reduced cost, energy for personal use

• Contributing to a safe and reliable grid

• Increased energy security through decreased fuel imports.

Further clarification on the degree to which the government prioritizes distributed 

renewable energy over larger-scale renewable energy is necessary to optimize policy, 

regulatory, and program design. For the purpose of this review, the assumption is that 

the government prioritizes as much DG as can be safely and equitably (for the people of 

Jamaica) integrated into the electricity grid. 
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GREENING THE GRID

This section provides an overview of programmatic opportunities to meet the stated goals. Recommendations are 

summarized in Table 2. 

Table 2. Summary of Net-Billing Programmatic Best Practices 

Recommend Current Practice Best Practice NREL Suggestion Expected Impact

Increase 

Transparency by 

Improving 

Process

• Only net-billed 

systems go through 

interconnection 

process

• Duplication of 

processes by 

agencies

• 10-18 months for 

interconnection

• BSJ approves 

inverters after 

reverse 

engineering, adds 

to the approved list 

Established interconnection and 

net- metering (net-billing) 

processes:

• Separate interconnection 

process from netbilling/metering mechanism

• Utility handles interconnection 

and net billing

• 3-5 months for interconnection

• Inverters meet UL standards or 

IEEE standards (but this is for 

60 Hz grids)

Establish clear interconnection 

guidelines for all systems and 

clear net-billing program rules:

• Eliminate duplication of 

efforts by realigning 

agency roles and 

responsibilities

• Establish and enforce 

timelines for all phases of 

process

• Adopt Australian list or IEC 

62109 for inverters built for 

Jamaican grid voltage and 

frequency

More systems 

interconnecting to grid:

• More accurate 

cataloging of 

systems for JPS 

planning

• Less burdensome 

process for solar 

customers

Change RE 

System Size Cap

10 kW for residential 

100 kW for commercial

Sizing based on known load. 

Usually based on historical data (4-

12 months)9

Set size cap to meet 120% of 

average 12-month historic 

annual kWh usage of 

customer as determined by 

electricity bill and solar 10 

• Assures self-use

• Increased 

predictability of 

load and 

generation needs

Change Deposit 

and Fee 

Structure

• 3-month-equivalent 

deposit-if used by 

JPS; customer 

must replenish with 

• Deposits vary across utilities.

One example is a US$250 

residential deposit that is 

refunded if customers complete 

their applications within 365 

Reduce or eliminate the 

additional deposit requirement 

for interconnected customers, 

make it refundable if customer 

Reducing the cost to 

participate will allow 

more customers to 

install RE systems

 9 Some jurisdictions maintain a set system size cap in addition to the load-based cap. However, the best practice does not restrict overall size caps apart from 

load-based caps. 10 Where historic data is not available, loads can be estimated using average Jamaican load per square foot data. See Xcel Energy’s Home Usage Estimator in the 

references for an example.
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GREENING THE GRID

Recommend Current Practice Best Practice NREL Suggestion Expected Impact

20 days

• Application fee paid 

to OUR at 

beginning of 

process

• JPS pays the cost 

of the net billing 

meter J$47,192 

(US$410)11

• Monthly program 

fees

days 

• No interconnection fees for 

small systems. Interconnection 

study fees may be applied to 

larger RE systems with higher 

levels of penetration. Most 

utilities have a cap on what they 

can charge

• Customers do not buy meter

• Nondiscriminatory fixed 

charges for all ratepayers

adheres to timelines 

Waive interconnection fees for 

small systems (<25 kW). 

Interconnection study fees for 

larger systems can 

compensate the utility for 

engineering costs

Designing NextPhase 

DGPolicy

• Pilot program 

ended in May 2014,

but utility continued 

to accept 

applications 

through May 1, 

2015. 

• Catalogued 

systems estimated 

at 0.2%, program 

cap is 2% 

• SOC term is 5 

years

• Individual system cap at 2 MW 

or greater

• Program cap at 5% or unlimited

net-billing, buy-back rate 

equivalent to retail rate

• SOC = 20 years

• Inventory grid-connected 

systems

• Maintain 2% net-billing 

program cap with stagegate points for program 

review

• Create and publish plan 

for program after 2% cap 

is met

• Consider SOC period 

extension

• Training and certification 

of installers and inspectors

• JPS will have better 

data to forecast 

demand 

• Decrease risk for 

investors

• Stronger solar 

workforce, higher 

quality systems 

 11 Comments on versions of the paper by different stakeholders had conflicting views about whether the utility or the consumer paid for the meter installation.
10

GREENING THE GRID

3.1 Practice 1: Increase Transparency by Improving Process

Based on stakeholder comments and the success of other solar net-billing/metering 

programs, the Jamaican net-billing program could benefit through the implementation of 

clearer processes, roles, timelines, and financial requirements. Process transparency 

reduces risk and increases investment likelihood for investors, installers, and solar 

owners. The following measures can increase transparency in the net-billing program.

3.1.1 Separate Interconnection and Net-Billing Process

The current interconnection process in Jamaica only applies to net-billing systems. It 

has been described as “onerous” by multiple stakeholders and requires many 

interactions between customers, JPS, OUR, MSTEM, GEI, and BSJ. This adds to the 

numerous unregulated interconnections that may, if continued, lead to grid instability. In 

order to provide a safe and reliable grid, the stated goal of the JPS and MSTEM, 

interconnected systems must be catalogued and planned.

In the U.S. solar market, interconnection standards and net-metering/billing standards 

are separate policies and most of the actions are incumbent upon the electric utility to 

both interconnect solar customers to the grid and to activate net-metering 

arrangements. A “permission to operate” notification is required before DG customers 

can energize their installed systems and start producing power. The permission is 

granted after inspection by the local authority having jurisdiction—GEI, in Jamaica—and 

the utility to make sure all codes have been adhered to and the system is safe to 

operate. Many utilities have an online application process for interconnection and net 

billing to streamline the paperwork, keep track of where applications are in the system, 

and to ensure completion of all forms. 

NREL recommends both a separation of the interconnection and net billing; and a 

realignment of the roles of the various parties to increase efficiency, provide 

transparency to customers, and to allow for cost recovery by the agencies incurring the 

programmatic costs. NREL also recommends establishing clear and streamlined 

interconnection guidelines and processes for systems up to 2 MW on the Jamaican grid 

to allow for a clearer understanding of power flow on the grid and increase safety and 

reliability. Applications for larger systems can be reviewed by the utility on a case-bycase basis. For transparency, these processes, roles, and expected timelines could be 

posted on the JPS website. 

Figure 1 shows the recommended interconnection process for DG systems.
11

GREENING THE GRID

Figure 1: Recommended interconnection process for DG systems. The licensing requirement, 

which may be integrated into Jamaica’s regulatory requirements, is omitted in this recommended 

process flow for interconnections to streamline the interconnection process and align with 

international best practices. As interconnected but non-net-billed customers will not sell excess 

energy to the grid, they should not be considered independent power producers (IPP’s) and 

should not require a license from MSTEM to operate. 

Start

Customer submits 

application and fee 

to JPS

JPS acknowledges receipt of 

application to customer (2 

days) 

JPS: is 

application 

complete (10 

days)

Yes

JPS communicates with 

customer that application is 

accepted

Customer Initiates 

BSJ/GEI Process

Is equipment 

approved? 

