Customers

• Sezibwa Homes
• Microgrid Design
• Budget - Phase 1: Sezibwa Homes
• Site Layout
• Procurement Pictorial
• Monthly Finances
• Sezibwa Site Plan for Phase 2
• Ownership (Membership)
• Phase 1 Pictorial
• Customer Registry
• Inspection Document
• Welcome Note to Customers
• Outage log
• Phase 1.1
• Phase 2.0
• PDU layout
• Nansana Community Microgrid Pilot
• Microgrid Cabinet Line Diagram
• Sezibwa rooftop solar: panel layout and installer brief
• Business Model
• Business Models for the NFE Microgrid OS
• Solar Plus Battery Economic Case (Sezibwa)
• Battery Arbitrage Economic Case (Sezibwa)
• Optimal Solar and Battery Allocation (Sezibwa)
• Battery Price Break-Even (Sezibwa)
• Solar Sizing Re-run, Sept 2026 (600 Wp panels)
• Sezibwa solar purchase: final Muden quote (19 Oct 2026)
• Market Intelligence
• Opinions on what causes Power Outages
• AES: From Backup to Backbone: Community Microgrids to boost National Grid Reliability
• Potential Customers
• Macro outlook: shilling, rates and NFE (15 Oct 2026)
• Sawa Energy's Bellavista proposal (competitor benchmark)
• UMEME → UEDCL transition: market impact
• Tracking prospects in ERPNext CRM
• Commercial RPMs
• NFE Commercial Reliable Power Microgrids
• Commercial RPM decision log
• Assessing a Commercial RPM lead
• Commercial RPM economics and bankability
• Worship Harvest (Commercial RPM customer #1)
• NFE Commercial RPM Finance Glossary

Sezibwa Homes

Microgrid Design

Budget - Phase 1: Sezibwa Homes

 

Realtime financials tracked via open collective here: https://opencollective.com/nfe/projects/sezibwa-homes-nfe-pilot

 

 

Bill of Quantity NFE-Nansana
S/No	Item	Specifications	Quantity	SI Unit	Rate(UGX)	Amount (UGX)
1	Enclosure box for the PDU	80cm*60cm*25cm	1	box	550,000	550,000
2	Single phase MCCB	160A ABB	3	pc	120,000	360,000
3	Three phase Smart meter	80A Chint	1	pc	400,000	400,000
4	Busbars (Red, Yellow, Blue, Black and Green Yellow)	200A	5	pc	150,000	750,000
5	Circuit breakers	80A	10	pc	30,000	300,000
6	Enclosure Trunkings (Slotted grey truncking)		2	pc	30,000	60,000
7	Din rail		1	pc	10,000	10,000
8	Self tapping screws	0.5"	1	pkt	35,000	35,000
9	Cable lugs ring	16mm pin	18	pc	3,000	54,000
10	Cable lugs ring	25mm ring	18	pc	5,000	90,000
11	Sleeves	25mm	2	m	5,000	10,000
12	Sleeves	16mm	2	m	3,000	6,000
13	Flexible Cable Red	25mm	2	m	15,000	30,000
14	Flexible Cable Blue	25mm	2	m	15,000	30,000
15	Flexible Cable Yellow	25mm	2	m	15,000	30,000
16	Flexible Cable Red	16mm	4	m	8,000	32,000
17	Flexible Cable Yellow	16mm	4	m	8,000	32,000
18	Flexible Cable Blue	16mm	4	m	8,000	32,000
19	Flexible Cable Yellow Green	10mm	2	m	5,000	10,000
20	Flexible Cable Black	2.5mm	2	m	1,500	3,000
21	Flexible Cable Green	2.5mm	2	m	1,500	3,000
22	Flexible Cable	2.5mm	2	m	1,500	3,000
23	Communication Cable	1.5mm	6	m	1,500	9,000
24	Indicator lamps	230V	3	pc	5,000	15,000
25	Double Socket	Pcs	1	pc	10,000	10,000
26	Insulating tape	Pcs	5	pc	3,000	15,000
27	Pin lugs 25sqmm for different colours	Pkt	1		4,000	4,000
28	Pin lugs 16sqmm for different colour	pkt	1		3,000	3,000
29	Airal Cable	35sqmm ABC Cable	100	m	15,000	1,500,000
30	IPC	35-70sqmm	8	EA	6,000	48,000
31	Armoured Cable	25qmm	10	m	65000	650,000
32	UEDCL 3phase Commercial Meter	TOU Code 10.2	1	EA	3,500,000	3,500,000
33	Service Cable	16sqmm 2 Core cable	30	m	15,000	450,000
34	Service Cable	16sqmm 3 Core cable	150	m	30,000	4,500,000
35	Service Cable	16sqmm 5 Core cable	100	m	50,000	5,000,000
36	Smart Meters	1 Phase DinRail Split prepaid meter-1.pdf	10		290,000	2,900,000
37	LoraWAN gateway	CAL-025.pdf	1		1,803,000	1,803,000
38	Labor (installation)	Green Volta			2,000,000	2,000,000
Total						25,237,000

Reconciled budget attached 1RECONCILIATION NFE-NANSANA.pdf

Site Layout

Procurement Pictorial

   

 

     

 

 

 

Monthly Finances

Energy Sales 

We are making these sales projects based on what they spend today and not the power they use.

• Number of Customers: 10 
• Average historical spend per customer: 80,000 UGX per month (about 3kWh per day, for 30 days)
• Total Revenue: 800,000 UGX per customer (800 UGX per kWh)

Expenses 

• Bulk Purchase of power: 491,760 UGX (546.4 per kWh at 3kWh per day for 30 days for 10 customers)
• Taxes (18% VAT) - Charge to customer? 
• Operations: 100,000 UGX 
• Real time expenses tracked here on Open Collective

Net Returns 

• Sales - Expenses: 308,240 UGX

Sezibwa Site Plan for Phase 2

Ownership (Membership)

This project is community owned as per the model described here. 

Funders 

• NFE - 21,300,071 UGX 
• Unallocated - 3,936,929 UGX

Workers 

• NFE 

Customers 

• Non Eligible yet

Phase 1 Pictorial

        

Customer Registry

Name	House Number	Contact	Meter Number

Inspection Document

Inspection Document.pdf

Welcome Note to Customers

Hello, This is Aaron from Nearly Free Energy. We provide reliable electricity to neighbourhoods like yours.

Your landlady has agreed to work with us to bring reliable power to your neighborhood. This will be done in the a 3 phase process.

Phase 1: Smart Metering:

We will switch you from Yaka to Smart Meters. This is needed in order for us to monitor when UEDCL power goes off so that we can size your neighbourhood backup correctly.

Phase 2: Backup installation:

We will install the right sized battery backup so that when UEDCL goes off, you power remains on. These batteries will be charged when UEDCL is on so that they can be ready when UEDCL is off. This backup will come on automatically so you should not notice when UEDCL is off.

Phase 3: Solar Generation:

We will install solar panels on your roof to help charge the batteries when UEDCL is off for much longer periods like several weeks.

Frequently asked Questions

If Yaka is gone, how will I pay for power?

You will switched from prepaid to postpaid. This is the same way you pay for your water bill. You receive a monthly bill from us via SMS and you will have 5 days to pay the bill via Mobile Money, Visa or Mastercard.

How can I know how much I have used at anytime during the month?

Please contact us on our Whatsapp business account. We shall check your smart meter and share with you our usage.

What happens when I don't pay my monthly bill by the 5th day of the month?

Your smart meter will automatically turn off power to your house. Once you pay the bill, the meter automatically turns power back on.

When will Phase 1 be completed?

Phase 1 is currently in progress. We are targeting to complete phase 1 by end of this week.

When will Phase 2 be completed?

We are targetting to start Phase 2 in December 2025, I should be completed within a month depending on transport logistics of the batteries. They are being imported from supplier overseas.

When will Phase 3 be completed?

The timelines for Phase 3 are not yet determined but will likely be within 2026.

How much will I be paying for power?

The cost of power will not change. IT is determined by ERA (Electricity Regulatory Authority). You will be paying the same domestic rate you are paying today: https://www.uedcl.co.ug/approved-tariffs. You will charged domestic rate fees per unit you use + VAT (18%) + monthly service charge (5320 UGX). All these charges exist on your Yaka bills. The only change here is that it's postpaid not prepaid. 

What if I want to still pay using prepaid token like Yaka?

At this time, our system doesn't support this payment mode. But we think postpaid is better for most customers so we think you will find it more convenient than yaka tokens.

What happens to my current yaka balance and yaka meter?

UEDCL will entually reposes that yaka meter. The timelines for this are unclear. However please contact us and share your current Yaka balance, we will credit the units to your monthly bill for next month.

How can I contact you?

You can email us on team@nearlyFreeEnergy.com or Whatsapp us on 077

Outage log

Date	Duration	Reason	Impact	Remarks
1 September 2025	8 hours	2/3 phases with voltage too low due to a broken link, this one impacted a wider area (whole of Nansana)	all 10 customers impacted because deployment was still in progress	Known to happen fairly often and could we temporarily resolved  locally with a phase selector
6th September 2025	1 hour	Meter Alarm triggered for Main house	Main house only	Need to investigate reason why alarm/relay was triggered
9th September 2025	6 hours	Transmission team doing substation maintenance so they shut down the line	10/10 houses impacted.

Phase 1.1

Goal

• Install phase selectors to increase reliability when some phases have low voltage 

Item	Specification	Quantity	Unit Price	Amount	Remarks
PDU	80cm*60cm*25cm	1	900,000	900,000	We need a bigger PDU in order to fit the phase selectors
Phase selectors		3	300,000	900,000
Labor		-	-
Total				18,000,000

Phase 2.0

Goal: Adding Battery Capacity. We are estimating that we need to add 15 to 25 kWh of battery capacity. We are yet to do some analysis on the consumption and outage profile for the community to determine what would be the ideal capacity. 

 

 

PDU layout

H3 - 200326020209
H2 - 210302003356
H1 - 200326020101
R1 - 250902040216
R2 - 
R3 - 200326020199
R4 - 250902040373
R5 - 200326019807
Boys Q - 200326019929
Main House - 200326020128

Nansana Community Microgrid Pilot

Demonstrating Open-Source Community Energy Systems on Unreliable Grids

Executive Summary

Nearly Free Energy (NFE) is developing a new generation of community-owned microgrids designed for urban and peri-urban communities connected to unreliable electricity grids. Unlike traditional rural electrification microgrids, NFE's approach focuses on improving reliability, resilience, and long-term energy abundance for communities that already have a grid connection but experience frequent outages and poor service quality.

To validate this approach, NFE deployed its first pilot microgrid in Nansana, Uganda. The pilot currently serves 10 households and provides a real-world environment for testing smart metering, distributed energy resource (DER) management, battery-backed reliability services, and open-source microgrid control technologies.

The pilot has successfully demonstrated the technical feasibility of NFE's Microgrid OS architecture and provided valuable operational data that is informing the design of larger community deployments.

---

The Problem

Over the past decade, electricity access has improved significantly across Africa. However, millions of households remain connected to grids that suffer from frequent outages, voltage instability, and poor reliability.

Nansana reflects this challenge. While households are connected to the national grid, they regularly experience power interruptions that affect household activities, communications, education, and small businesses.

Traditional backup solutions such as petrol and diesel generators are expensive, noisy, polluting, and inaccessible to many households.

NFE believes that community microgrids can provide a more affordable, scalable, and sustainable alternative.

---

Project Objectives

The Nansana pilot was established to:

• Validate NFE's Microgrid Cultivation Blueprint.

• Test open-source energy management technologies in real operating conditions.

• Evaluate customer demand for improved electricity reliability.

• Develop and test smart metering infrastructure.

• Demonstrate battery-backed community energy services.

• Generate operational data for future commercial deployments.

---

Pilot Configuration

Location

Nansana, Wakiso District, Uganda

Community Served

10 households

System Components

• Smart meters installed at participating households.

• Community battery storage system.

• Backup power infrastructure.

• Raspberry Pi 4B controller running OpenEMS.

• Communications network for remote monitoring and management.

• MicroPowerManager integration for metering and operational functions.

Operational Phase

The pilot currently operates within the Monitor and Backup phases of NFE's Microgrid Cultivation Blueprint.

---

Technical Innovation

One of the most important outcomes of the pilot was the transition from a proprietary gateway architecture to an open-source Microgrid OS architecture.

Initial Architecture

The original system relied on a proprietary gateway capable of communicating only with specific smart meter vendors.

This approach limited flexibility, interoperability, and scalability.

Current Architecture

The pilot now uses a Raspberry Pi 4B running OpenEMS.

This controller can communicate with:

• Smart meters using Modbus.

• Battery systems.

• Inverters.

• Future distributed energy resources.

This transition has significantly improved interoperability and established the foundation for NFE's Microgrid OS platform.

Images from site 

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Key Learnings

Open Standards Enable Scalability

The pilot confirmed that open standards such as Modbus can support interoperability across multiple device types and vendors.

Communities Value Reliability

Participating households consistently identified reliability as a higher priority than simply having access to electricity.

Software is as Important as Hardware

The ability to monitor, orchestrate, and automate distributed energy resources is essential for scalable community microgrids.

Phased Adoption Reduces Risk

The Monitor → Backup → Backbone → Community Power Plant progression allows communities to adopt advanced energy services gradually while minimizing technical and financial risks.

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Next Phase

The next phase of development will expand the solution from 10 households in Nansana to approximately 100 households in Garuga.

Key objectives include:

• Development of an open-hardware controller based on the NPE X500 CM4 platform.

• Deployment of additional battery and solar assets.

• Expansion of smart metering infrastructure.