(5days)

Yes

Customer installs 

DG system

Customer submits 

inspection application 

GEI Inspects 

Facility (10 

days)

Pass

GEI signs 

inspection form 

on-site

Customer submits all final 

documents and application 

for commissioning to JPS

JPS: is final 

packet 

complete 

(15days)

Yes

JPS performs 

commissioning test 

(10 days)

JPS interconnects 

Customer (5 days)

End

No

Customer has 30 

days to complete

Fail

Customer has 30 days 

to correct installation 

No

BSJ assessment 

needed J$30,000 

(30 days)

 No

JPS informs customer of 

incomplete application

Customer has 10 days 

to complete

Entity Responsible:

Blue = customer

Orange = JPS

Red = BSJ/GEI
12

GREENING THE GRID

3.1.2 Realign Agency Roles

NREL suggests realigning agency roles to avoid duplication of processes and shorten 

the timeline. Specific suggestions include: 

• Positioning OUR and MSTEM as the strategic direction setting agencies for the 

program, including setting achievable and enforceable timelines for 

interconnecting systems, establishing appropriate allocation of program costs 

and benefits, reviewing overall program caps, and serving as arbitrators of 

disputes between the utility and solar customers. The current structure of the 

OUR requires OUR’s involvement in the process as a licensing agent. Aligning 

Jamaica’s policy with international and regional best practices would indicate the 

removal of this requirement and shift the regulatory role to a strategic, 

overarching one. 

• Positioning JPS, BSJ, and GEI to implement the program including the 

integration of cost-recovery mechanisms to accurately allocate costs. 

Implementation activities include (but are not limited to) receiving and processing 

applications; approving and inspecting equipment and installations; performing 

system interconnection; processing the SOC; and accurately net-billing excess 

energy. 

These roles are common practice—regulatory and legislative bodies set overarching 

goals and policy direction while utilities and jurisdictions having authority12 are 

positioned to implement the program.

3.1.3 Shorten Timeline

Another suggested improvement is to shorten the timeline for each step. Figure 2 shows 

the recommended net-billing flow for a new (i.e., not already interconnected) solar 

system. This includes setting target maximum times for each step of the process. These 

time requirements are for all parties involved including the utility, the inspectors, and the 

customer. Enforcement of utility compliance with these timelines can vary across 

jurisdictions. For example, in California the Public Utility Commission can mandate 

process changes or levy penalties on noncompliant utilities. In Massachusetts, utilities 

can face penalties up to twice the amount of interconnection fees collected in a year 

(Ardani et al. 2015). The time limits on the steps in the flowchart in Figure 1 are based 

on average connection times and common practices among utilities.

Commonly, effective practices for net-billing programs internationally indicate that prior 

to installation of the system, the customer submits a single, complete application and 

application fee to the utility. The utility may also consider requiring a deposit from the 

customer that, upon successful interconnection, will be either refunded or applied to 

future bills. In the recommended process flow, the utility informs the customer of the 

receipt of the application within two business days and reviews the application for 

completeness within 10 business days. Incomplete applications are returned to the 

customer, who has 10 days to complete and refile the application. The utility uses the 

10-day review period to determine if a study is needed to safely interconnect the 

 12 In the U.S. market, “jurisdictions having authority” refers to the local government who oversees the permitting and 

some of the inspection process for installing renewable energy systems.
13

GREENING THE GRID

system.13 If it is determined that a study is needed, the customer is informed of the 

study justification, timeline, and possible costs. Upon completion of the study, the 

customer is informed of any cost-incurring actions in order to move forward with the 

application. If the customer chooses to abandon the project due to the results of the 

study, the application fee is refunded. Once an application has been accepted, the utility 

informs the customer that construction may begin. The utility also begins the process of 

replacing the existing meter with a net-billing capable meter and conducting any 

necessary distribution upgrades. Note that for interconnected but not net-billed 

customers, the net billing functions will be switched off by the utility. Also, to ensure 

accurate applications, any installations with capacities greater than +/- 10% of the 

capacity for which the application was made will have to submit a new application, and 

will forfeit fees and deposits associated with the incorrect application.

Customers should acquire inspection applications when they begin installation as well 

as submit their intended component information to BSJ. BSJ will then have 5 days to 

inform customers whether or not the intended components are on the approved list. If 

their intended system components are not on the BSJ approved list, they should submit 

full product specifications to BSJ for approval. It is important to note that using nonpreapproved components will add up to 30 days to the process. 

Upon successful installation of the DG system, the customer will submit the GEI 

application for inspection including all system and facility drawings. The GEI will then 

have 10 business days to complete the site inspection.14 If the DG system fails 

inspection, customers will have 30 days to make corrections and resubmit the 

application for inspection. GEI will then re-inspect the system. GEI will sign letters of 

completed inspection on-site. 

Customers will then submit their final application packets to JPS. This packet will 

include the final system drawings, the signed inspection letter, insurance documents (if 

applicable), specification sheets on system components, BSJ reports on nonpreapproved equipment (if applicable), interconnection agreement, and application for 

commissioning. The utility will then have 15 business days to review the application. If 

the application is incomplete, it will be sent back to the customer. The customer will then 

have 30 days to complete the packet. Upon acceptance of the application packet, JPS 

will have 10 business days to complete the commissioning test. Within 5 days of the 

successful commissioning test, the customer will be interconnected and the system may 

be energized. 

The timeline above equates to a maximum 57 days from application submission until 

system interconnection. It should be noted that any incomplete application or 

unapproved installation will incur greater time in the process. It should also be noted 

that some of these processes may be done in parallel—thus shortening the length of 

time to interconnection. 

 13 Screen limits should be set under which systems can automatically be assessed to determine the need for an indepth system study. It is recommended that these screening criteria be developed following established guidelines,

such as the Federal Energy Regulatory Commission’s Small Generator Interconnection Procedures, and published to 

the JPS net-billing website. 14 This standard time frame could be negotiated with GEI to account for staffing considerations.
14

GREENING THE GRID

For new interconnection customers who wish to participate in the net-billing program, 

the final application pack to JPS will also include a net-billing application form. The netbilling form will be returned to the customer with the approved application. The customer 

will then apply for a license to sell electricity back to the grid through MSTEM. MSTEM 

will grant or deny the license within 10 business days and send copies of the license to 

both JPS and customer. JPS and the customer will then have 10 days to complete the 

SOC. Upon the signing of the SOC, JPS will perform the commissioning test and 

interconnect the customer as described above. It should be noted that customers who 

elect to interconnect, but not net-bill (that is not sell excess electricity to the grid), will 

not require licensing through MSTEM as they will not be operating as electricity 

suppliers. Only customers who elect to net-bill will obtain a license from MSTEM to 

supply grid power. 

Existing interconnection customers can elect to participate in the net-billing program at 

any time. To do so, they must submit net-billing application forms along with a copy of 

their interconnection agreements to JPS. JPS will have 15 business days to review the 

application. The approved application will be sent back to the customer. The customer 

must apply for the license from MSTEM. MSTEM will have 10 business days to grant or 

deny the license and send a copy to JPS and the customer. The SOC signing, 

commissioning test, and interconnection will then proceed as described above. 

As illustrated in the sample timeline above, JPS, GEI, and BSJ are the only entities 

responsible for the implementation of the interconnection program. The process was not 

designed to remove OUR or MSTEM from the program, but rather to give both entities a 

strategic role of program design and oversight. As noted above, current policy 

frameworks in Jamaica make licensing by MSTEM a requirement to sell power back to 

the grid. As such, MSTEM will continue to have an implementation role in the next 

iteration of the net-billing program. 
15

GREENING THE GRID

Figure 2: Suggested net-billing flow for a new DG system. The OUR license recommendation is 

omitted in this recommended process flow for net billing for process streamlining in accordance 

with international and regional best practices. It is understood that the current policy framework 

may not allow for this omission, and that a cross-governmental group may be valuable in 

streamlining the process in accordance with current laws.

3.1.4 Adopt an Expanded Approved Inverters List

Another area with the potential to increase transparency and to reduce costs is to 

expand the approved power converter (inverters list). Customers wishing to interconnect 

and net bill could be required to use an inverter on the approved list. NREL 

recommends that Jamaica consider utilizing the Australian Clean Energy Council’s list 

of compliant inverters that is used for that country’s renewable energy credit scheme. 