• Enhancement of Microgrid OS capabilities.

• Validation of autonomous microgrid operation.

• Progression toward the Backbone phase of the Microgrid Cultivation Blueprint.

---

Long-Term Vision

NFE's long-term vision is to enable thousands of households across Africa to benefit from reliable, resilient, and increasingly abundant clean energy through community-owned microgrids.

The Nansana pilot represents the first step toward a scalable platform that combines:

• Open-source software.

• Open-hardware controllers.

• Distributed energy resources.

• Community ownership.

• Autonomous microgrid operations.

By demonstrating these capabilities in a real-world environment, the pilot has established the technical and operational foundation for future deployments and broader adoption across Africa.

Microgrid Cabinet Line Diagram

Sezibwa rooftop solar: panel layout and installer brief

For: the Green Volta installers and the NFE site team. Owner: Aaron Tushabe. Last reviewed: 21 Oct 2026. Status: proposed. The layout was worked out from satellite imagery, so do the site checks below before drilling.

The plan

• What: 8 × Golden Sun GS600N-144M (600 W, 2278 × 1134 mm, 30 kg each), 4.8 kWp in total, from the Muden quote.
• Where: the long north-west-facing face of the house at about 0.36236, 32.53602 (Nansana). The pin 0.36245, 32.53592 lands on the neighbour's roof about 15 m to the north-west.
• How: one row in portrait (long side up the slope), split into two groups of 4 with a 1.5 m gap around a vent or flue. The top edge sits about 0.4 m below the ridge. Flush-mounted at the roof pitch.
• Wiring: all 8 panels in one series string into PV1 of the SRNE ASP48120SH3. PV2 stays free.

Why this roof face

At 0.36° N the sun is close to overhead all year, so the direction a face points makes little difference:

Roof face	kWh per year	Worst month (kWh/day)
North-west (chosen)	6,780	16.8 (Nov)
South-west	6,770
South-east	6,660	15.7 (Jun)
North-east	6,640

PVGIS (SARAH3 data, 2005 to 2023), 20° pitch, 14% system losses, no tree shade.

The trees decide it. Tall trees stand against the north, north-east and east sides of the house, and big trees to the south and south-west. The north-west face looks away from most of them. All 8 panels are on one string, so shade on one panel pulls down all 8. The north-west face also gives the steadiest output through the year.

Site checks before drilling

Words used in these checks

Word	What it means	How to check it on site
Ridge	The top line of the roof, where the two roof faces meet.
Eave	The bottom edge of the roof, where the gutter is.
Roof face	One sloping side of the roof. Ours is the side facing the alley (north-west).
Pitch	How steep the roof is, in degrees.	Lay a phone level app on the sheet, pointing up the slope. Or use a 1 m level and the table in picture 4.
Face depth	The distance from the eave to the ridge, measured along the sheet (following the slope, not on the ground).	Run a tape up one rib from the gutter edge to the ridge. It must be at least 3.0 m.
Purlin	Wooden strips under the iron sheets, running the same way as the ridge. The sheets are nailed to them, and the L-feet must screw into them.	Each straight row of roofing nails across the roof is a purlin. Measure the gap between rows (picture 2).
Rafter	The sloping timbers under the purlins, running from eave to ridge.	Look inside the roof space if you can, and check for rot or termite damage.
Crest and valley	The high ribs and the low channels of the corrugated sheet.	Drill only through a crest. Rain runs down the valleys (picture 3).

• Vent or flue. Satellite shows two dark marks about halfway along the face, roughly 8.7 m from the north-east end. If nothing is there, close the gap between the groups to about 0.3 m (keep the two rail pairs separate) and centre all 8 panels on the face.
• Pitch. Measure it and write it on this page. Anything from 10° to 25° is fine.
• Face depth. Eave to ridge along the slope must be at least 3.0 m (2.28 m panel, 0.4 m at the ridge, margin at the gutter). The satellite estimate is about 4.7 m.
• Purlins. Find their positions and spacing. Each rail has to sit on a purlin line.
• Shade.
  • Stand at the array position at about 8 am, noon and 4 pm, or use a sun-path app.
  • Trim the trees on the north, north-east and east sides and on the south and south-west sides to below ridge height.
  • Check that the neighbour's roof (north-west, across the alley) is not higher than our ridge.
• Roof condition. Replace rusty or loose sheets and rotten timber under the array first.
• Cable route. Measure from the drop point to the inverter so the 6 mm² cable can be ordered.

Mounting

The hardware on the Muden quote matches this layout exactly: two 5.1 m rails per group of 4 portrait panels.

Item	Per group	Total	On the quote
Rail, 5100 mm	2	4	4
End clamp	4	8	8
Inter clamp	6	12	12
L-foot	6	12	12

• Rail position: rails run parallel to the ridge, about a quarter of the panel length (about 570 mm) in from the top and bottom edges, so about 1.14 m apart.
  • The panel datasheet does not give the clamping zone, so check Golden Sun's installation manual.
  • Move the rails within that zone so they land on purlins.
• L-feet: 3 per 5.1 m rail gives spans of about 2.25 m. Check the rail's span table. 4 per rail (about 1.5 m spans) is safer: that's 4 more L-feet, about 48,000 UGX at the quoted price.
• Fixing: fix the L-feet into the purlins, not just the iron sheet. Go through the crest of the corrugation, with EPDM washers and sealant.
• Airflow: leave about 100 mm under the panels. Cooler panels produce more.
• Load: about 240 kg of panels plus rails, spread over about 21 m².

Wiring: one string of 8 into PV1

	String of 8	SRNE ASP48120SH3, per PV input	OK
Open-circuit voltage	422 V at 25 °C, about 440 V on a cold morning	800 V max	✓
Max-power voltage	359 V, about 310 V on a hot afternoon	200 to 650 V tracking range	✓
Current	13.4 A at max power, 14.0 A short-circuit	22 A max	✓
Power	4.8 kW	9 kW max	✓

The hot and cold figures assume typical n-type temperature coefficients (open-circuit voltage −0.27 %/°C, max-power voltage −0.30 %/°C), because the panel datasheet does not give them.

• Two strings of 4 will not work. They would run at about 155 to 180 V, below the inverter's 200 V minimum. The 4 + 4 split is physical only.
• Panel to panel: panels 1 to 4 connect directly with their 300 mm leads. A short jumper crosses the gap to panel 5, then panels 5 to 8 connect directly.
• Return lead: the string's + leaves panel 1 and its − leaves panel 8, so one lead runs back along the row (about 11 m).
  • Tie it under the panels along the lower rail.
  • Drop both leads at whichever end is nearer the inverter.
  • Keep + and − together all the way to the inverter. A small loop picks up less lightning surge.
• Cable: 6 mm² UV-rated PV cable (the 4 mm² was out of stock). Voltage loss over a 30 m run is under 1%.
• MC4 connectors: crimp them with the proper tool and mate only with compatible connectors.
• At the inverter:
  • The 32 A 4-pole DC isolator, wired to its diagram for 500 V+ DC (usually two poles in series on each polarity).
  • Then the 1000 V DC surge protector, with a short lead to earth.
  • The inverter is IP20, so it must be indoors.
• Earthing: bond every rail and panel frame to the site earth with at least 6 mm² copper.

Not on the Muden quote: bring these

• 6 mm² PV cable for the return lead (about 11 m), the jumper and the run to the inverter. Measure first; 30 to 40 m was budgeted.
• Earthing conductor, lugs or bonding clips, and the connection to the earth rod.
• Roof sealant, EPDM washers, UV-rated cable ties or clips.
• Optional: 4 extra L-feet.

Commissioning

• Before closing the isolator: check polarity and measure the string's open-circuit voltage.
  • Expect about 370 to 425 V in daylight. It reads lower when the panels are hot.
  • About 50 V low means a panel is left out of the string.
  • About 100 V low means one panel is connected backwards.
• Insulation test: if a tester is available, test + and − to earth.
• Close the isolator. Check PV1 voltage, current and power on the inverter display and in OpenEMS.
• Photos: the panel labels and serial numbers (for the warranty), the finished array, the isolator and the surge protector.
• Update this page with the as-built positions, the measured pitch and the voltage reading.

Commissioning log

Date and time (EAT)	Check	Result
26 Oct 2026, about 16:45	String open-circuit voltage at the bottom of the 6 mm² drop cable, isolator open (INGCO DM360011 meter, 600 V DC range)	379 V, positive on the red probe. All 8 panels are in series, none reversed, and the drop cable is continuous.

Expected output

Average kWh per day by month, unshaded, north-west face at 20° (PVGIS):

Jan	Feb	Mar	Apr	May	Jun	Jul	Aug	Sep	Oct	Nov	Dec
18.6	20.0	20.4	19.7	18.7	18.5	19.1	18.2	18.2	17.7	16.8	17.2

That is about 6,780 kWh a year. It agrees with the 5.2 peak-sun-hour assumption in the sizing re-run (about 19.5 kWh/day). Single days swing a lot with the weather. A month that comes in well below these figures points to shade or a wiring fault.

Assumptions

• Roof dimensions come from Google and Esri satellite imagery, scaled from the Google Maps scale bar, and are good to about ±0.5 m. The pitch is assumed to be 20°.
• The PVGIS figures include no tree shading.
• Sources: Golden Sun GS600N-144M datasheet; SRNE ASP 8 to 12 kW three-phase datasheet V1.0.

Related pages

• Sezibwa solar purchase: final Muden quote (19 Oct 2026)
• Solar Sizing Re-run, Sept 2026 (600 Wp panels)
• SRNE ASP48120SH3 Safe Settings Write: design, registers, and commissioning
• Microgrid Cabinet Line Diagram

As built, 26 Oct 2026

• All 8 panels in one row on two continuous rail lines; the unused vent was removed (landlord agreed), so no gap.
• Clamps: the one-row layout needs 14 inter + 4 end clamps; 12 + 8 were supplied, so the 4 spare end clamps were used back to back at one joint.
• 6 mm² PV cable (negative 25 m, positive 15 m; ~0.4% drop). FMPV32 4-pole DC isolator, manual layout 4B; 1000 V DC surge protector across +/−; inverter PV1 (PV2 unused).
• Readings: 379 V open circuit at 16:45 EAT; inverter PV1 152 V at sunset (18:39).
• Open: earthing (no earth point on site) for the surge protector and rails; possible tree shading at one end of the array.
• Operating plan and commissioning log: Sezibwa Solar + Battery Operating Plan.

Business Model

Business Models for the NFE Microgrid OS

[!info] Current working basis — August 2026
Tariff: UEDCL Code 10.2, Q3 2026: Peak 666.5 / Shoulder 562.1 / Off-Peak 429.7 UGX/kWh. The full tariff schedule must remain a configurable model input because ERA/UEDCL rates change periodically. Sezibwa base case: zero export value until site eligibility, interconnection terms, and the applicable export credit are confirmed. All commercial offers should be re-run with site-specific load, tariff, capex, financing, and reliability assumptions before commitment.

Update, October 2026: Commercial RPMs. For commercial facilities NFE has chosen the NFE-owned energy-service model, with reliability included in a utility-matched tariff (no separate reliability fee) and a 50% minimum monthly payment. That differs from the "explicit reliability tier" and "partner-led first" guidance below, which came from the Sezibwa community case. See NFE Commercial Reliable Power Microgrids and the Commercial RPM decision log.

Purpose

NFE Microgrid OS needs a business model that creates durable recurring revenue while improving the economics and reliability of community energy systems. Two ownership models remain viable, but the current Sezibwa evidence suggests a clear sequencing principle: scale first through partner-owned deployments, while using NFE-owned projects selectively where the project return and strategic value justify tying up capital.

The operating system is the common product in both models. Ownership determines who funds the assets, carries performance risk, and receives the energy margin.

Current evidence from Sezibwa

The Sezibwa analysis is not a universal tariff card, but it gives NFE a grounded reference case for product and commercial decisions:

Question	Current finding	Business implication
What should be added to the existing inverter and 8.9 kWh battery?	Solar first. Adding battery at today's price lowers NPV.	The OS should recommend marginal investments based on the assets already installed, not sell a standard hardware bundle.
How much solar?	4 kWp is the low-spill efficiency sweet spot; 5 kWp is the maximum-NPV optimum.	The recommendation depends on the customer's objective: capital efficiency and minimal curtailment versus maximum total value.
What does battery arbitrage contribute?	About 22,000–40,000 UGX/month before fully pricing degradation, depending on backup reserve.	Arbitrage is incremental value from sunk hardware, not the core investment case. Dispatch must exceed marginal degradation cost and preserve the agreed reserve.
When does more storage pay?	At the 5 kWp anchor, the first added unit breaks even around 367,000 UGX/kWh, versus about 626,000 UGX/kWh today.	Treat battery price as a procurement trigger. Additional storage may still be justified separately for outage resilience.
Can surplus solar be sold?	Not assumed in the Sezibwa base case.	Use zero export value until site-specific arrangements are confirmed; show export as a separate upside scenario.

Detailed evidence: Solar Plus Battery Economic Case, Battery Arbitrage Economic Case, Optimal Solar and Battery Allocation, and Battery Price Break-Even.

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1. NFE-owned energy-service model

NFE finances and owns the supported microgrid assets and sells an energy and reliability service to a landlord, estate, community entity, or other contracted counterparty. The exact structure—PPA, lease, energy-service agreement, or another permitted form—must be confirmed against the applicable licensing, tariff, consumer-protection, and metering requirements.

Assets and responsibilities

NFE funds, owns, and operates the contracted system: submeters, solar, batteries where justified, inverters, communications, and the NFE Microgrid OS control and billing layer. NFE carries financing, asset-performance, collections, maintenance, and technology-obsolescence risk.