The list includes grid-connected inverters, off-grid inverters, micro-inverters, multimode 

inverters, energy + storage inverters, grid control devices, and power conversion 

equipment; and it is easily searchable online 

at: http://www.solaraccreditation.com.au/products/inverters/approvedinverters.html#searchResults. 

It also states which components meet the International Electrotechnical Commission 

(IEC) 62109 standard, which is for the safety of power converters for use in PV 

systems. This list is suggested because it incorporates many different component types, 

it denotes which components meet the international standard, it is transparent, and it is 

Customer submits final 

interconnection packet 

and net billing form to JPS

JPS reviews 

final packet 

(15 days)

Complete

JPS returns approved net 

billing form to customer

Customer submits form, 

license application, and 

fee to MSTEM

MSTEM sends license to 

JPS and copy to customer 

(10 days)

JPS and Customer Sign 

SOC (10 days)

JPS performs 

commissioning test (10 

days)

JPS connects customer 

enabling net billing 

channels on meter (5 

days)

End

Entity Responsible:

Blue = customer

Orange = JPS

Green = MSTEM
16

GREENING THE GRID

used by Australia, which has a sub-climate that is tropical and coastal and its grid 

operates at 50 hertz (Hz); factors applicable to Jamaica’s climate and grid.

3.2 Practice 2: Change Renewable Energy Size Cap for Individual 

Systems

The current individual renewable energy system size in Jamaica is limited to 10 kW for 

residential and 100 kW for commercial systems. Some U.S. states in leading solar 

markets set the allowable system size based on a percentage of the customer’s load. 

For example, an allowable size might be a system that would meet 120% of a 

customer’s average load over a 12-month period.15 This limit ensures that solar 

customers are not over incentivized to produce solar power that they won’t use on-site. 

In cases where electric vehicle charging is paired with a renewable energy system, 

these limits are increased, usually by the equivalent of 200-300 kWh per month to allow 

for charging the vehicle and using the solar energy on-site. In comparison, Puerto Rico 

sets the system cap at 25 kW for residential and 5 MW for nonresidential systems in 

phase 1 of its net-metering program. In phase two, the system caps were set at 15 kW 

for residential customers and 100 kW for commercial customers with the stipulations 

that customers could only be compensated for up to 1.5 times their monthly 

consumption. The Dominican Republic’s net-metering program limits system sizes to 25 

kW for residential customers and 1 MW for commercial customers.

NREL recommends that individual system size caps for the Jamaica net-billing program 

be based on 100%-120% of the customer’s previous 12-month historic peak load. NREL 

recognizes that there are differing methodologies for sizing DG systems with varying 

levels of complexity. However, a system cap as a percentage of customer peak 

electrical load will ensure that the users of the interconnection and net-billing program 

are primarily using the generated power for self-use—a stated goal of the program. 

3.3 Practice 3: Change Deposit and Fee Structure

Utilities may collect application and interconnection fees to recover costs incurred in 

reviewing and approving DG systems for connecting to the grid. Deposits may also be 

collected to ensure adherence to interconnection timelines. In Colorado,16 the deposit 

for a residential system is US$250 which is refunded if the customer completes their 

application within 365 days. If it is forfeited, the utility puts the deposit into the state’s 

renewable energy fund. In U.S. states with leading solar markets, interconnection fees 

are waived or limited to US$100 for net-metered/billed systems up to 25 kW. Fees may 

range up to US$300 for non-net-metered/billed systems up to 25 kW. Fee structures for 

larger systems vary and may include inspection fees, study fees, or interconnection 

fees. Typically fee structures for systems greater than 25 kW include a fixed charge 

plus a variable charge based on the system size. In the United States, California law 

states that solar customers cannot be charged additional fees. Solar customers of 

 15 For new construction, home load estimate tools may be used in place of historical data. See Xcel Energy’s home 

usage tool in the references for an example. 16 The Colorado deposit example is taken from Xcel Energy’s solar renewable energy credit program.
17

GREENING THE GRID

Austin Energy do not pay extra for their net meters as the utility spreads the cost over 

all the ratepayers.

Solar customers in Jamaica pay several different fees and a deposit to participate in the 

net billing program. Table 3 shows these fees. If JPS uses the customer’s deposit, the 

customer is required to replenish it within 20 days.

Table 3. Customer Paid Fees in Jamaican Net Billing

In U.S. best practice solar markets, net-metered customers are not charged additional 

costs and in some cases are protected from additional charges by law. Fixed charges, 

akin to Jamaica’s monthly program fees, are charged to all customers and vary by state. 

These fixed charges are used as a cost-recovery mechanism for transmission, 

distribution, and administrative costs. Other costs for net-metered customers are 

spread across all ratepayers. One recent study found that at PV penetration levels of 

2.5% or less, customer-sited PV results in roughly equivalent levels of revenue 

reductions and cost reductions to the utility, thereby having minimal to no impact on 

non-net-metered customers. At greater penetrations, revenue reductions exceeded 

cost reductions under existing rate recovery mechanisms (LBNL 2014). Cost recovery 

for net metering programs is a commonly discussed issue for many states and utilities in 

the United States. and they are considering various rate designs to equitably allocate 

such costs. It is difficult, with currently available data, to assess the cost savings to the 

utility related to reduced fuel purchases due to increased DG. It is recommended that 

these cost savings be measured and incorporated into total program benefit and cost 

calculations. 

Insurance requirements for renewable energy system owners differ in Jamaica in that 

homeowners may not carry property insurance. Program requirements for the netbilling program dictate that residential system owners carry liability insurance against 

Description Cost J$ Cost US$

Assessment and Approval of Grid Inverters $ 30,000 $ 261

Deposit - 3 Months Bill varies varies

Meter $ 57,835 $ 503

Insurance varies varies

Monthly Direct Program Costs - Residential $ 315 $ 3

Monthly Direct Program Costs - Commercial $ 700 $ 6

Application Fee - Residential $ 2,000 $ 17

Application Fee - Commercial $ 10,000 $ 87

Infrastructure Changes/Upgrades varies varies

Impact Study Cost varies varies

Additional Required Property Tax for RE System varies varies

Utility Disconnect Switch $ 25,000 $ 217

Meter Add-ons $ 22,093 $ 192

Meter Bi-directional Communication $ 23,828 $ 207

Large Commmercial (over 200VA) ONLY UDS $ 200,000 $ 1,740
18

GREENING THE GRID

any damage caused by their renewable energy systems. Best practices in areas in 

which homeowners insurance is typical dictate the exemption of additional insurance for 

systems less than 1 MW. Further examination of risks and exposure as well as 

insurance products and costs available can inform these requirements in the next phase 

of the program. 

Given that Jamaica’s solar penetration level of net-billed systems is at 0.2% as of this 

analysis, costs for participating in the net-billing program could be spread across all 

ratepayers removing barriers to nascent solar market development.17 As penetration 

levels approach the 2% net-billing program cap and the costs to nonparticipating 

customers become appreciable and measurable, cost allocation can be reconsidered. 

When the amnesty of interconnected systems is evaluated, the program cap may be 

close to being met. See Recommendation 4 in Appendix B for additional information.

NREL recommends, in accordance with best practices in other jurisdictions, both 

reducing the additional deposit requirement for renewable energy systems and 

establishing transparency regarding how the utility implements and repays the deposit. 

If customer fees are retained, they could be allocated to the entity incurring the costs to 

allow for cost recovery.

3.4 Practice 4: Designing the Next Phase of Distributed Generation 

Policy 

Because of the high, competing electricity costs that have ranged from approximately 

US$0.25/kWh to US$0.37kWh throughout the pilot period, renewable technologies are 

economically viable with some customers reporting payback periods, without incentives, 

of 6-8 years. Economic drivers coupled with a further streamlining of the process and 

counting of uncatalogued systems indicate that total DG on the grid may exceed 2%. 

NREL recommends several near-term measures, in addition to Recommendations 1-3 

in Appendix B, to improve the net-billing program including implementing better data 

collection, revisiting the SOC period, and establishing training for installers and 

inspectors . 

The period for the Jamaican SOC is 5 years. Due to high electricity prices in Jamaica, 

the payback period on PV systems (6-8 years) is shorter than in other markets with 

lower electricity prices. Correspondingly SOCs range from 15-25 years in markets with 

feed-in tariffs and are usually 20 years in U.S. net-metering markets. Multiple 

stakeholders expressed concern over the lack of transparency as to what happens to 

their net-billing arrangements after the 5-year SOC period is over. Revisiting and 

extending the contract period may, for the purposes of reducing risk, further support 

programmatic goals.

Training for solar installers can increase the quality of the solar installations and 

minimize installation and inspection time. An endorsed installers list could be 

 17 For more information on how DG impacts all ratepayers, see Financial Impacts of Net-Metered PV on Utilities and 

Ratepayers: A Scoping Study of Two Prototypical U.S. Utilities in references (Satchwell et al. 2014).
19

GREENING THE GRID

established to ensure quality control. BSJ or JSEA could design and implement a 

certification or minimum training level for installers to increase JPS’s confidence in the 

quality of the installations.18

A mid-term measure to keep solar market momentum going might include examining 

utility rate designs and crafting policy to send desired market signals. While the 

National Energy Plan sets overarching goals for renewable energy, policymakers could 

set clear, long-term goals specifically for solar including the desired amounts for 

distributed, community-scale and utility-scale systems. Policy and rate designs can 

then be constructed to achieve these goals and keep momentum going in the solar 

market. Such rate designs can include implementing a feed-in-tariff, using a value of 

solar tariff, reallocating fixed and variable charges to ratepayers, changing the net-billing 

rate, or setting a fixed-compensation rate. 

4 Policy, Program and Technical Environment to 

Support Safe and Reliable Distributed Generation in 

Jamaica

The goal of the recommendations presented is to increase customer access to DG 

while also ensuring safe, reliable power generation, transmission, and distribution in 

Jamaica. Regulatory and policy considerations must be balanced with technical 

concerns to achieve this goal. Recommendations are based on lessons learned and 

best practices from other jurisdictions as well as considering the Jamaican context. To 

keep market momentum going, NREL recommends that the OUR lead a stakeholderdriven, integrated resource planning process including studies to understand the costs 

and benefits of increased DG on the grid.

It is anticipated that making the above programmatic changes will result in a 

streamlining of access to DG. This streamlined access coupled with the economic 

viability of DG technologies in Jamaica will lead to an increased capacity of DG. This 

increase is not without some risk—particularly to the stability of the grid. The currently 

interconnected renewable energy systems account for less than 1% of Jamaica’s 

energy generation capacity. At these levels it is difficult to quantify the impacts of DG. 

However, there are several feeders identified by JPS as having more than 10% DG, and 

these feeders could be studied for a better understanding of how DG is affecting the 

grid. Additionally, the current energy generation mix should be able to accommodate 

increased levels of variable renewable energy as petroleum generation can be ramped 

up and down with relative ease. 

In order to ensure that the expansion of DG enhances safe and reliable grid operation, 

NREL suggests the maintenance of the 2% program cap pending better understanding 

of increased DG on Jamaica’s grid. There are several options for this including steadystate analysis, dynamic grid simulation, transient studies, fault (or short circuit) studies, 

 18 For example, the North American Board of Certified Energy Practitioners, a nongovernment organization, sets 

standards for renewable energy professionals in North America.
20

GREENING THE GRID

and quasi-static time series (QSTS) analysis19. It should also be noted that these 

various studies and simulations can be used in concert to create the most robust 

analysis of a power system. 

4.1 Steady-State Analysis 

The first option is to expand on existing grid studies such as the MSTEM-commissioned 

study, Grid Impact Analysis and Assessment for Increased Penetration of Renewable 

Energy into the Jamaican Electricity Grid. This study was a steady-state analysis of the 

Jamaican grid using a plausible renewable energy mix. Siemen’s PSS-E Power 

Transmission System planning tool was used for the study as it was the same software 

used by JPS. Steady-state studies typically include analysis of load or power flow 

studies. The MSTEM commissioned study looked at both of these issues. This study 

could be updated using current renewable energy system data and known planned 

system data. This would provide an analysis that more closely mirrors Jamaica’s actual 

renewable energy mix. 

The goal of a steady-state study is to solve and evaluate power flow operations under 

worst-case scenarios. This allows utility planners to ensure that there is sufficient 

generation for loads and losses, voltages at busses are at an acceptable level, 

generators operate within active and reactive power constraints, and transmission and 

distribution systems are not overloaded. This is a good first-cut analysis to understand 

the ability of the grid to absorb renewable energy systems.

4.2 Dynamic Grid Simulation

The second option would be to conduct a dynamic grid simulation. Dynamic studies are 

often used to assess the feasibility of high-penetration levels of variable renewable 

energy on the grid. Dynamic modeling analyzes components that affect namely the 

synchronous machine, turbine governor, and exciter system. Dynamic modeling shows 

whether or not these components will allow a system to remain in synchronism following 

a major event such as a fault or sudden change in load or generation. 

4.3 Transient Studies

Transient studies may also be conducted to understand power quality issues such as 

harmonics and flicker. Transient studies require highly reliable data on generation, 

loads, and power system characteristics. 

4.4 Fault or Short-Circuit Studies

Fault, or short-circuit, studies analyze the ability of protective devices to withstand or 

interrupt short-circuit current. These studies determine the magnitude of current flowing 

through the system following a fault until steady state is reached. These studies are 

most often used to set parameters for relay settings and typically consider a variety of 

fault types including three-phase, phase-to-phase, double-phase-to-ground, and phaseto-ground faults.

 

19 For more information, please see https://solarhighpen.energy.gov/topics/modeling_and_analysis
21

GREENING THE GRID

4.5 Quasi-Static Time Series Analysis

Finally, QSTS analysis can be used to evaluate the operation of a power system. QSTS 

simulations solve multiple power flow equations at a set, consecutive, discrete time step 

(ranging from 1 second to 1 hour). It is important to note that the modeled system has to 

return to an equivalently static (quasi-static) state before the next time series solution 

can be solved. QSTS is best used for low-bandwidth system components (e.g., line 

voltage regulators) and is not appropriate for high-bandwidth dynamic behavior 

modeling. QSTS simulations often include variable-load and generation data from 

distributed renewable energy systems on the grid. This allows determination of timebased bus voltages and the effects on the system due to generator control 

mechanisms. 

4.6 Study Recommendations 

Based on stakeholder interviews, the NREL team recommends the following steps to 

analyze the impact of high DG penetration on the Jamaican grid. First, appropriate 

stakeholders20 should undertake a grid-wide survey of all interconnected systems that 

are not currently operating under an SOC. During the stakeholder interviews, multiple 

stakeholders knew of grid-tied renewable energy systems on the grid that had been 

interconnected with little oversight from the utility. These same stakeholders noted that 

it was difficult to know exactly how much DG was on the grid. In order to have 

appropriate inputs into any model, the number, sizes, and locations of these systems 

must be determined. Without this information, models and simulations will likely not 

yield useful results. 

Upon completion of the grid survey, steady-state analysis can be conducted (or updated 

from the previous model) to determine possible problematic points on the system. 