Revenue and value capture

• Energy-service revenue: contracted charges for electricity supplied or bills avoided, subject to the approved commercial structure.
• Reliability service: an explicit availability or backup tier rather than an assumed premium hidden inside the energy price.
• Operating efficiency: lower losses, better collections, solar self-consumption, reserve-aware dispatch, and tariff-aware control increase project margin.
• Optional services: installation, maintenance, reporting, or financing fees where separately contracted.

Optimization is not revenue by itself. It improves the margin or service quality of a contracted energy product. The commercial model should therefore distinguish customer charges from internally generated savings.

Investment test

Approve an NFE-owned project only when the site-specific model shows acceptable NPV, IRR, downside resilience, and debt-service capacity after turnkey capex, losses, degradation, maintenance, collections, taxes, and financing. At Sezibwa, the attractive next investment is solar on hardware already owned; that result should not be generalized to a greenfield site where inverter and battery costs are not sunk.

Best fit

• High-confidence load and collections data.
• A creditworthy counterparty or enforceable payment mechanism.
• Strong solar self-consumption and limited dependence on unconfirmed export revenue.
• A strategically important reference site or a return high enough to justify NFE capital.

Key tradeoff

This model captures the most project economics and operational learning, but it is capital-intensive and concentrates construction, credit, regulatory, and long-term asset risk on NFE.

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2. Partner-owned managed-platform model

A developer, landlord, estate, community entity, or energy-service partner finances and owns the physical assets. NFE supplies the operating platform, supported controls, deployment services, and ongoing technical operations.

Partner role

The partner funds and owns solar, batteries, submeters, inverters, communications hardware, and other site infrastructure. The partner retains asset-financing risk and receives the energy margin, subject to the commercial agreement.

NFE role

• NFE Microgrid OS licensing and supported device integration.
• Metering, customer accounts, billing, collections data, and settlement reporting.
• Monitoring, alerts, remote operations, and performance reporting.
• Tariff-aware, forecast-aware, reserve-aware, and degradation-aware dispatch.
• Site modelling, investment recommendations, commissioning, and lifecycle support.

NFE revenue

• Deployment fee: site assessment, modelling, integration, commissioning, and training.
• Recurring platform fee: a base site fee plus a usage driver such as connected meters, managed assets, or energy settled.
• Managed-operations fee: optional monitoring, dispatch, incident response, reporting, and maintenance coordination.
• Performance component: only where savings can be baselined and audited; use a share of verified incremental value rather than gross electricity sales.

A pure revenue share is easy to describe but difficult to govern when tariffs, load, collections, outages, and partner capex all change. A fixed recurring fee provides predictable platform revenue; a narrowly defined performance component can align incentives without making NFE responsible for every movement in the partner's electricity income.

Hardware support and maintenance

NFE should publish a supported-hardware list and define responsibility by asset. Partner-owned equipment remains the partner's financial responsibility. NFE may provide maintenance directly or coordinate approved providers under a separate service level. Unsupported third-party assets, including generators, are excluded unless explicitly integrated and contracted.

Key tradeoff

This model produces less revenue per site than ownership but requires much less NFE capital, limits balance-sheet exposure, and can scale faster across heterogeneous sites.

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Common modelling and operating rules

1. Keep tariffs configurable. Store the entire time-of-use schedule, effective dates, fixed charges, taxes, and export credit separately from model logic. Re-run forecasts whenever ERA/UEDCL publishes a revision.
2. Model the actual site. Use interval load, outages, collections, existing assets, weather, and installed quotations. Do not transfer Sezibwa results unchanged to another microgrid.
3. Separate sunk and new capital. Dispatching an owned battery can create incremental value; buying another battery requires a separate investment case.
4. Separate energy and resilience value. Energy NPV should stand on its own. Backup reserve, outage avoidance, and service availability should be quantified and priced explicitly where possible.
5. Use a Sezibwa-specific zero-export-value base case. Add export value only as a documented scenario with confirmed eligibility, interconnection limits, and credit terms.
6. Price degradation at the margin. Arbitrage should run only when avoided tariff cost exceeds conversion losses, marginal battery wear, and the opportunity cost of reducing backup reserve.
7. Treat second-life storage as a hypothesis. Recycled batteries may become attractive, but require a second-life-specific techno-economic model covering acquisition, testing and grading, BMS and pack integration, safety, warranty, heterogeneous health, remaining life, and replacement.

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Strategic recommendation

Situation	Preferred approach
Partner has capital and wants operating capability	Partner-owned managed platform
Site has strong verified economics, reliable collections, and strategic value	Consider NFE ownership after investment committee review
Demonstration or product-learning site	NFE-owned or co-invested, with an explicit learning budget
Economics depend on unconfirmed export revenue or speculative battery pricing	Do not finance on the upside case; validate first

The near-term portfolio should therefore be partner-led and platform-first, with a small number of deliberately selected NFE-owned or co-invested sites. This builds recurring software and operations revenue, expands the data set behind the optimizer, and preserves NFE capital for projects where ownership offers exceptional return or strategic learning.

Decisions and evidence still required

1. Define the minimum recurring platform fee and its pricing driver: site, meter, managed asset, or energy settled.
2. Define a measurable baseline and audit method before offering performance-based fees.
3. Set NFE-owned project hurdle rates, concentration limits, credit requirements, and downside tests.
4. Confirm the permitted contracting and electricity-resale structures for each customer segment.
5. Publish supported hardware, warranty boundaries, maintenance responsibility, and service levels.
6. Build the second-life-specific techno-economic model before presenting recycled batteries as a validated strategy.
7. Turn the current optimizer into a repeatable site proposal that reports energy value, resilience value, capex, financing, NPV, IRR, payback, tariff sensitivity, and export sensitivity separately.

Solar Plus Battery Economic Case (Sezibwa)

Data provenance

Underlying data: the aggregate meter meter_100 plus the 10 customer sub-meters, over 2026-03-19 to 2026-08-10, from the modbus energy-logger archive (sources: pi-direct and nextcloud-import), i.e. the pre- and early-OpenEMS period. Load basis is a conservative 21.3 kWh/day.

Note (2026-08-20): the site has since migrated to OpenEMS, which is now the live source. OpenEMS-sourced daily figures from mid-August show inconsistencies (the aggregate roughly doubled exactly at the source switchover, and on some days the customer-meter sum exceeds the aggregate), so they are treated as a data-quality issue to resolve before use; this analysis stays on the validated archive. Phase assignments reflect the wiring as observed up to about May 2026 and should be re-verified against the current OpenEMS setup if any connections have been changed.

Battery Arbitrage Economic Case (Sezibwa)

Data provenance

Underlying data: the aggregate meter meter_100 plus the 10 customer sub-meters, over 2026-03-19 to 2026-08-10, from the modbus energy-logger archive (sources: pi-direct and nextcloud-import), i.e. the pre- and early-OpenEMS period. Load basis is a conservative 21.3 kWh/day.

Note (2026-08-20): the site has since migrated to OpenEMS, which is now the live source. OpenEMS-sourced daily figures from mid-August show inconsistencies (the aggregate roughly doubled exactly at the source switchover, and on some days the customer-meter sum exceeds the aggregate), so they are treated as a data-quality issue to resolve before use; this analysis stays on the validated archive. Phase assignments reflect the wiring as observed up to about May 2026 and should be re-verified against the current OpenEMS setup if any connections have been changed.

Optimal Solar and Battery Allocation (Sezibwa)

Data provenance

Underlying data: the aggregate meter meter_100 plus the 10 customer sub-meters, over 2026-03-19 to 2026-08-10, from the modbus energy-logger archive (sources: pi-direct and nextcloud-import), i.e. the pre- and early-OpenEMS period. Load basis is a conservative 21.3 kWh/day.

Note (2026-08-20): the site has since migrated to OpenEMS, which is now the live source. OpenEMS-sourced daily figures from mid-August show inconsistencies (the aggregate roughly doubled exactly at the source switchover, and on some days the customer-meter sum exceeds the aggregate), so they are treated as a data-quality issue to resolve before use; this analysis stays on the validated archive. Phase assignments reflect the wiring as observed up to about May 2026 and should be re-verified against the current OpenEMS setup if any connections have been changed.

Battery Price Break-Even (Sezibwa)

Data provenance

Underlying data: the aggregate meter meter_100 plus the 10 customer sub-meters, over 2026-03-19 to 2026-08-10, from the modbus energy-logger archive (sources: pi-direct and nextcloud-import), i.e. the pre- and early-OpenEMS period. Load basis is a conservative 21.3 kWh/day.

Note (2026-08-20): the site has since migrated to OpenEMS, which is now the live source. OpenEMS-sourced daily figures from mid-August show inconsistencies (the aggregate roughly doubled exactly at the source switchover, and on some days the customer-meter sum exceeds the aggregate), so they are treated as a data-quality issue to resolve before use; this analysis stays on the validated archive. Phase assignments reflect the wiring as observed up to about May 2026 and should be re-verified against the current OpenEMS setup if any connections have been changed.

Solar Sizing Re-run, Sept 2026 (600 Wp panels)

This page re-runs the solar sizing from Solar Plus Battery Economic Case (Sezibwa) on three months of live OpenEMS load. It answers one question: is 7 to 8 panels (600 Wp each) still the best PV size for Sezibwa, and does it cut the energy bill in half?

Answer

Yes. With 600 Wp panels:

• 6 panels (3.6 kWp) cut the energy bill by half.
• 7 panels (4.2 kWp) cut it by 55%.
• 8 panels (4.8 kWp) cut it by 58% and give the best 20 year return (highest NPV).

Past about 5 kWp each extra panel adds little. The battery is already full by midday, and without grid export the surplus is wasted.

What changed since August

Input	August model	This re-run
Load data	Modbus logger archive, Mar to Aug 2026	OpenEMS aggregate meter DTSU666 (serial 221123297561), 1 Jul to 28 Sep 2026, 76 days of data
Average load	21.3 kWh/day	25.8 kWh/day
Baseline energy bill	about 374,000 UGX/month	about 454,000 UGX/month
Panel size	kWp only	600 Wp panels

The model code and economics are otherwise unchanged. One correction was made: the daily average now divides by the hours actually covered by data, not the calendar span, so data gaps (for example the site internet outage of 25 to 26 Sep) no longer understate the load.

Cost of an 8 panel install (at cost)

Priced from the Rincol catalogue (August 2026 buy prices), with the railing at 421,000 UGX per 4 panel kit:

Item	Qty	Cost (UGX)
600 Wp mono panel (GS600N-144M) at 320,250	8	2,562,000
Railing kit (4 panels per kit) at 421,000	2	842,000
6 mm2 UV solar cable at 12,000/m	40 m	480,000
PV combiner box (MC4)	1	80,000
DC circuit breaker 20 A	1	25,000
Surge protector (a DC rated one is still to be sourced)	1	35,000
Earthing (rod, clamps, conductor)	1	80,000
MC4 connectors (estimate)	6 pairs	48,000
Labour and transport	1	250,000
Total		4,402,000

Panels and railing are 3.4M, and the rest of the balance of system and labour adds about 1.0M. The inverter (3.84M) and battery (5.57M) are already paid for, so these are the only new costs.

Results (600 Wp panels, no grid export, at cost)

Panels	kWp	Saving per month (UGX)	Bill cut	Solar wasted	Cost (UGX)	Simple payback	IRR	NPV at 15% (UGX)
5	3.0	199,406	44%	4%	3.44M	1.4 yr	69%	10.9M
6	3.6	225,904	50%	10%	3.76M	1.4 yr	71%	12.4M
7	4.2	247,923	55%	16%	4.08M	1.4 yr	72%	13.6M
8	4.8	263,462	58%	22%	4.40M	1.4 yr	71%	14.3M
9	5.4	273,637	60%	28%	5.14M	1.6 yr	63%	14.3M
10	6.0	281,205	62%	33%	5.46M	1.6 yr	61%	14.5M
11	6.6	287,350	63%	38%	5.78M	1.7 yr	59%	14.6M
12	7.2	292,746	64%	42%	6.10M	1.7 yr	56%	14.6M

Cost is built per panel count: panels, one railing kit per 4 panels, and a fixed 40 m of cable, combiner, breaker, surge protector, earthing, connectors and labour. 4 panels is left out because a 4 panel string (about 175 V) is below the inverter's 200 V MPPT minimum. The SRNE ASP48120SH3 has 2 MPPT inputs of up to 9 kW each at 200 to 650 V, so 6 to 14 panels fit on one string. A 5 panel string (about 224 V at 25 °C) drops to about 194 V on hot afternoons, just under the minimum, so the 5 panel row in the table above is optimistic.

For a turnkey quote at Rincol selling prices, add roughly 20 to 25% (the August 7 panel quote was 5.02M at sell prices against 4.16M at cost).

Battery only (the existing SRNE, no panels) saves about 34,000 UGX/month (8%) on the model's arbitrage policy.

How to read it

• Bill cut: the share of the energy bill (energy charges only, excluding the fixed service charge and VAT) that solar plus the existing battery removes.
• Solar wasted: the share of generated solar energy that can't be used or stored, because the battery is full and there is no export.
• Extra per panel: saving rises by about 35,000 UGX/month for the 5th panel, but only about 10,000 UGX for the 9th and under 6,000 by the 12th. The 9th panel also needs a third railing kit.
• NPV at 15%: the 20 year value after paying the install cost. It climbs to 14.3M at 8 panels and then flattens (14.6M at 12). Panels 9 to 12 add about 1.7M of cost for almost no extra value, and IRR is highest at 7 to 8 panels.