These points should subsequently be studied in greater detail. After steady-state 

analysis, transient studies should be conducted on the system. Several stakeholders 

noted power quality concerns with increased DG penetration—these transient studies 

will determine the extent of any power quality issues. Transient studies should be 

followed by dynamic simulation to determine any DG impacts on synchronism. 

As penetration levels reach and surpass the 2% threshold, QSTS simulations can be 

considered. These comprehensive simulations allow detailed analyses of the system –

including time-depended load and generation changes due to variable renewable 

energy generation. These models involve significant input data including details on 

lines, transformers, capacitors, and voltage regulators as well as historical time-series 

information on loads and renewable energy system output. The more granular the 

analysis, the more data required. This amount of data also requires significant 

processing power to run the simulations. 

Grid analyses can be obtained from private entities who utilize commercially available 

software.21 NREL can also provide grid analysis support through our Energy Systems 

Integration Facility—the United States’ premier facility for research, development, and 

 20 JPS and GEI would be integral to a grid survey, and the participation of OUR and MSTEM would improve 

integration with longer-term national priorities. 21 Software options include the free Electric Power Research Institute platform OpenDSS available at: 

http://smartgrid.epri.com/SimulationTool.aspx.
22

GREENING THE GRID

demonstration of the components and strategies needed to optimize the entire energy 

system. NREL can also offer request for proposal design assistance to complete the 

above analyses. 

Finally, all stakeholders discussed the need to review the rate at which customers are 

compensated for electricity supplied to the grid. There are many ways to evaluate the 

benefits and costs of DG technologies. Energy, environmental, and ancillary services 

costs and benefits; generation, transmission, and distribution capacity values; and 

transmission and distribution loss adjustments are all commonly considered when 

making this type of rate decision. Other benefits and costs that can be considered 

include hedging against volatility and enhancing energy mix diversity. To create a longterm, sustainable, and fair DG market, it is recommended that this type of study be 

conducted by the OUR and MSTEM.22

5 Conclusion

The JPS Net-Billing Pilot Program has commensurate impact with other programs of 

similar design and duration. Programmatic complexities, however, combined with 

favorable economics (6-8 year paybacks) for DG systems may be resulting in 

uncatalogued interconnections. Streamlining the program design to enable easier 

interconnection to the grid is likely to result in increased program participation quickly 

reaching the 2% program cap and increasing the understanding of DG systems on the 

grid. Understanding the DG systems interconnected to the grid (with and without net 

billing) can result in increased planning capacity for JPS to be able to measure progress 

toward national renewable energy goals.

 22 A general framework for this study can be found in Methods for Analyzing the Benefits and Costs of Distributed 

Photovoltaic Generation to the U.S. Electric Utility System listed in the References section (Denholm et al. 2014).
23

GREENING THE GRID

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Austin Energy, personal communication, 3/3/15.

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on renewable energy nationally appropriate mitigation actions (NAMAs) for policy makers and project 

developers. Accessed April 7, 2015: http://decarboni.se/publications/irena-handbook-renewable-energynationally-appropriate-mitigation-actions-namas-policy-makers-and-project-developers/.

IRENA. (2012). Grenada Renewables Readiness Assessment. Accessed April 7, 

2015 https://www.irena.org/DocumentDownloads/Publications/Grenada_RRA.pdf.

Jamaica Public Service Company Limited. (2014). Net Billion Pilot Programme Report to OUR.

Krasko, V.A.; Doris, E. (2012). Strategic Sequencing for State Distributed PV Policies: A Quantitative 

Analysis of Policy Impacts and Interactions. NREL/TP-7A30-56428. Golden, CO: National Renewable 

Energy Laboratory. Accessed March 26, 2015. http://www.nrel.gov/docs/fy13osti/56428.pdf.

Konold, M. (2013). “Renewable Energy and the Dominican Republic.” EarthTechling. Accessed April 7, 

2015: http://earthtechling.com/2013/01/renewable-energy-and-the-dominican-republic/.

MSTEM. (2009). Jamaica’s National Energy Policy, 2009-2030. Accessed March 26, 

2015: http://ocs.mona.uwi.edu/public/conferences/12/schedConfs/11/energyPolicyOctober212009.pdf

New York Department of Public Service, Personal Communication, March 14, 2013.
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Net Metering for Bahamas and Barbados. (2010). Metering.com. Accessed April 7, 2015. 

http://www.metering.com/net-metering-for-bahamas-and-barbados/.

Olson, L., et al. (2014). “Renewable Energy Island Index and Marketplace.” Presented at the 2014 

Caribbean Renewable Energy Forum. Accessed March 26, 2015: http://castaliaadvisors.com/files/2014/CREF-Castalia_Index_and_Marketplace_141007-1.pdf

Pacific Gas and Electric Company (2015a). Distribution Interconnection Handbook. (2015).. Accessed 

March 26, 2015: 

http://www.pge.com/en/mybusiness/services/nonpge/generateownpower/distributedgeneration/interconne

ctionhandbook/index.page. 

———. (2015b). Net Energy Metering. Accessed March 18, 

2015: http://www.pge.com/en/mybusiness/services/nonpge/generateownpower/netenergymetering.page

———. (2015c). Standard Net Energy Metering (NEMS). Accessed March 26, 

2015: http://www.pge.com/en/mybusiness/services/nonpge/generateownpower/netenergymetering/standa

rdnem/index.page

“Renewables Interactive Map Country Profile: Dominican Republic.” (2015). Renewable Energy Policy 

Network for the 21st Century. Accessed April 7, 

2015. http://www.map.ren21.net/pdf/profilepdf.aspx?idcountry=41.

Sacramento Municipal Utilities District, personal communication, 2/27/15.

Satchwell, A.; Mills, A.; Barbose, G. (2014). Financial Impacts of Net-Metered PV on Utilities and 

Ratepayers: A Scoping Study of Two Prototypical U.S. Utilities. DOE DE-AC02-05CH11231. Berkeley, 

CA : Ernest Orland Lawrence Berkeley National Laboratory. Accessed March 26, 

2015: http://emp.lbl.gov/sites/all/files/LBNL%20PV%20Business%20Models%20Report_no%20report%20

number%20%28Sept%2025%20revision%29.pdf.

“Status and Outlook of the Renewable Energies in the Dominican Republic.” (2012). Global Workshop on 

Clean Energy Development: Establishing a Foundation for Low Carbon Energy Systems. Accessed April 

7, 2015. http://www.usea.org/sites/default/files/event-

/Dominican%20Republic%20Country%20Presentation_0.pdf.

Sustainable CUNY. (undated). NYS Net Metering FAQ – Residential. Accessed March 18, 

2015: http://www.cuny.edu/about/resources/sustainability/solar-america/installerresources/ResidentialNYSNetMeteringFAQFinal.pdf.

U.S. Department of Energy. (2015). “Sunshot Initiative High Penetration Solar Portal.” Accessed March 

20, 2015: https://solarhighpen.energy.gov/.

Virgin Islands Water and Power Authority. (2013). Net Metering. Accessed April 7, 2015: 

http://www.viwapa.vi/OurEnergyFuture/NetMetering.aspx.

“WAPA Eliminates Requirement for Net Metering.” (2013). Virgin Islands Daily News. Accessed April 7, 

2015: http://virginislandsdailynews.com/news/wapa-eliminates-requirement-for-net-metering-1.1462067.

Xcel Energy. (undated-a). Minnesota Solar*Rewards® Sample Customer Contract. Accessed March 26, 

2015: https://www.xcelenergy.com/staticfiles/xe/Marketing/Files/MN-SR-Contract.pdf.

———. (undated-b). Small Generator Interconnection Agreement. Accessed March 18, 

2015: https://www.xcelenergy.com/staticfiles/xe/Marketing/Files/CO-SR-Interconnection-AgreementCustomer-Owned.pdf
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Appendix A. Best Practice Resources for Stakeholders 

(Annotated Bibliography)

The following resources may be of interest to the stakeholders designing the next phase 

of Jamaica’s net-billing program and investigating grid integration. Many of the 

resources are based on the U.S. solar market although contain relevant information for 

the Jamaican context. While many of these sources reference net metering, they 

contain relevant information for net-billing program design as well. A further list of 

curated resources on DG from the 21st Century Power Partnership is available 

at: http://www.21stcenturypower.org/dglibrary.cfm

Grid Architecture 3.0

Description: This report, commissioned by the U.S. Department of Energy, outlines the 

emerging vision of a “smart grid” in the United States. The report is not intended to be a 

full treatment of reconstructing a modernized grid; rather it outlines the structural 

challenges of the U.S. current grid and presents some visions of what the next 

generation electric grid could look like. The document is being used as a resource by 

New York in its Reforming the Energy Vision Process, which will enable utilities to better 

plan for distributed energy generation.

Available at: http://www.pnnl.gov/main/publications/external/technical_reports/PNNL24044.pdf

Organization(s): U.S. Department of Energy, Pacific Northwest National Laboratory

Methods for Analyzing the Benefits and Costs of Distributed Photovoltaic Generation to 

the U.S. Electric Utility System

Description: This report examines current and potential future methods, tools and data 

for capturing the benefits and costs of distributed solar photovoltaics. The focus is on 

characterizing these costs and benefits from the perspective of an electricity generating 

utility in the United States. The report is being used by several leading U.S. solar states 

to inform their calculations “value of solar” cost figures.

Available at: http://www.nrel.gov/docs/fy14osti/62447.pdf

Organization(s): National Renewable Energy Laboratory, Jarett Zuboy

Model Interconnection Procedures

Description: This guidebook is on its third update and outlines best practices in 

interconnection procedures in the U.S. solar market. It specifies the various technical 

requirements, level of review (screens), time frames, and fee processes that have 

emerged from the Interstate Renewable Energy Council’s (IREC’s) work with utility 

representatives, states, and engineers to incorporate renewable energy onto the grid.

Available at: http://www.irecusa.org/wp-content/uploads/2013-IREC-InterconnectionModel-Procedures.pdf

Organization(s): IREC
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Net Metering Model Rules

Description: This guidebook provides a template for utilities to use when establishing or 

updating net energy metering rules. The guide is a widely used resource in the U.S. 

solar market. IREC is an unbiased non-profit organization with over a decade of 

experience in state regulatory proceedings.

Available at: http://www.irecusa.org/regulatory-reform/net-metering/

Organization(s): IREC

Xcel Energy Home Usage Estimator

Description: This is an example of a simple home energy usage estimator. This type of 

estimator can be used to appropriately size DG systems for new homes with no energy 

consumption history.

Available at: www.xcelenergy.com%2Fstaticfiles%2Fxe%2FMarketing%2FCO-SR2010-Home-UsageEstimator.xls&ei=TWo1Vb7vKuTbsATN0oGQDw&usg=AFQjCNH9AVupH8v91fKOZXn

HO9I-AHbKKg&sig2=_tdy53pQ_PTqQsda2VvXMw
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Appendix B. Summary of Stakeholder Comments on 

Draft Versions of Report

In May 2015, the authors delivered a draft of this report to stakeholders in Jamaica and 

collected further comments on the recommendations. The review confirmed the core of 

the recommendations, and comments were offered by a variety of stakeholders on 

potential implementation strategies. Those comments are catalogued in this appendix. 

The comments in this appendix were captured in a public meeting, and are therefore 

attributed to the commenting agency. This summary is not intended to validate the 

comments, only to catalogue them. 

Recommendation 1: Separating interconnection and net billing, realigning 

various agency roles and responsibilities, shortening the timeline for 

interconnection and permitting, and adopting an expanded approved inverters list

Commenters indicated that the shortening of the timeline is preferable to the current 

longer system. Jamaica Public Service Company Limited (JPS) noted that due to the 

on-site inspection necessary to ensure that surrounding infrastructure is technically 

acceptable for system integration and suggested that a more realistic time was 60 days. 

The Jamaica Solar Energy Association (JSEA) suggested that in addition to the 

Australian list for inverters, the European lists also should be considered. JPS 

representatives suggested and the Office of Utilities Regulation (OUR) agreed to 

meeting within 2 weeks to develop a schedule to determine next steps for the net-billing 

pilot program or revised policy. JPS noted that it is developing an integrated resource 

plan due for delivery in early 2016. Installers also commented that there is a different 

process for the JPS solar mill product than for other interconnected systems. JPS noted 

that its inspection (which the recommendation within indicates should be removed) is 

required because it needs confirmation that surrounding infrastructure can support DG. 

All stakeholders expressed interest in clear guidelines for the program in terms of 

programmatic capacity cap. 

Recommendation 2: Changing the renewable energy size cap for individual 

systems to further support the programmatic goal of electricity for self-use

JPS and OUR suggested that to maintain programmatic simplicity the residential system 

cap remain at 10 kilowatts (kW) and the commercial cap be altered to be 120% of 

historic use to ensure self-use and be maintained at an upper limit of 100 kW until the 

current programmatic cap is met. During the technical training, clarification was sought 

on historical use. It was suggested by installers that the cap be adjusted to be 120% of 

historic annual kilowatt-hour (kWh) usage—a quantity currently tracked through the JPS 

billing system. JPS noted that a standardized kWh/square-foot measure would need to 

be used by both the installers and JPS in order to appropriately size systems. Some 

installers supported a 150% cap for commercial to adjust for time-of-use rate usage. 

Recommendation 3: Changing the deposit and fee structure for the net-billing 

program to include cost recovery for the investment of investing stakeholders

JPS suggested that a cost-recovery mechanism for investments needs to be clearly 

outlined in the revision to the policy. Installers argued that the deposit should be 

removed entirely or reduced after 12 months because net-billing customers represent a 

reduced financial risk as their payments to JPS are lower. JPS and OUR noted that 
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waiving the interconnection fee for smaller (residential) systems may be more common 

and appropriate for more mature markets and may still be necessary in Jamaica to 

ensure safe interconnection to the grid. 

Recommendation 4: Studying and determining programmatic next steps in 

advance of when the 2% (12 MW) net-billing program cap is reached

This includes: 

• Establishing clear goals for both net billing and DG in the context of Jamaica’s 

larger renewable energy goals. 

• Creating, through amnesty or registration, a full understanding of the current DG 

on the electric grid, for the purpose of longer-term planning.

All commenters agreed that a clearly outlined goal for DG could drive a more stable 

market development for DG in Jamaica. All commenters agreed that the evaluations 

and next steps should be done prior to the end date of the program to avoid market 

disruptions. There was a lack of clarity as to whether the 2% cap referred to all DG or 

just that connected through the net-billing program, and comments surrounding gaining 

clarity on that through policy. Installers noted that the Governor of Jamaica had 

requested that JPS start investing in a more flexible grid and suggested that the next 

iteration of the net-billing program could be a part of that effort, if planned in concert. 

All commenters agreed that the determination of programmatic design for DG, following 

meeting the 2% cap on the net-billing program, should be determined in advance of 

meeting that goal. Installers at the technical training expressed concern that amnesty 

may not be fully given to customers with un-cataloged photovoltaic systems due to laws 

surrounding electrical system alterations. They noted that clear definitions of an 

amnesty (or registration) program would have to be outlined. 
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Appendix C. Specific Submitted Written Comments 

from Stakeholders

Robert Wright, New Leaf Solar

a. Caps - I think that the hard caps should be increased from 10 kW to 15 kW for 

residential systems to take into account some of the larger houses that exist in Jamaica, 

especially in Kingston and Montego Bay. Increasing the cap would not preclude smaller 

residential systems from being installed and especially in resort areas would be more 

appropriate for some of the second homes and villas that need more capacity than 10 

kW. This will support increased competitiveness and help lead to increased investment 

and employment; all good things. Time of Use analysis should not apply to residential 

systems.