Recommendation

Install 8 panels of 600 Wp (4.8 kWp) on the existing SRNE inverter and battery, for about 4.4M UGX at cost. That cuts the energy bill by 58% (about 263,000 UGX/month) and pays back in about 1.4 years. 7 panels (4.1M, 55%) is the cheaper option. Going above 8 only makes sense with grid export (net metering) or more battery storage.

Assumptions and caveats

• Weather is modelled, not measured: 5.2 peak sun hours, 0.78 performance ratio, and a seeded day to day variation. Measured site irradiance would firm this up.
• Tariff is UEDCL Code 10.2 Q3 2026 (off peak 429.7, shoulder 562.1, peak 666.5 UGX/kWh). The Q4 schedule takes effect on 1 Oct and should be checked.
• Capex uses August 2026 Rincol catalogue buy prices and the 421,000 railing kit. The catalogue has no DC rated PV surge protector yet (the 35,000 line is the AC one), so budget more for that. Confirm current prices before buying.
• Load covers July to September only, so there is no seasonal variation.
• Battery use: with solar, the battery is charged from solar and discharged through the shoulder and peak periods. It replaces the current grid arbitrage (off peak charge, 21:30 to 23:30 discharge). A 30% reserve is held for backup.
• Per phase limit: the inverter delivers at most 4 kW per phase on battery (see the 27 Sep outage report). Solar does not change that limit.

Reproduce

The model is versioned in the nfe-modbus-energy-logger repository under scripts/solar_sim/ (issue #89, PR #90, in review). From the repo root:

python3 scripts/solar_sim/sweep_bom.py scripts/solar_sim/m100_openems.csv
python3 scripts/solar_sim/nfe_solar_model.py scripts/solar_sim/m100_openems.csv

m100_openems.csv holds the site aggregate energy in 15 minute steps (site totals only, no per customer data).

Sezibwa solar purchase: final Muden quote (19 Oct 2026)

Sezibwa (Nansana) solar purchase: final quote, 19 Oct 2026

The final proforma invoice from Muden Systems for the 8-panel string, as sent in the "NFE Nansana panel installation" WhatsApp group on 19 Oct 2026. The PDF is attached to this page. The design is in Solar Sizing Re-run, Sept 2026 and the discussion is in the Element solar thread (business room, "Sezibwa solar: where we are").

Quote: MS/SOLAR/10-26, dated 19 Oct 2026, addressed to Nearly Free Energy, valid 15 days or while stock lasts. Delivery to Nansana.

#	Item	Qty	Unit price (UGX)	Amount (UGX)	Warranty
1	Delivery cost	1	100,000	100,000
2	600 W monocrystalline panel	8	370,000	2,960,000	10 years
3	Aluminium rail 5100 mm	4	140,000	560,000
4	End clamp	8	7,000	56,000
5	Inter clamp	12	8,000	96,000
6	L-feet	12	12,000	144,000
7	32 A 4-pole DC isolator	1	320,000	320,000
8	1000 V DC surge protector	1	110,000	110,000
9	MC4 connector	4	15,000	60,000
	Sub total			4,406,000

The invoice's grand total is UGX 4,406,000. The lines add up correctly.

Not on the invoice

• PV cable. The earlier quote (4,426,000) included 30 m of 6 mm² cable at 360,000. This one does not, so the cable is bought separately (the 4 mm² cable was out of stock).
• Installation labour. The line is blank (labour via Green Volta, separate).
• VAT. The 18% line is blank, so VAT on the invoice is not shown.

Changes from the earlier quote (7 Oct)

• The 2-pole 32 A 500 V DC breaker (80,000) became a 32 A 4-pole DC isolator (320,000). For a single string of 8 panels (Voc about 422 V, about 437 V cold) a 2-pole device rated for the voltage is normally enough; a 4-pole isolator is often wired as two poles in series for extra breaking capacity. Worth confirming what was intended.
• The 1000 V surge protector (150,000 earlier) is now 110,000.
• Delivery is a separate line (100,000).

Terms (from the invoice)

• Warranty: 10 years on panels; 1 year manufacturing defect warranty on the rest, on a back-to-base basis. No warranty against misuse, surges or acts of God.
• Title of goods stays with Muden Systems until fully paid.
• Validity: 15 days or until stock runs out.

To do on delivery

• Check every line against this table, including panel count and rating.
• Take photos of labels (panel model, serials) for the warranty record.
• Confirm cable, labour and VAT with the supplier and the installer.

Market Intelligence

Opinions on what causes Power Outages

We are sending out to this form to Ugandans in Urban areas to collect general opinions on what is causing power outages in Urban Communities

https://nextcloud.nearlyfreeenergy.com/apps/forms/s/SaPBZqB6DMetHXs6REMDwPTF

AES: From Backup to Backbone: Community Microgrids to boost National Grid Reliability

Africa has made significant progress expanding electricity access, yet a growing challenge is emerging: reliability. Millions of households and businesses remain connected to national grids that experience frequent outages, disrupting economic activity, education, healthcare, and daily life. In response, many consumers rely on costly and fragmented backup solutions such as diesel generators, batteries, and standalone solar systems.

This paper presents a community microgrid model for urban and peri-urban communities connected to unreliable national grids. Rather than replacing the utility grid, the model leverages shared solar and battery infrastructure to improve reliability, reduce costs, and strengthen local energy resilience. Communities begin by monitoring electricity consumption and outage patterns, then progressively deploy distributed energy resources (DERs) that evolve from backup systems into primary community energy infrastructure.

Drawing on lessons from a pilot deployment in Uganda, the paper examines the technical, economic, governance, and regulatory considerations required to implement community-owned microgrids at scale. Particular attention is given to cooperative ownership, affordability, grid integration, and digital platforms for managing DERs. The paper further explores how community microgrids can reduce peak demand on local transformers and substations, improving network performance and reliability for both participating and neighboring customers.

The paper argues that community microgrids can complement national electrification efforts while supporting utility networks. It also examines policy and regulatory frameworks that could enable wider deployment of community-scale microgrids and unlock private and community investment in local energy infrastructure.

Potential Customers

Prospects now live in ERPNext. Since 5 November 2026, NFE tracks prospective customers in the ERPNext CRM: Opportunities (the pipeline, by sales stage), Prospects (organisations) and Leads (people). Add and update prospects there; Aaron, Dansturn and Hillary have access. The table below is the list as it stood on 5 November 2026. Sezibwa Homes (an operating customer) and Arkright Estates were not carried over. How we use it: Tracking prospects in ERPNext CRM.

Name	Size	Customer Contact	NFE  Contact	Phase
Sezibwa Homes	10 bungalows	Samuel Kisakye	Aaron Tushabe	Phase 1 operations
Pearl Marina - Bellavista Apartments	360 apartments ( 1 MW)	Bellavista HOA	Aaron Tushabe	Proposal. Sawa Energy has also proposed a lease-to-own system (benchmark)
Arkright Estates	26 bungalows	TBD	Aaron Tushabe	Discovery
Bugolobi Flats	Over 300 apartments	TBD	Aaron Tushabe	Discovery
Wandera Homes	13 households	Nimrod Wandera	Aaron Tushabe	Discovery
Ntinda Flats	30 apartments	John W. Matovu	Aaron Tushabe	Discovery
Innocent's Appartments (Serena heights owner)	35 apartments	Davi Mute	Hillary Arinda	Discovery
Worship Harvest	Commercial facility, ~6.9 MWh/month (Commercial RPM)	Via Dansturn Kimbowa	Aaron Tushabe	Proposal (sent 6 Oct 2026)
Kampala Club	Members' club, Plot 8 Ternan Avenue, Nakasero. Grid plus generator today; consumption not yet known (Commercial RPM)	Michael Wamuwaya (GM); Lauben Ahimbisibwe (Hon. Secretary)	Aaron Tushabe; Dansturn Kimbowa (on site)	Discovery: intro email sent 5 Nov 2026 (Aaron is a member); meeting requested for Fri 6 Nov, 11:00 at the Club

Macro outlook: shilling, rates and NFE (15 Oct 2026)

Macro outlook: shilling, interest rates and NFE (15 Oct 2026)

Asked by Aaron in the NFE leads chat. Facts are from public reporting found on 15 Oct 2026 (links at the end). Where sources disagree or I could not confirm, it is marked UNVERIFIED. NFE's own cost and funding numbers are not all known to this note; the "what we need" list at the end says which.

What happened

• 14 Oct, special MPC meeting: Bank of Uganda raised the Central Bank Rate from 9.75% to 12% (+225 bp), the first move after eight holds. (Aaron's chat said 9.5%; the reports say 9.75%.) Reasons given: shilling down about 12% this year, higher oil prices, strong dollar demand from fuel importers, foreign investors leaving government bonds.
• Shilling: weakest in 33 years, about 4,143 to 4,153 per US dollar on 12 to 13 Oct. It reportedly strengthened more than 2% after the decision, but the reports give different levels (UNVERIFIED which is right). It passed 4,000 on 5 Oct.
• Inflation: headline 3.7% (June); energy, fuel and utilities 11.9% year on year, diesel up 37%. BoU now expects headline inflation to average 7 to 7.5% over the next 12 months (core 5.5 to 6%) and cut 2026/27 growth to 6 to 6.5%.
• Credit: the cash reserve requirement rose from 11% to 13.5% on 24 Sep, so banks have less to lend. In August, shilling loans averaged 17.9% and foreign-currency loans 7.5% (before the hike). Post-hike lending rates: not found.
• Electricity tariffs (ERA): Q4 2026 (Oct to Dec) appears unchanged from Q3 (domestic 779.4 UGX/kWh above the lifeline band, commercial 562.1). UNVERIFIED against the ERA PDF. ERA cited a 4.22% shilling depreciation when it held Q3.

How it reaches NFE

Channel	Direction	Why
Hardware (inverters, batteries, panels, meters, Pis)	Cost up	Priced off the dollar. Local quotes follow the shilling within weeks.
Solar quote (Mudde, UGX 4,426,000 materials)	Cost up	About USD 1,067 at 4,150. See table below.
Customer tariff in MGM	Lagged support	MGM bands mirror ERA's domestic tariff (250 / 779.4 / 412 / 779.4 UGX/kWh, UGX 7,320 service charge, 18% VAT). ERA reviews quarterly and has named the exchange rate as an input, so retail prices follow the dollar with about one quarter of delay.
Arbitrage (peak 666.5 vs off-peak 429.7 UGX/kWh, Code 10.2)	Mild support	The saving is set in shillings, so it grows only if ERA raises tariffs. Today about 189 UGX per shifted kWh, roughly UGX 35,000 a month on one site at 6 kWh a night. Small against hardware costs.
Borrowing	Cost up	CBR at 12% points to higher shilling loan rates (assumption: not yet seen). Dollar loans look cheaper (7.5%) but turn expensive if the shilling keeps falling.
Customers (Sezibwa households)	Risk	Fuel and food inflation cuts what households can spend; September's pilot bill was UGX 552,197 for 8 households, so a few late payers matter.
Cloud and SaaS (Hetzner in EUR, Claude Team, API credits)	Cost up, small	Charged in foreign currency. The Claude credits (USD 1,000) and any USD grant gain value in shillings.
Grid reliability	Possible risk	Fuel cost and import pressure can strain UEDCL. Our 20:00 to 22:30 L3 sag pattern is already grid-side.

Sensitivity: the Mudde solar materials quote (UGX 4,426,000 at 4,150/USD)

UGX per USD	Materials cost (UGX)	Change
3,950	4,212,700	-5%
4,150	4,426,000	base
4,500	4,799,300	+8%
4,800	5,119,200	+16%
5,000	5,332,500	+20%

The quote is valid to about 22 Oct. Labour is extra and local (Green Volta).

What I would do

1. Decide the solar order before the quote lapses (about 22 Oct) or ask Mudde to hold the price in writing. Every 5% shilling move is about UGX 220,000 on materials.
2. Buy hardware earlier rather than later for anything already planned (spare meters, Pis, a second inverter), while the shilling is firmer after the hike.
3. Keep any USD funding in USD (grant, credits) until a shilling cost needs paying.
4. Keep customer tariffs on the ERA bands and re-read the ERA schedule every quarter (next: the Q1 2027 schedule, due about the end of December).
5. Avoid new shilling debt at the current rates unless the project pays back well inside a year; compare with a dollar-linked option only if income is dollar-linked.
6. Watch the cash side of billing: track unpaid bills in MGM monthly, because households are the first to feel inflation.

What we need to finish this properly

• The next hardware order (items, supplier currency, timing) and any quotes in USD.
• How the grant (about USD 3,000) is held and when it is spent.
• Any loan or financing plan for the next site.
• Whether solar panels, inverters and batteries now carry import duty or VAT: not found in the 2026/27 budget reports (UNVERIFIED). Check URA and EAC tariff lines 8541, 8504 and 8507.
• Post-hike commercial lending rates (next BoU Financial Stability or bank rate releases).

Sources

• Pulse Uganda: Bank of Uganda raises CBR to 12% (14 Oct 2026)
• bne IntelliNews: Uganda central bank raises rate to 12% at emergency meeting as shilling hits record lows
• Investing.com: Uganda central bank raises rates to 12% to support shilling
• UBC: Bank of Uganda raises interest rate to 12% as inflation and shilling pressures mount (14 Oct 2026)
• Pulse Uganda: Uganda shilling falls to lowest level in 33 years
• UG Business: Bank lending grows at its fastest rate since 2015
• Monitor: High fuel prices push Uganda's inflation to 3.7 per cent
• ERA: Approves electricity tariffs for the third quarter of 2026; Monitor and Watchdog Uganda on Q4 2026 tariffs
• KPMG and Forvis Mazars: Uganda Budget Brief 2026/27

Sawa Energy's Bellavista proposal (competitor benchmark)

What Sawa Energy offered Bellavista Apartments (Pearl Marina) for solar and storage, and what NFE took from it for the Commercial RPM. Bellavista is also in NFE's pipeline (see Potential Customers). Based on Sawa's proposal document "Bellavista (576kW) Proposal_Lease to Own_Battery", reviewed 18 Sep 2026. Owner: Aaron Tushabe.