The commercial systems should have their hard cap increased from 100 kW to 200 kW. 

There are thousands of manufacturing and commercial entities that can easily consume 

the power produced by a 100 kW system and so a 200 kW system would be more 

appropriate. The use of Time of Use data would be encouraged but I would suggest 

increasing the maximum size to 150% of the peak consumption to take into account 

variances in the TOU patterns that exist from customer to customer. Factories that 

operate at night, for example, will need to export more power during the day to support 

self consumption, a consensus goal of MSTEM and the OUR.

b. Residential Set Aside - JPS advised that approximately 50% of the quota under the 

net billing pilot project had been applied for even though only 0.2% of the 2% 

penetration goal had been fully approved and commissioned. It seems to me that we 

would want to ensure that the residential stakeholders, critical participants if we want to 

democratize access to power, should have a specific MW amount set aside for 

residential installations only; say 4 MW. That would mean that the approximately 1000 

households would be guaranteed to secure systems using the 4 kW as the average size 

of a residential PV installation. 

c. Three Months Security Deposit - This should be completely scrapped and only 

introduced based on credit risk assessment; which is what it was originally intended for. 

It’s completely discriminatory and unfair.

d. JPS Cost Recovery - International precedent should be used to determine what fees 

JPS should reasonably charge. They should not be allowed to recover the entire cost of 

their staff and systems investment from net billing customers as much of the 

investment was required anyway (like upgrades to their legacy IT and Billing systems) 

they receive commensurate benefits from the program like access to meters that can 

communicate wirelessly and access to cheap, clean power at a competitive price per 

kWh; not to mention the goodwill earned and brand halo burnished as a result of their 

support of clean energy on the island. This project has also allowed them to set up a 

new profit center, their solar mills and energy efficiency.

e. Overall Net Billing Penetration Goal - Should be increased from 2% to 5% and the 

existing amount will be exhausted soon and it should be a policy imperative to promote 

distributed solar even more so that utility size solar facilities that benefit a few and have 
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GREENING THE GRID

to accept the wholesale PPA rate. Distributed solar allows for customers to peak shave 

and displace expensive power at the retail rate. The target should therefore be 

increased now in the national interest.

David Barrett, ENBAR Consulting

THE COMMENTS EXPRESSED ARE THOSE OF THE AUTHOR ONLY AND 

COINCIDENTALLY MAY OR MAY NOT REPRESENT THE OPINIONS OF ANY 

OTHER INDIVIDUAL, GROUP OR ORGANISATION. PLEASE BE GUIDED 

ACCORDINGLY.

General –

1. Very useful overarching document incorporating a number of stakeholder inputs and 

concerns.

2. Most of the findings are accurate and recommendations for a second phase 

programme welcomed.

3. Critical to change the report title from the “JPS Net Billing Pilot Programme”. With 

Cabinet approval, MSTEM established the National Net Billing Policy, under 

legislation/regulations and administered same under the OUR through JPS. This is 

a National Net Billing Programme.

4. Attach NREL ToR in appendix so readers can determine the limitations placed on 

the consultants and also independently determine if the objectives were met. 

5. Separate the recommendations from the findings (may be a table of the barebones 

of all recommendations and a table of all findings or executive summary for quick 

reference). The PPT presentation for example was a useful summary. 

6. It was expected that NREL may have made comments/recommendations on the 

tariff allocated to the net billing programme (short-run avoided cost + premium). 

What is the international experience? Is the rate acceptable within options for 

computing the SoC Tariff? Is the rate arbitrary and can it be made more empirical? 

Etc.?

2.0 pages 7– critical to note that OUR provided 2 separate start dates in its public 

determination notice (see JSEA documents provided) when determining the start/end 

dates. As such the end dates should be accurately stated.

2.0 page 7 – critical to note that since the programme start date the success rate from 

application to license has been approx 85% (under control of OUR and MSTEM); 

success rate from license to SoC and interconnection has been approx 25% (under 

control of JPS/GEI/client). In the latter timeline the GEI normally responds within the 

expected 15 days but applicants have been frustrated by very fluid changes, 

uncertainties and challenges with the JPS managed stages.

2.0; PAGE 8 – clarify “JPS also reported J$3,098,442.40 (approximately US$26,900) in 

costs recovered through charges (JPS 2014). These charges include the direct program 

cost and meter, feature key upgrades, and utility disconnect switch payments. JPS 

reports that this equates to J$11.2M (approximately US$97,000) in unrecovered costs 
31

GREENING THE GRID

to the utility”. Please note the applicant pays for the new meter, disconnect switch, 

facility upgrade etc.

2.1.2 – include;

• Significant bottleneck at stages dealing directly with JPS (85% success with 

obtaining license; 25% success towards final SOC). 

• JPS has undue, excessive and inordinate control of process of inspection and 

approval after license.

2.1.2 – can NREL recommended QF capacities for phase 2?

2.1.2 – was this stakeholder JPS or OUR? (a) “Some stakeholders thought that the 

avoided cost plus 15% premium was too high as it did not account for 3 grid costs”.... 

(b) “Confusion regarding the licensing and approval protocol for adding capacity to 

existing systems was highlighted”.(c) ” There was concern that increased programmatic 

costs without corresponding recapture methods would decrease utility profit”. 

Recommendation – it is critical to separate utility comments from net billing (QF) clients 

for clarity and that grouped comments correctly represent the constituency groupings as 

the two constituents (utility or licensees) have diverse goals and expectations for the 

programme. As stated, the experience as grouped and described could adversely 

affect the recommendations and outcomes for the QF client experience towards a 

second phase. 

2.1.2 – add comments.

• There needs to be a centralised Governmental repository for Net Billing data 

(number of licenses; number of SOCs; status of application process, etc.). The 

MSTEM and OUR are usually not up to date on a daily basis regarding the status 

of the National GoJ programme and has to request the data of JPS.

• Payment and submission locations should be diversified from the JPS Kingston 

office only. (JPS has many offices with admin capacity in other parishes).

• Uncertainty of when net billing payments would be made, frequency and form of 

payment needs to be resolved (some clients have not been paid after 1 year and 

there are various explanations for when, how and how much they will be actually 

paid).

2.1.3 – separate utility and OUR comments from utility/net billing clients for clarity 

and to correctly represent the constituency groupings. How the experience is grouped 

and described could adversely affect the impression of the client experience for a 

second phase.

2.1.4 Clarify – “A lack of clear overall Jamaican energy goals and policies was cited as 

creating regulatory uncertainty.” The National Net Billing Policy, RE targets, and 

programme generation caps are clear. 
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GREENING THE GRID

2.1.6 – comments;

• Separate utility and OUR comments from utility/net billing clients for clarity 

so the perspectives correctly represent the constituency groupings. How the 

experience is grouped and described could adversely affect the client experience 

for a second phase.

• Require mandatory Quality Performance Standards from utility with sanctions.

• Communication between QF and utility to be formal (written).

• Inadequate, unclear and veiled communication from utility to QF and applicants 

in particular. Timely communication needed from Utility and Regulator.

• Clarity needed on who has authority in determinations for disputes and 

processes in the programme - OUR or utility - (OUR refers to JPS and vice versa 

regarding resolutions of complaints for action by QF/applicants). 