Sawa's offer

Item	Sawa's Bellavista proposal
Solar	576 kWp
Battery	691 kWh (about 2 hours)
Ground area	3,200 m²
Stated system value	UGX 4.762 billion
Upfront cost to the customer	None
Monthly lease	USD 17,038 (operating lease USD 13,068 + O&M USD 3,970)
Term	25 years
Security deposit	3 months (USD 51,113)
Ownership	Optional purchase from year 3 at a declining, predefined price; transfer for USD 1 after 25 years
Share of consumption covered	43% overall; 85% of daytime consumption
Included	Monitoring, maintenance, insurance, warranty management, panel washing and repairs, with inverter replacement about every 7 years and battery replacement about every 10 years ("set it and forget it")
Sizing	Subject to validation by logging actual consumption

The lease comes to about USD 204,000 a year, or about USD 5.1m over 25 years before escalation or discounting. Bellavista pays it whether it uses a little electricity or a lot.

How it compares with a Commercial RPM

	Sawa (lease-to-own)	NFE Commercial RPM
Customer pays for	Equipment: a fixed monthly lease	Electricity used, per kWh at the utility tariff, with a 50% minimum
Who carries volume risk	The customer	Mostly NFE, above the 50% floor
Reliability	Comes with the equipment	Part of the service and included in the price
Proposal is built around	The asset (kWp, kWh, system value)	The service (the power stays on at the same price)
Capital	The full system up front	In phases: measure first, then build what the data supports
Ownership	From year 3; USD 1 at year 25	Optional purchase from year 5

What NFE adopted

• "Set it and forget it" risk allocation. NFE owns, monitors, maintains, repairs, insures and replaces the equipment for as long as it runs the system, all covered by the energy price.
• A predefined buyout schedule agreed at signing, so the customer always has a path to ownership at a known price.
• An onboarding sequence: data logging → credit assessment → site assessment → final design → contract → deployment. Sawa asks for corporate documents, utility bills or audited statements, credit references and site or roof information.

What NFE does differently, on purpose

• Bills for energy, not for equipment.
• Leads proposals with the service, with the hardware list secondary.
• Deploys capital in phases as consumption is proven, rather than financing the whole system on day one.

Related: NFE Commercial Reliable Power Microgrids · Commercial RPM decision log

UMEME → UEDCL transition: market impact

Summary

UEDCL (government-owned) has taken over national electricity distribution from UMEME (private). Since then, people have been complaining publicly about a sharp drop in service. This page records what we know and what it means for NFE.

What's being said

A widely read X post by Ronald Amanyire (19 Oct 2026, ~12.8K views) argues that the decline comes from incentives and institutional culture, not infrastructure. In his view a state entity has less pressure to perform, and patronage and weak teamwork make it worse. He also points out that UEDCL's remote service areas were already struggling before the handover. His conclusion is that customers judge a distributor only on reliability. Source

What it means for NFE

• Grid reliability is a live concern for customers, so energy independence and backup power are timely conversations.
• The strongest prospects are commercial and institutional customers on the main grid: health, cold chain, hospitality, manufacturing, telecom/offices and schools.
• Pitch reliability and fault response, not just equipment.
• Remote and off-grid sites support mini-grid and standalone system work.

Caveats

This is based on opinion, not outage data. Add ERA/UEDCL figures and customer evidence here as we collect them.

Related: Business Development project doc "UEDCL transition lead segments" (lead log).

Owner: Aaron Tushabe · Last reviewed: 28 Oct 2026

Tracking prospects in ERPNext CRM

Since 5 November 2026, NFE tracks prospective customers in ERPNext's CRM, not in the Library's Potential Customers table. This page explains how we record a prospect, which sales stage and probability to use, and how to keep the pipeline current. Owner: Aaron Tushabe.

Where to look

• The pipeline: Opportunities, one per deal, with its stage, probability and owner.
• Organisations: Prospects. People: Leads.
• Reports: Sales Pipeline Analytics and Opportunity Summary by Sales Stage. Both count Opportunities only, which is why every prospect gets one.

Access: Aaron, Dansturn and Hillary have Sales User and Sales Manager (granted 5 November 2026; see the ERPNext access review addendum). Anyone else who needs the CRM asks Aaron.

How we record a prospect

ERPNext record	What it holds	Example
Prospect	The organisation or site. One per prospective customer	Example Heights Apartments
Lead	A named person there, added to the Prospect's Leads table	Jane Example (Property Manager)
Contact	Made automatically from each Lead	Jane Example
Opportunity	The deal, raised from the Prospect	CRM-OPP-2026-NNNNN

Adding a new prospect

1. Prospect. Give the organisation name, Customer Group (Commercial; Non Profit for churches and NGOs; Government), Territory Uganda, Industry (Real Estate for housing), and Prospect Owner, the NFE person leading it. On the Notes tab, add the size (apartments, households or MWh/month), how we met them, and a link to any Library page.
2. Leads. Make a Lead for each named person (first and last name, organisation, job title, Lead Owner), then add it to the Prospect's Leads table. Skip this step until you have a name.
3. Opportunity. On the Prospect, use Create → Opportunity. Set Opportunity Type Sales, the Sales Stage and Probability from the table below, the Opportunity Owner, and the Contact Person if there is one. Add the amount and expected closing date once you know them.

Always set Probability. A new Opportunity starts at 100%, which inflates the pipeline.

Claude can do all three steps with the erpnext-api skill, using your own key, so you show as the owner (see Using ERPNext with Claude). Don't create CRM records through mcphub, which records them as Administrator's.

Sales stages and probabilities

Where the deal is	Sales Stage	Probability
We know of the site but haven't reached anyone yet	Prospecting	10%
In conversation with a named contact; screening the site (for Commercial RPMs, see Assessing a Commercial RPM lead)	Qualification	20%
Proposal sent	Proposal/Price Quote	40%
Negotiating terms	Negotiation/Review	60%

We don't use ERPNext's other stages (Needs Analysis, Value Proposition, Identifying Decision Makers, Perception Analysis).

Keeping it current

• After every meeting, call or email that moves a deal: add a note on the Opportunity's Notes tab, and update its Sales Stage and Probability.
• Leave Status at Open while a deal is live. ERPNext closes Opportunities left at Replied for 15 days (CRM Settings).
• Lost: set Status to Lost. ERPNext asks for a reason, and the list starts empty, so add one if none fits (for example "Chose a competitor").
• Paused: use Close on the Opportunity, and Reopen when talks restart.
• Won: tell Aaron. We haven't yet decided how a won deal becomes an ERPNext Customer, since NFE's customers aren't in ERPNext yet.
• Keep the long-form story (site details, economics, history) on the customer's Library page, as for Worship Harvest, and link it from the Prospect's notes.

Not in the CRM

• Sezibwa Homes is an operating customer, not a prospect.
• Arkright Estates was left out when the list moved to ERPNext on 5 November 2026.

Last reviewed 5 November 2026 by Aaron Tushabe.

Commercial RPMs

NFE Commercial Reliable Power Microgrids

Summary page, current as of 21 October 2026. Owner: Aaron Tushabe. The detail lives in the pages linked below. The 18 Sep "Team Review Pack v0.1" this page used to hold is in its revision history.

What it is

A Commercial Reliable Power Microgrid (RPM) is NFE's Energy as a Service offer for commercial facilities. NFE designs, finances, installs, owns and operates the battery, inverter, solar, metering and controls behind the facility's power supply. The customer buys electricity per kWh at the applicable ERA Code 10.2 time-of-use tariff, the same rate it pays UEDCL, with reliability included and no equipment to buy. It can choose to buy the system from year 5.

NFE adds no premium for reliability. Its return comes from solar: kWh that NFE's panels supply directly in the daytime, and solar stored in the battery for the 18:00–24:00 peak, replace grid electricity NFE would otherwise buy at the same tariff it sells at.

The offer: current terms (set 6 Oct 2026)

These were agreed for the Worship Harvest proposal and are the model the funders' pitch describes.

Term	Position
Energy price	The applicable ERA Code 10.2 time-of-use tariff per kWh. Applicable taxes are shown separately.
Reliability	Included in the energy price. No separate reliability fee.
Upfront cost to the customer	None. NFE funds and owns the equipment.
Minimum monthly payment	From commissioning, the greater of the actual metered energy charge or 50% of the reference monthly energy charge agreed after Phase 1. It replaces a lower bill and is never added on top. Service-performance credits apply if NFE fails to deliver.
Utility account	NFE prefers to manage and pay the customer's UEDCL bill and issue one consolidated energy bill. The customer decides during Phase 1. Formal transfer of the account only if needed.
Regulatory approval	ERA certificate of registration for the microgrid.
Ownership	Optional purchase from year 5 ("Ownership stage"), subject to agreed terms.
Not yet standard	Contract term (15 years in the first proposal), deposit, SLA wording, tariff indexation and early termination. See the open questions below.

Why each term was chosen: Commercial RPM decision log.

Who it is for

Monthly consumption	Fit	What to do
Below ~1.5 MWh	Below the preliminary economic threshold	Generally outside the target
1.5–2 MWh	Marginal	Assess selectively
2–3 MWh	Meets the screening threshold	Target for assessment
3 MWh and above	Stronger candidate	Prioritise

Beyond volume, good candidates use most of their electricity in the day and evening (shoulder and peak periods), pay their utility bills reliably, and have roof or ground space for solar. Typical targets: churches, schools, clinics, hotels, offices, supermarkets and small factories. Facilities that run generators for reliability are especially good fits, because replacing the diesel adds to the customer's savings.

How to screen, size and check the margin on a lead: Assessing a Commercial RPM lead.

How a Commercial RPM is delivered

Phase	What happens	Typical timing
1. Measure & Manage	NFE submeters the facility at 15-minute intervals or finer, ideally after the grid/generator changeover so generator-supplied load is captured. We learn peak demand, evening, Sunday and event loads, outages and generator use, and agree the reference monthly energy charge. The customer decides whether NFE takes over the UEDCL bill.	Usually 3 months
2. Reliable Power	NFE installs the battery, the inverter, enough solar to pay for the reliability, and its metering and Microgrid Manager platform. Energy billing and the minimum payment start at commissioning.	Installation 3–6 months after the load and outage profiles are confirmed
3. Energy Optimization	NFE adds solar or storage and tunes dispatch as demand and outages change, so the grid and generator become secondary sources.	Ongoing
4. Ownership (optional)	The customer may buy the system from year 5 at a buyout set in the contract. The price must at least clear any outstanding project debt.	From year 5

These phases adapt NFE's Microgrid Cultivation Blueprint for commercial customers. In customer documents, call phase 4 the "Ownership stage" so it isn't confused with step 4 ("Install and commission") of the delivery plan.

Why the economics work

• Commercial Phase 2 is a right-sized battery for reliability plus enough solar to pay for it. Solar isn't needed to get through an evening outage, but at tariff parity NFE earns little on grid electricity it simply passes through. Solar is what funds the reliability.
• The battery works every day. Solar charges it in the daytime and it supplies the 18:00–24:00 peak (UGX 666.5/kWh). If the grid fails in the evening, the battery keeps doing what it was already doing.
• Worship Harvest base case (6.9 MWh/month; 120 kWh battery, 50 kW inverter, 40 kWp solar): about UGX 34.8m a year of grid purchases avoided, about UGX 24.5m a year of cash flow after maintenance, admin and a battery and inverter replacement reserve, and about a 15% project return over 15 years. CAPEX is a range of UGX 120–145m until we have EPC quotes. Worship Harvest is one of the larger sites we expect to build; most commercial sites are planned at 30–80 kWh of battery.
• Financing works with shilling debt at 12% or less over 10 years or more (debt service cover of about 1.6–1.9x). Ordinary commercial bank debt at 18–19% does not work well. Target concessional or climate finance, and later a portfolio vehicle (SPV).

Assumptions, sensitivities and financing structures: Commercial RPM economics and bankability.

Where things stand (21 Oct 2026)

• Worship Harvest, the first commercial customer: the proposal (with the company profile) and a one-page summary for their leadership went out on 6 Oct. Next step: Worship Harvest agrees to start Phase 1. See Worship Harvest.
• Website: the Products section presents Residential RPMs (50–500 residents) and Commercial RPMs (at least 2 MWh/month) under "Energy as a Service, not another equipment project" (since 1 Oct).
• Strategy: NFE plans to build more commercial than residential microgrids (2 Oct). The Roadmap doesn't show this yet.
• Funders' pitch: a revision presenting Commercial RPMs as the near-term expansion priority alongside Residential RPMs is in draft (v0.1, 21 Oct). The provisional raise is US$500,000 to target ten new RPMs over about 18 months, seven commercial and three residential (Funding target). Deployment milestones still need settling before the web page changes.
• Competition: Sawa Energy sells lease-to-own solar and storage. See Sawa Energy's Bellavista proposal.

Open questions

1. Reliability promise. Hours of backup, availability %, or both? What the SLA covers and how service credits work.
2. Tariff mirroring. Which UEDCL charges we mirror (fixed or service charges, VAT) and how tariff changes flow through to the customer.
3. Hardware. Commercial customers and EPCs may expect SMA- or BYD-class equipment (Hillary, 12 Sep). Our CAPEX benchmarks use budget-brand retail prices, so we need a C&I hardware scenario.
4. Thresholds. The 1.5 and 2 MWh/month thresholds came from the first, lighter model. Re-run them with the bankability model's replacement reserve and the 50% minimum payment.
5. Financing. Which lenders (for example UDB's climate finance facility), how much debt on early projects, and when to set up a project or portfolio SPV. Shilling borrowing is likely to get dearer after the 14 Oct rate rise (Macro outlook).
6. Standard term sheet. Deposit, early termination payment, site access, insurance and the year-5 buyout method.
7. A shared model. The calculations so far live in a ChatGPT conversation. Build a spreadsheet the team can use and check.

Related pages

• Commercial RPM decision log
• Assessing a Commercial RPM lead
• Commercial RPM economics and bankability
• Worship Harvest (Commercial RPM customer #1)
• NFE Commercial RPM Finance Glossary
• Sawa Energy's Bellavista proposal (benchmark)
• Funding target: ten Reliable Power Microgrids (Oct 2026)
• Business Models for the NFE Microgrid OS
• Team discussions: NFE checkin 12/09/2026 and NFE Checkin 18/09/2026

Source: Aaron's ChatGPT working session "Commercial RPM Modeling" (18 Sep–21 Oct 2026) and the check-ins above. Last reviewed 21 October 2026 by Aaron Tushabe.

Commercial RPM decision log

Decisions about the Commercial RPM model, newest first. When the team decides something, add a row at the top. Don't rewrite old rows: if a decision changes, add a new row and say which one it replaces. Current terms in one place: NFE Commercial Reliable Power Microgrids. Owner: Aaron Tushabe.

Date	Decision	Why	Who / where
21 Oct 2026	Fundraising target (provisional): US$500,000 of total programme capital to target ten new RPMs over about 18 months: seven Commercial and three Residential (70% commercial, within the 60–80% range). US$550,000 if we want room for a fourth residential site. Replaces the US$650,000 working estimate from earlier the same evening.	Sized to deploy about ten microgrids with a commercial majority. The first estimate used Worship Harvest's scale for every commercial site.	Aaron set the scope; budget worked up in his ChatGPT session. See Funding target
21 Oct 2026	Planning assumption: Worship Harvest (~120 kWh) is one of the larger Commercial RPMs, not the typical size. Budget most commercial sites as smaller (30–40 kWh, ~US$15,000 installed) or medium (60–80 kWh, ~US$25,000).	Aaron's expectation of the commercial pipeline.	Aaron
21 Oct 2026	The funders' pitch will present Commercial RPMs as NFE's near-term expansion priority alongside Residential RPMs, with Worship Harvest kept anonymous. Draft v0.1 is in review. The web page stays unchanged until the fundraising amount and deployment milestones are set.	NFE's growth plan has shifted toward commercial customers.	Aaron
6 Oct 2026	Price: ERA Code 10.2 time-of-use tariffs, with applicable taxes shown separately. Reliability is included; no separate reliability fee.	"Reliability baked in" is the pitch. A fee would change the offer.	Aaron, after a teammate's review of the Worship Harvest proposal
6 Oct 2026	Minimum monthly payment: from commissioning, the customer pays the greater of the actual metered energy charge or 50% of the reference monthly energy charge agreed after Phase 1 submetering. The baseline kWh is fixed in the contract and tariff changes adjust its value. It replaces a lower bill and is never added on top. Service-performance credits apply if NFE fails to deliver. Replaces "no hard minimum" (18 Sep).	Pure pay-as-you-use left NFE with all the volume risk for 15 years. A 50% floor gives lenders some revenue protection, while the customer's use can fall a long way before it applies.	Aaron
6 Oct 2026	Utility account: NFE prefers to manage and pay the customer's UEDCL bill and issue one consolidated energy bill. The customer decides during Phase 1. Formal account transfer only if needed. If the customer keeps paying UEDCL directly, agree a reconciliation so they aren't charged twice.	One bill is simpler for the customer, and NFE has to be the billing layer to capture the solar margin.	Aaron
6 Oct 2026	Approvals: the ERA requirement is a certificate of registration for the microgrid. Replaces the broader "confirm licensing, registration or exemption" wording.	Sets out the one approval NFE needs.	Aaron
6 Oct 2026	Ownership wording: customer documents say "Optional purchase from year 5 (Ownership stage), subject to agreed terms", not "Phase 4".	"Phase 4" clashed with step 4 ("Install and commission") of the delivery plan.	Aaron, on a teammate's suggestion
6 Oct 2026	Savings illustrations use the customer's historical weighted Code 10.2 tariff (Worship Harvest: UGX 567.1/kWh) plus assumed 18% VAT (UGX 669.2/kWh). The UGX 800/kWh figure is dropped. Sunday demand will come from Phase 1 submetering.	The proposal priced energy at the tariff but illustrated savings at UGX 800, which nothing explained.	Aaron, after a teammate's review
2 Oct 2026	NFE's roadmap will include more commercial than residential microgrids.	—	Aaron
2 Oct 2026	Phase 1 (load and outage monitoring) normally lasts 3 months. Installation follows 3–6 months after the load and outage profiles are confirmed.	Size each microgrid from measured data.	Aaron
2 Oct 2026	NFE's platform is called Microgrid Manager in all documents, not MicroPowerManager.	NFE now uses Microgrid Manager.	Aaron
1 Oct 2026	The website Products section shows two products: Residential RPM (50–500 residents) and Commercial RPM (at least 2 MWh/month). Customer-facing pages leave out internal economics and financing. Headline: "Energy as a Service, not another equipment project".	Prospects need to know whether they fit and what to prepare before contacting us.	Aaron
19 Sep 2026	Pursue Worship Harvest, but treat the financial and engineering figures as unvalidated until reviewed. Peak demand is the biggest gap: meter after the grid/generator changeover, capture generator and event loads, and add avoided diesel to the model.	Worship Harvest runs a 200 kVA generator on Sundays and for events, so its bills understate both demand and the value at stake.	Team, check-in
18–19 Sep 2026	Screen commercial leads at ≥2 MWh/month (≥3 MWh is stronger). Preliminary.	Modelled break-even was about 1.5 MWh/month; 2 MWh leaves room for downside cases.	Aaron's model; team check-in
18 Sep 2026	Commercial Phase 2 = a battery for reliability + enough solar to finance it.	At tariff parity, solar is what pays for the reliability.	Aaron's model; confirmed at the 19 Sep check-in
18 Sep 2026	Fund the battery and inverter replacement reserve explicitly in the model (lenders won't accept a generic % of CAPEX). Present Worship Harvest CAPEX as a range (UGX 120–145m; UGX 140m in the model), not as "UGX 143m".	UGX 143m was a conservative modelling number, not a quote.	Aaron
18 Sep 2026	Commercial RPMs keep NFE's Energy as a Service model: per-kWh billing at utility-tariff parity, NFE owns and runs the equipment, four phases with an ownership option. Not an equipment lease like Sawa's, but borrow Sawa's "set it and forget it" risk allocation and predefined buyout.	Keeps the offer simple: pay for power, not power equipment.	Aaron
12 Sep 2026	Explore a commercial/industrial model as an adjacent opportunity, without distracting from the residential/community strategy. Superseded by the 2 Oct shift toward commercial.	A business with a predictable UGX 4–5m monthly bill could fund a system from its existing energy spend.	Team, check-in

Source: Aaron's ChatGPT working session "Commercial RPM Modeling" (18 Sep–21 Oct 2026) and the linked check-ins.

Assessing a Commercial RPM lead

How to decide whether a commercial facility is worth a Phase 1 proposal, and how to do a first-pass Phase 2 sizing and margin check from its utility bills. The results are screening estimates, not quotes. Worked example: Worship Harvest. Owner: Aaron Tushabe.

1. Ask the prospect for

• Utility bills for the last 12 months (at least 4), showing kWh by time-of-use period. UEDCL commercial bills split peak (18:00–24:00), shoulder and off-peak.
• An account statement or payment history for the same months
• Operating hours, including evenings, weekends and events
• Critical loads that must stay on in an outage, and how outages affect them today
• Generators: size, when they run, and monthly fuel and maintenance spend
• Roof or ground space for solar, and who owns the premises (a landlord would have to agree)
• Peak demand in kW or kVA, if they know it
• Who decides, and who signs

The website lists the same items under "Before you reach out", so many prospects will already have them.

2. Screen

Check	Pass	Worship Harvest
Monthly consumption	≥2 MWh/month (≥3 is stronger; 1.5–2 is marginal)	~6.9 MWh
Load shape	Most kWh in shoulder and peak periods, when solar and storage can serve them	81% shoulder + peak
Payment record	Bills cleared within each billing cycle	Cleared every month, June–August
Site	Space for the solar; ownership of the premises clear	Owns its premises
Extra value	Generators run for reliability (diesel the RPM can replace)	200 kVA generator all day on Sundays

A facility that uses most of its electricity at night is a weaker fit even at high volumes, because solar can only reach that load through a much bigger battery.

3. Read the load from the bills

1. For each bill, note peak, shoulder and off-peak kWh. Average them to a typical month and work out each period's share.
2. Weighted tariff = (peak kWh × peak rate + shoulder kWh × shoulder rate + off-peak kWh × off-peak rate) ÷ total kWh
3. NFE energy revenue at tariff parity = the same sum per month, before VAT
4. If recent bills or payments are rising, run a second case at the recent level.

Code 10.2 rates used so far (Q3 2026, before VAT): peak UGX 666.5/kWh, shoulder 562.1, off-peak 429.7. ERA reviews tariffs every quarter, so check the current schedule before each proposal.

4. First-pass Phase 2 sizing

Evening energy (E) = peak-period kWh per month ÷ 30. This is what the battery must cover for six hours from 18:00.

Battery, nominal kWh = E × 1.15 ÷ (0.90 × 0.95) ≈ E × 1.35 (15% reliability reserve, 90% usable depth of discharge, 95% inverter efficiency)

Inverter, kW. Bills show energy, not instantaneous demand. Allow generous headroom over the average evening load (E ÷ 6 hours), check against large motor loads and the size of any generator, and confirm the real peak kW in Phase 1 before buying.

Solar, kWp. Enough to charge the battery for the evening peak and serve daytime load directly, without counting on export. Estimate output at 1,500 kWh per kWp per year (conservative for Uganda).

• Solar needed to supply the peak through the battery ≈ annual peak kWh ÷ 0.90 (round-trip efficiency)
• The rest of the solar output offsets shoulder kWh directly, up to the facility's shoulder consumption
• Solar beyond what peak + shoulder demand can absorb needs export arrangements or load growth

5. Check the margin

1. Avoided grid purchases per year = (peak kWh supplied from the battery × peak rate) + (solar kWh used directly × shoulder rate)
2. Cash flow (CFADS) = avoided grid purchases − routine O&M (~1.5% of CAPEX) − NFE monitoring, billing and admin (UGX 1.2m per site) − battery and inverter replacement reserve (~5% of CAPEX in the Worship Harvest case)
3. RPM margin per kWh = CFADS ÷ the customer's annual kWh
4. Capital recovery needed per year = CAPEX × r ÷ (1 − (1 + r)^−n). At NFE's 15% target over 15 years the factor is 0.171. CFADS should at least match it, with room to spare.

In Sep 2026, a 120 kWh / 50 kW / 36–40 kWp system cost an estimated UGX 120–145m on budget-brand retail prices. Benchmarks and caveats: Commercial RPM economics and bankability.

6. Add the customer's side of the case

The customer pays the same per kWh, so its savings come from what the RPM removes: diesel and generator maintenance, generator rentals for events, UPS and backup equipment, staff time spent managing backup, and outage losses. None of this is NFE revenue, but it often decides the sale. Worship Harvest spends about UGX 900,000 on diesel every Sunday (UGX 46.8m a year).

7. Decide and propose

• If the lead passes the screen and the margin covers capital recovery with room to spare, propose Phase 1 on the current terms.
• Phase 1: submeter after the grid/generator changeover at 15-minute intervals or finer for about 3 months, covering normal days, evenings, weekends, events and generator periods. Then redesign Phase 2 from the measured data.
• Present system sizes and CAPEX as indicative until Phase 1 and EPC quotes are done.

Worship Harvest in numbers

Step	Result
Average month	6,912 kWh: 2,017 peak / 3,565 shoulder / 1,330 off-peak (29% / 52% / 19%)
Weighted tariff	UGX 567.1/kWh, so revenue of UGX 3.92m/month (UGX 47.0m/year) before VAT
Evening energy	67 kWh a night on average; 88 kWh at the August run-rate
Battery	88 × 1.35 ≈ 118 → 120 kWh (about 103 kWh usable, or ~17 kW for 6 hours)
Inverter	50 kW three-phase, for headroom over an average evening load of 11–15 kW. The 200 kVA generator means Phase 1 must confirm this.
Solar	The first model needed ≥32 kWp for a 15% return; with the full replacement reserve, 40 kWp gives ~15%. Around 46 kWp, solar covers all peak + shoulder demand.
Avoided grid purchases (40 kWp)	24,207 kWh of peak via the battery + ~33,100 kWh directly against shoulder ≈ UGX 34.8m/year
CFADS	34.77 − 2.14 O&M − 1.20 admin − 6.91 replacement reserve = UGX 24.5m/year (~UGX 296 per kWh sold)
Capital recovery at 15% over 15 years	UGX 140–143m × 0.171 ≈ UGX 24.0–24.4m/year, so a project return of about 15%

Limits of this method

• It uses monthly and annual averages. Real use varies from day to day, so less solar is used on cloudy or quiet days. Move to an hourly model once Phase 1 data exists.
• The ≥2 MWh/month threshold came from a lighter version of this calculation (smaller replacement reserve). Treat it as a screen, not a guarantee of profitability.
• Utility bills don't show generator-supplied consumption, such as Worship Harvest's Sundays.