• Utility should not burden the programme with information requests from applicant 

e.g. applicant is required to obtain the utility data from the utility, to give to the 

utility, to connect to the utility (e.g., pole numbers, transformer information are in 

the possession of the utility, etc.). Also applicant has to provide line drawing 

beyond the boundary of their premises and the RE system. Utility has service 

address and all associated information. These requirements in the application 

are unnecessary, onerous and should be removed.

• Written report should be required especially from GEI in cases of failed 

inspection outlining (a) issues and (b) recommendations so QFs can respond 

quickly and appropriately.

• JPS treats its solar mill clients differentially with shorter inter-connection time and 

previously with a 2-way digital meter with no export credits. This was not 

publicised to the market while net billing was being executed in parallel with the 

JPS stream. Also there is a fair trading issue as the JPS advertises its 

SolarMill product as “Standard offer Contract Ready” and also that “1 Utility 

Disconnect Switch” is included in the offer. JPS clients are therefore not 

subject to the approved and regulated Net Billing Application Process, have 

lower interconnection equipment costs and also are accelerated in the queue 

(see attached - http://www.myjpsco.com/wp-content/uploads/E-STORE-SOLARMILL.png; dated 1/6/2015).

Table 2 – recommendation - establish quality performance standards with sanctions for 

utility to meet reasonable timeline and deliverables.

Table 2 – recommendation - set commercial size cap as a fixed number for simplicity. 

Unable to evaluate the impact of 120% of average 12 month historic peak load of 

customer as determined by the electricity bill as acceptable. Perhaps a simple cap of 

say 200 – 300 kW is simpler and adequate for a non-IPP programme.

Table 2 – in Jamaica, the deposit is related to non-payment liabilities. Remove 3 

month deposit as the client has reduced the non-payment performance risk to the 

utility through self generation.
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Table 2 – payment of net billing SR Avoided costs tariff must be clarified in terms of 

frequency and form. 

3.1.1 – accept recommendation - “online application process for interconnection and 

net billing to streamline the paperwork, keep track of where applications are in the 

system and to ensure completion of all forms”. Excellent.

3.1.1 – accept recommendation – “interconnection standards and net metering/billing 

standards are separate policies and most of the actions are incumbent upon the electric 

utility to both interconnect solar customers to the grid and to activate net metering 

arrangements. A “permission to operate in parallel with the grid” notification is required 

before DG customers can energize their installed systems and start producing power”.

Separations of interconnection and net billing is positive - but also make rules and 

conditions public instead of the current practice of utility negotiating and approving 

interconnections on a case by case onsite basis, and with the current accelerated path 

for its Solar Mill clients.

Proposed process flow recommendations for modification;

• JPS – 7 calendar days for residential application evaluation only (10 days too 

long). 10 days allowed for commercial QFs in the event that an assessment is 

required.

• Customer should be permitted to undertake on their own cognizance to initiate 

Licensed Electrician inspection, GEI and BSJ process in parallel with JPS 

application at his/her own risk (i.e. it's the customer’s risk with low liability or cost 

to JPS et. al.). This will allow the applicant to shorten the total SoC period.

• CLARIFY – “JPS: Is final packet complete” (15 days).

• Insert start point/execution and duration for SOC process.

• Insert MSTEM/OUR licensing application/approval start/approved and duration. 

Figure 1; page 15 – comment on process flow for net billing – accept recommendation –

“As interconnected but non-net-billed customers will not sell excess energy to the grid, 

they should not be considered IPP’s and should not require a license from MSTEM to 

operate”.

3.1.2 – Clarify – “Positioning JPS, BSJ, and GEI to implement the program including the 

integration of cost recovery mechanisms to accurately allocate costs”. JPS desires to 

recover costs on items which should be included under normal maintenance and 

systems which improves their safety and data collection for billing etc.

3.1.3 – Accept recommendation - setting target maximum times for each step of the 

process. These time requirements are for all parties involved including the utility, the 

inspectors, and the customer. Enforcement of utility compliance, mandate process 

changes or levy penalties on non-compliant utilities, penalties apply to GEI, BSJ and 

Utility.
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3.1.3 – Comment – “If the DG system fails inspection, the customer will have 30 days to 

make corrections and resubmit the application for inspection. GEI will then re-inspect 

the system. GEI will sign letters of completed inspection on-site”. Written reports should 

also be required of GEI (or JPS) if DG system (applicant’s system) fails inspection.

3.1.3 – is the alternate process flow suggesting a license AFTER the SOC application or 

is it just the same process flow on another page?

3.1.3 – for simplicity summarise and restate the total timelines for;

• Smooth unimpeded application process (best case scenario). (Total XX days).

• Challenged and impeded application process including applicant fault (worst 

case scenario). (Total xx days)

3.1.4 – is considered favourably (“NREL recommends that Jamaica consider utilizing 

the Australian Clean Energy Council’s list of compliant inverters that is used for that 

country’s renewable energy credit scheme”) however to avoid limiting the technologies 

perhaps other proven lists for other jurisdictions could be added?.

3.3 – reject – “Given that Jamaica’s solar penetration level of net billed systems is at 0.2 

percent as of this analysis, costs for participating in the net billing program could be 

spread across all ratepayers removing barriers to nascent solar market development”. 

The residential sector in particular is antagonistic to further costs regardless of how 

miniscule and particularly to the sharing of costs with non-beneficiaries. This was 

already demonstrated and rejected during the JPS Tariff rate review.

3.3 – table 3;

• Reject - Deposit Upgrade of 3-Months Bill.

• Reject – or at best share meter cost and meter bi-directional communications. (a) 

Utility will need to replace/upgrade meters in its normal maintenance operations 

and was doing so even without the net billing programme (b) utility needs the 

meter to conduct its normal rate collection activities (c) the new meter with its 

data and communication features is an advantage to the utility for quality data 

collection.

• Reject of share utility disconnect switch – required by the utility. RE systems has 

effective anti-islanding feature. Experience worldwide over time shows this to be 

a sufficient and highly effective option for safety. Also BSJ should be required to 

confirm that equipment has anti-islanding feature to satisfy the requirement, 

therefore mitigating the disconnect switch requirement. 

3.4 – recommendation – extended SOC period is very acceptable, but in any case 

should be no less than 15 yrs.

3.4 – accept – “An endorsed installers list could be established to ensure quality 

control”.

4.6 - amnesty has to be created first before investigation of the number of DG 

interconnected systems to allow free sharing of information without penalty implications.
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Other Recommendations:

1. STRONGLY AND CLEARLY RECOMMEND GOING FORWARD INTO A SECOND 

PHASE of no less than 5 years.

2. Recommendations for going forward are integrated in the main report. Clear 

recommendations ONLY should also be accessible (see recommendation #1 above) 

as such a summary should clarify and expand recommendations for going forward. 

Use either expanded summary, table of recommendations, appendix/annex or 

executive summary for clarity and brevity.

3. Study should also reference net billing and net metering practices and experiences 

particularly in SIDs of the Caribbean and other locations (USVI, Bahamas and 

Barbados referenced in literature but not effectively in the report).

4. Although there may be various interconnection issues of concern to JPS, the Net 

Billing Programme should be clearly separated from non-net billing interconnection 

recommendations. 

Other:

Based on the Stakeholders review workshop, it is apparent that JPS wishes to address 

wider issues of large commercial interconnection, feeder capacity and RE clusters, 

multiple non-net metering inter-connection processes, potential/future grid stability risks 

and a forward planning via an IRP or grid stability study. These are however not the 

prevue of the Net Billing programme and should be separated as the Net Billing 

Programme in its current state is not a threat/risk. However it may be prudent to 

proceed to develop parallel processes for interconnection for the 0 – 100kW option for 

overall addition of new small generation, so small systems can be monitored, be fairly 

and transparently included and well managed. 

The current suspension is therefore unnecessary and the programme should resume 

while these matters are addressed.