Last reviewed 21 October 2026 by Aaron Tushabe.

Commercial RPM economics and bankability

The numbers behind the Commercial RPM: where NFE's margin comes from, the Worship Harvest Phase 2 model, the customer-size threshold, and how a project can be financed. These are internal screening figures, not quotes or investment commitments. Model built 18 Sep 2026; terms updated to 21 Oct 2026. Owner: Aaron Tushabe.

Summary

• NFE charges the utility tariff, so its margin is the grid electricity it no longer has to buy: solar used directly in the daytime, and solar stored for the 18:00–24:00 peak. The margin sits inside the customer's existing price, not on top of it.
• Worship Harvest base case (120 kWh / 50 kW / 40 kWp; CAPEX modelled at UGX 142.8m): revenue UGX 47.0m/year, avoided grid purchases UGX 34.8m/year, cash flow available for debt service (CFADS) UGX 24.5m/year, project return (IRR) about 15% over 15 years.
• Financing works with shilling debt at 12% or less over 10 years or more (debt service cover, DSCR, of 1.6–1.9x). At ordinary commercial rates of about 18–19%, DSCR falls to about 1.25x and the equity return to about 10%.
• First projects: 50–55% debt, a 6-month debt service reserve, and a 15-year customer contract. Later, pool sites into a portfolio SPV.

Terms are defined in the NFE Commercial RPM Finance Glossary.

1. Where the margin comes from

RPM margin per kWh = (customer revenue − grid purchases − RPM operating costs) ÷ kWh sold

• Grid electricity NFE passes through at the same tariff earns nothing.
• Solar used directly replaces shoulder-rate grid electricity (UGX 562.1/kWh).
• Solar stored in the battery and used in the evening replaces peak-rate electricity (UGX 666.5/kWh), after about 10% round-trip losses.
• The battery cycles every day, so reliability, solar shifting and peak avoidance all come from the same asset.
• NFE has to be the billing layer for the facility's electricity. If the customer kept paying UEDCL for normal grid power and bought only backup power from NFE, this margin would not exist.

Charging the battery from the grid off-peak to sell at peak adds a little, but it is not the investment case (see Business Models for the NFE Microgrid OS).

2. Model structure

Customer → Load → System → Dispatch → Economics → Financing

• Customer: tariff, monthly bill, generator costs, outage frequency and cost, credit quality
• Load: annual and monthly kWh, peak/shoulder/off-peak split, maximum kW, critical kW, interval profile
• System: solar kWp, battery kWh and kW, inverter kW, CAPEX, useful life
• Dispatch: solar used directly, battery throughput, grid and generator kWh, curtailed solar, unserved energy
• Economics: revenue, energy costs, O&M, replacement reserve, CFADS, project IRR
• Financing: debt share, rate and tenor, DSCR, debt service reserve, equity IRR, buyout schedule

There is no shared spreadsheet yet; the calculations so far were done in Aaron's ChatGPT working session.

3. Base assumptions

Assumption	Base value	Validate with
Customer tariff	Applicable Code 10.2 time-of-use tariff. Q3 2026, before VAT: peak 666.5, shoulder 562.1, off-peak 429.7 UGX/kWh. Q4 2026 reportedly unchanged.	ERA schedule at each proposal date
Load (Worship Harvest)	82,940 kWh/year; 29% peak / 52% shoulder / 19% off-peak	12 months of bills and Phase 1 interval data
Solar yield	1,500 kWh/kWp/year (a Soroti solar plant averaged ~1,670)	Site-specific PV simulation
Battery	90% round-trip efficiency; 90% depth of discharge	Supplier datasheet and warranty
Inverter efficiency	95%	Datasheet
Reliability reserve	15% on battery sizing	SLA definition
Routine O&M	UGX 2.14m/year (~1.5% of CAPEX)	O&M quotes
NFE monitoring, billing and admin	UGX 1.2m per site per year	NFE operating costs
Battery and inverter replacement reserve	UGX 6.91m/year (~5% of CAPEX)	Warranty terms, cycle life, replacement prices
CAPEX	UGX 120–145m (model run at 142.8m)	At least two EPC/vendor quotes
Contract term	15 years; no residual value; no export income	Contract
Tariff escalation	None (real terms)	Indexation clause
Target project return	15%	Investment decision

4. Worship Harvest results

Energy flows (40 kWp)

Flow	kWh/year
Customer consumption	82,940
Solar production (40 kWp × 1,500)	60,000
Peak load supplied through the battery	24,207
Solar used directly against shoulder load	~33,100
Grid purchases replaced	~57,300
Grid purchases remaining	~25,600
Share of consumption met by solar and battery	~69%

Cash flow (bankability model, 40 kWp)

Item	UGX m/year
Customer energy revenue, before VAT	47.0
Grid electricity NFE still buys	(12.3)
Avoided grid purchases (gross margin)	34.77
Routine O&M	(2.14)
NFE monitoring, billing and admin	(1.20)
Battery and inverter replacement reserve	(6.91)
CFADS	24.52
CFADS per kWh sold	~UGX 296
Project IRR, 15 years, before financing	~15.1%

Solar size sensitivity (first, lighter model)

Solar	CAPEX (UGX m)	Annual contribution (UGX m)	Margin per kWh (UGX)	15-year IRR
32 kWp	135.5	23.4	282	15.2%
36 kWp	139.1	26.7	322	17.5%
40 kWp	142.8	30.0	361	19.6%
~46 kWp	148.6	35.2	425	22.6%

The first model combined O&M and replacements at 2.5% of CAPEX. The bankability model funds battery and inverter replacement explicitly, which lowers the 40 kWp return from about 19.6% to about 15.1%. The "around 20%" return discussed at the 19 Sep check-in came from the first model.

5. Customer-size threshold

The model was scaled to hypothetical customers with Worship Harvest's load shape, sizing the battery, inverter and solar for each and checking the 15-year return (first, lighter model):

Monthly consumption	Result at the 15% target
1.0 MWh	Below target
1.25 MWh	Below target
~1.5 MWh	About 15% (break-even ~1,490 kWh/month)
2.0 MWh	Attractive (for example ~30 kWh battery, 15 kW inverter, ~12 kWp solar)
3.0 MWh	Strong
5.0 MWh	Very good

Downside case	Break-even consumption
Base	~1.49 MWh/month
Solar yield 1,350 kWh/kWp	~1.68
CAPEX +15%	~2.09
Required return 20%	~2.24
Reliability reserve 30%	~1.64
Site overhead UGX 2m/year	~1.81

Several reasonable downside cases land near 2 MWh/month, which is why it became the screening threshold. Caveat: these runs used the lighter replacement assumption. Re-run them with the bankability assumptions and the 50% minimum payment before treating 2 MWh/month as firm.

6. Financing

Structures compared

CAPEX UGX 142.8m, CFADS UGX 24.52m/year, 10-year loan with level annual repayments:

Debt share	Rate	Debt service (UGX m/year)	DSCR	Equity IRR
60%	12%	15.16	1.62x	~15.7%
60%	18.7% (commercial bank)	19.54	1.25x	~10%
50%	18.7% (commercial bank)	16.28	1.51x	~11%
60%	10%	13.94	1.76x	~17.4%
60%	8%	12.77	1.92x	~19.2%
55%	12%	13.90	1.76x	~15.6–16.0%
50%	12%	12.64	1.94x	Not calculated

Equity IRR treats the 6-month debt service reserve as cash tied up for the term. In the 60% / 12% case, LLCR is about 1.62x and PLCR about 1.95x.

Rates context: Bank of Uganda reported weighted shilling lending rates of about 18.7% in Q4 2025, and shilling loans averaged 17.9% in August 2026. On 14 Oct 2026 the Central Bank Rate rose from 9.75% to 12% (Macro outlook), so commercial debt is likely dearer now. That strengthens the case for concessional finance.

Volume risk (60% debt at 12%)

Useful energy vs today	CFADS (UGX m)	DSCR
Base	24.52	1.62x
−5%	22.78	1.50x
−10%	21.04	1.39x
−15%	19.30	1.27x
−20%	17.56	1.16x

A lender wanting DSCR of at least 1.30x needs about 86% of today's throughput (about 5.95 MWh/month). At 50% debt, a 20% drop still leaves about 1.39x. The 50% minimum monthly payment (agreed 6 Oct) adds a revenue floor. This table hasn't been re-run with it yet.

Recommended structure for the first projects

Item	Position
Debt	50–55% of CAPEX, shilling, 10 years or more, 12% or less
Equity (NFE and investors)	45–50%
Debt service reserve (DSRA)	6 months of debt service
Customer contract	15 years
Customer deposit	About 2 months of electricity bills
Minimum payment	50% of the reference monthly energy charge (agreed 6 Oct)
Early termination	Payment covering outstanding debt, demobilisation and a defined share of unrecovered investment
Export income	None in the base case

At 55% debt: debt UGX 78.5m, equity plus DSRA about UGX 71m, debt service UGX 13.9m/year, DSCR 1.76x.

Capital stack to aim for

• 50–60% concessional or project debt at 8–12% in shillings, over 8–10 years or more
• 30–40% NFE and investor equity
• 0–20% climate grant, guarantee or first-loss capital

One candidate is Uganda Development Bank's Climate Finance Facility, which describes concessional debt, equity, guarantees and grants, and supports solar mini-grid projects. Once 5–10 sites have an operating history, pool them in a portfolio SPV (for example 20 sites × UGX 150m ≈ UGX 3bn) with portfolio-level DSCR and a central reserve. Lenders prefer that to financing one site at a time.

7. Ownership option and buyout

The year-5 purchase price must at least repay the outstanding senior debt and any prepayment costs, plus the NFE residual value agreed at signing. Outstanding debt in the 60% / 12% / 10-year case:

End of year	Senior debt outstanding
3	UGX 69.2m
5	UGX 54.7m
8	UGX 25.6m
10	0

8. Cash-flow waterfall

1. The customer pays NFE for metered electricity (or the minimum payment).
2. NFE (or the SPV) pays for grid electricity and other energy costs.
3. Routine O&M and operating costs are paid.
4. The battery and inverter replacement reserve is funded.
5. What remains is CFADS.
6. Scheduled senior debt service is paid.
7. The debt service reserve is topped up if needed.
8. The rest goes to NFE and equity investors.

9. Risks and mitigations

Risk	Mitigation
Customer uses less electricity	50% minimum monthly payment; lower debt on early sites; credit review; early termination payment
Tariff changes	Mirror the Code 10.2 structure; define indexation in the contract
Late or missed payments	Payment history, deposit, remote metering, clear default procedures, a diversified portfolio
Battery and inverter replacement	Explicit reserve, manufacturer warranties, standard equipment, remote health monitoring
Solar or storage underperforms	Conservative yield, commissioning tests, reserve margins
Peak demand underestimated	Phase 1 metering after the grid/generator changeover; size the inverter from measured kW
Regulatory	ERA certificate of registration for the microgrid before operation
Construction	Competitive quotes, fixed-price scope where possible, acceptance tests, EPC warranties
Currency	Equipment is priced in dollars; the shilling has fallen about 12% this year (Macro outlook)

10. Equipment cost benchmarks (Sep–Oct 2026)

Item	Price	Source and caveat
61.44 kWh high-voltage LFP battery (Felicity)	~UGX 32.77m incl. VAT	Uganda retail listing, Sep 2026
50 kW three-phase hybrid inverter (Felicity)	~UGX 14–15m	Uganda retail listings, Sep 2026
580 W solar module (Felicity)	~UGX 405,000 (~UGX 700/W)	Uganda retail listing, Sep 2026
600 W mono solar module	UGX 370,000 (~UGX 617/W), VAT not shown	Muden Systems quote, 19 Oct 2026 (page)
Packaged 120 kWh / 50 kW / 55 kWp C&I system	~UGX 144.69m incl. VAT	Uganda retail listing, Sep 2026
Packaged 60 kWh / 50 kW / 26.4 kWp system	~UGX 96m	Uganda retail listing, Sep 2026
Protection, changeover, mounting, cabling, switchgear	~UGX 8–12m	Estimate
NFE metering, controls and installation	~UGX 6–9m	Estimate
SRNE equipment for a ~120 kWh / 60 kW / 40 kWp system	~US$30,750, before the remaining installation costs	NFE's SRNE wholesale price list (Uganda), 23 Jul 2026

These are budget-brand retail prices. Hillary pointed out on 12 Sep that commercial customers and EPCs may expect SMA- or BYD-class equipment, so get quotes for that too. Dollar-priced equipment follows the shilling within weeks.

Installed planning allowances used for the Oct 2026 funding target: about US$15,000 for a smaller commercial site (30–40 kWh), US$25,000 for a medium site (60–80 kWh) and US$45,000 for a Worship Harvest-scale site (~120 kWh), each including solar, inverters and installation. Worship Harvest is one of the larger sites, not the typical one. See Funding target.

How the Worship Harvest CAPEX moved: UGX 118m in the first estimate (~28 kWp) → UGX 135.5m (32 kWp) → UGX 142.8m (40 kWp, with more conservative installation, project and contingency allowances). Present it as UGX 120–145m until EPC quotes arrive.

11. Before an investment decision

• Replace CAPEX with at least two EPC quotes, including an industrial-grade option
• 12 months of bills plus Phase 1 interval data, including generator-supplied load
• Site-specific solar simulation
• Lender term sheets (rate, tenor, minimum DSCR, reserve requirements)
• Re-run the threshold and volume-risk tables with the 50% minimum payment
• Move from annual averages to a monthly or hourly dispatch model
• Never quote the IRR, DSCR or 2 MWh threshold without the assumptions behind them; they are outputs of this model, not constants

Source: Aaron's ChatGPT working session "Commercial RPM Modeling" (18 Sep–21 Oct 2026). Last reviewed 21 October 2026 by Aaron Tushabe.

Worship Harvest (Commercial RPM customer #1)

Customer file for Worship Harvest, NFE's first Commercial RPM prospect. Stage: proposal sent 6 Oct 2026; Dansturn meets the Apostle on 3 Nov to ask for Phase 1 (monitoring). NFE lead: Aaron Tushabe. Point of contact on the ground, and introductions to decision-makers: Dansturn Kimbowa. Last updated 2 Nov 2026.

Next steps

• Dansturn meets the Apostle (3 Nov): ask permission to install NFE monitoring and share weekly reports, then propose a solution from the data
• Prepare the alternatives with costs: voltage stabilisers, the generator, UEDCL fixes, a move to Code 20 (Dansturn)
• Check whether Worship Harvest qualifies for Code 20 rather than Code 10.2
• Check the roof areas of both towers and the church against the panels needed (Aaron)
• Worship Harvest leadership decides on the proposal and Phase 1
• Phase 1: install NFE submetering after the grid/generator changeover (15-minute data or finer) for about 3 months
• Measure Sunday and event demand, peak kW/kVA and generator run hours
• Worship Harvest decides whether NFE manages and pays its UEDCL bill
• Agree the reference monthly energy charge (this sets the 50% minimum)
• Get at least two EPC quotes for the redesigned system, including an industrial-grade option
• Obtain the ERA certificate of registration for the microgrid before installation
• Attach the final proposal PDF and leadership summary to this page

The site

• A church and community facility. Worship Harvest owns its premises, so no landlord is involved.
• UEDCL commercial customer on the Code 10.2 time-of-use tariff.
• Runs a 200 kVA diesel generator all day on Sundays, even when the grid is up, so services aren't interrupted. This costs about UGX 900,000 per Sunday (about UGX 3.9m a month, UGX 46.8m a year).
• Brings in extra generators for large events, with temporary wiring to outdoor tents, LED screens and sound systems.
• Because the generator supplies Sundays, the utility bills understate the facility's real consumption.
• Two towers and the church, joined together. Panels could go on the other tower's roof as well as the church's.
• Apartments on site, around 40% occupied, sometimes with only four in use.
• Building work on the top apartments, and roof leaks they've been raising with the contractor for some time.

Pain points and how to approach them (check-in, 2 Nov 2026)

From Dansturn, who knows Worship Harvest from the inside. Source: NFE Checkin - 02/11/2026.

• Expensive backup. In an outage the 200 kVA generator runs the whole building, even when the only load is a few apartments. The cost comes up in the budget.
• Voltage problems. Over-voltage and flickering lights start the generator automatically. The facilities manager then calls Dansturn to find a UEDCL technician to change the transformer tap. Dansturn puts it down to the many roadside food vendors on the same supply, with lights of around 200 W and chip fryers of around 2 kW.
• Sundays cost several times more. Dansturn estimates about UGX 6M a month to UEDCL (in line with August's UGX 6.25m bill), or 1.5M a week, plus about UGX 900k for the generator each Sunday. Aaron: the weekday cost is just what power costs. What stands out is paying about UGX 1M for one day, at least four times the price, on Sundays.
• Irregular income. A church that runs on collections won't want to commit upfront capex. No upfront capex is the whole offer, so this works for us.
• They value data. They already produce performance reports, with ChatGPT's help, so weekly outage and consumption reports should land well. Agreed pitch: ask permission to install monitoring, share weekly reports, then propose. Weekly reports keep them engaged, but we need the longer window to show the patterns aren't one unusual week.
• They'll compare alternatives. A church member at Knight Frank recommended voltage stabilisers. Customers often want to know the options before saying yes, so show the alternatives (stabilisers, the generator, UEDCL fixes), what they cost, and why ours is better. Stabilisers bring their own losses.
• Tariff. Dansturn thinks they could qualify for Code 20. Aaron: that could be the first step in fixing their power.
• Ownership. A church that values long-term sustainability may like owning the system eventually. The proposal's optional purchase from year 5 speaks to that.
• Timing. Listen for reasons the timing might be wrong, such as the building work or the roof leaks, rather than pushing.
• Decision-makers. The Apostle first. The facilities manager and the chief architect / project manager follow, and Dansturn expects those to be formalities once the Apostle agrees.

Electricity use from the UEDCL bills

Four bills from the first half of 2026: Jan–Feb, Mar–Apr, Apr–May and May–Jun (the Feb–Mar bill is missing).

Bill	Peak kWh (18:00–24:00)
Jan–Feb	~1,665
Mar–Apr	~2,249
Apr–May	~2,107
May–Jun	~2,048

Average month	kWh	Share	Code 10.2 rate (UGX/kWh)	Value before VAT
Peak	2,017	29.2%	666.5	UGX 1.34m
Shoulder	3,565	51.6%	562.1	UGX 2.00m
Off-peak	1,330	19.2%	429.7	UGX 0.57m
Total	6,912		567.1 weighted	UGX 3.92m/month (UGX 47.0m/year)

Payment record (UEDCL account statement): the June bill of UGX 4.18m was cleared by 26 June, July's UGX 4.92m by 22 July, and August's UGX 6.25m by 15 August, leaving a small credit. The rising invoices suggest consumption is growing (roughly 7.3 MWh in July and 9.3 MWh in August, estimated from the amounts), so the 6.9 MWh/month base case may be conservative. If that run-rate holds, NFE revenue would be about UGX 4.3–5.3m a month.

Proposed system (indicative, before Phase 1)

Component	Proposal
Battery	120 kWh LFP
Inverter	50 kW three-phase hybrid
Solar	40 kWp (36–40 kWp range)
Metering and control	NFE metering and Microgrid Manager
Reliability target	At least 6 hours across the 18:00–24:00 peak
CAPEX	UGX 120–145m (the model uses UGX 140–143m)

Sizing risk (Hillary, 19 Sep): a 50 kW inverter may be far too small if Sunday and event loads come near what the 200 kVA generator supplies. The proposal ties ending routine generator use to measuring Sunday demand in Phase 1.

Scale: Worship Harvest is expected to be one of NFE's larger Commercial RPMs, not the typical size. The Oct 2026 funding target budgets US$45,000 installed for a site of this scale. That is above the UGX 120–145m model CAPEX (roughly US$29–35k), leaving room for a complete deployment. See Funding target.

What we offered (proposal of 6 Oct 2026)

• No upfront equipment cost; electricity at the applicable Code 10.2 tariff with reliability included
• Minimum monthly payment of 50% of the reference energy charge agreed after Phase 1
• NFE's preference to manage and pay the UEDCL bill (one consolidated bill), with Worship Harvest deciding during Phase 1
• ERA certificate of registration for the microgrid
• Phase 1 monitoring for about 3 months; installation 3–6 months after the load and outage profiles are confirmed
• A 15-year term and a deposit as proposed terms; optional purchase from year 5 (Ownership stage)
• NFE company profile appended, with NFE letterhead and watermark throughout

Sunday savings. The proposal's savings illustrations price replacement electricity at UGX 669.18/kWh (the UGX 567.1 historical weighted tariff plus assumed 18% VAT) until Phase 1 measures Sunday use. Example at 500 kWh per Sunday:

	UGX
Generator spend per Sunday	900,000
Replacement electricity from NFE	334,590
Saving per Sunday	565,410
Saving per year (52 Sundays)	~29.4m

Economics for NFE (internal)

• Revenue of about UGX 3.92m a month before VAT on the 6.9 MWh base case
• CFADS about UGX 24.5m a year; project return about 15%; at 55% debt and 12%, DSCR about 1.76x
• Detail: Commercial RPM economics and bankability

Documents

Document	Date	Where
Proposal (PDF and Word), with the NFE company profile	6 Oct 2026 (latest version)	Made in ChatGPT; attach the final PDF to this page
One-page summary for Worship Harvest leadership (PDF)	6 Oct 2026	Made in ChatGPT; attach to this page
UEDCL bills (4 photos) and account statement	Received 18 Sep 2026	Store the originals in Nextcloud and link them here

History

Date	What happened
18 Sep 2026	Bills and statement received; first Commercial RPM model and Phase 2 sizing built from them
19 Sep 2026	Team check-in: model promising but unvalidated; Sunday and event generator use came to light; peak demand is the main gap
1 Oct 2026	Proposal drafted with the company profile, letterhead and watermark
2 Oct 2026	Sunday generator cost added; roadmap section removed; premises ownership, Microgrid Manager and the Phase 1 timeline corrected
6 Oct 2026	Teammate review handled (tariff basis, 50% minimum, UEDCL bill, ERA registration, Ownership stage wording); one-page leadership summary made
17 Oct 2026	On the business pipeline agenda at the weekly check-in
2 Nov 2026	Team check-in: Dansturn's pain points (voltage problems, generator running the whole building, irregular income); data-first pitch agreed; Dansturn booked a meeting with the Apostle for 3 Nov

Related: NFE Commercial Reliable Power Microgrids · Assessing a Commercial RPM lead · Commercial RPM decision log

NFE Commercial RPM Finance Glossary

Commercial RPM Finance & Energy Glossary

Plain-English reference for NFE commercial microgrid discussions

STATUS Reference Draft

VERSION 0.2

DATE 21 Oct 2026

How to use this glossary The goal is not to turn every NFE discussion into finance jargon. These terms are included so engineering, product, commercial and finance discussions use the same definitions. Where NFE uses a term in a specific internal way, that is noted explicitly.

1. Core product and engineering terms

Acronym	Stands for	Plain-English meaning
RPM	Reliable Power Microgrid	NFE's product model for providing reliable electricity as a service, with NFE owning/operating the enabling infrastructure during the service term and an optional later ownership path.
EaaS	Energy as a Service	A commercial model in which the customer buys an energy service (for NFE, metered electricity and reliability) rather than buying the underlying solar, battery and inverter equipment.
C&I	Commercial and Industrial	Customer segment covering businesses and institutions such as offices, schools, hotels, clinics, supermarkets, churches and factories.
CAPEX	Capital Expenditure	Upfront investment in long-lived assets: batteries, inverters, PV modules, switchgear, cabling, controls, installation and commissioning.
OPEX	Operating Expenditure	Recurring costs of running the RPM after construction, such as monitoring, service visits, insurance, communications, billing/admin and some maintenance.
O&M	Operations and Maintenance	Activities needed to keep the system safe and performing: monitoring, inspections, cleaning where applicable, repairs, warranty administration and maintenance.
EPC	Engineering, Procurement and Construction	The party/scope responsible for final engineering, purchasing equipment, constructing/ installing the system and commissioning it.
BoS	Balance of System	All supporting equipment beyond the main PV modules/batteries/inverters: mounting, cabling, protection, switchgear, combiner boxes, earthing and related hardware.
PV	Photovoltaic	Solar-electric generation technology that converts sunlight directly to electricity.
BESS	Battery Energy Storage System	The complete battery system, including cells/modules and associated controls/safety systems. Often used interchangeably with “battery storage” at project level.
LFP	Lithium Iron Phosphate	Lithium-ion battery chemistry commonly used in stationary storage because of its cycle life, thermal characteristics and cost profile.
kW	kilowatt	A unit of power: the instantaneous rate at which electricity is being produced or consumed. Inverter size and maximum facility demand are power quantities.
kWh	kilowatt-hour	A unit of energy: one kilowatt used for one hour. Customer bills and battery energy capacity are expressed in kWh.
kWp	kilowatt-peak	The rated DC output capacity of a PV array under standard test conditions.
DoD	Depth of Discharge	The percentage of a battery's nominal capacity that is used before recharging. A 90% DoD on a 120 kWh battery implies up to roughly 108 kWh discharged before other conversion losses/reserves.
RTE	Round-Trip Efficiency	The ratio of energy recovered from storage to energy put into it. If 100 kWh charges a battery and 90 kWh is later delivered, RTE is 90%.
EMS	Energy Management System	Software/control layer that decides how grid, PV, batteries and other resources operate, and provides monitoring, alarms, data and dispatch logic. For NFE this is part of the Microgrid OS.
TOU	Time of Use	A tariff structure in which electricity prices differ by time period, such as peak, shoulder and off-peak. TOU pricing can make stored solar particularly valuable during expensive evening hours.
SLA	Service Level Agreement	Contractual definition of the service NFE promises, such as availability, supported critical load, response time or outage-coverage duration.
PPA	Power Purchase Agreement	A contract under which one party sells electricity to another under agreed pricing and terms. RPM is broader than a conventional PPA because reliability, storage and operations are central to the service.
SPV	Special Purpose Vehicle	A separate legal entity created to own one project or a portfolio of projects. An RPM SPV could hold the equipment, customer contracts, debt and project cash flows separately from NFE's general corporate balance sheet.

2. Project-finance terms

Acronym / term	Stands for	Plain-English meaning
CFADS	Cash Flow Available for Debt Service	Cash generated by the project that is available to pay principal and interest after defined operating costs. In the current NFE screening model we conservatively calculate CFADS after routine O&M, NFE site overhead and lifecycle reserve contributions, but before debt service.
DSCR	Debt Service Coverage Ratio	CFADS divided by scheduled principal + interest for the same period. Example: UGX 24.5m CFADS / UGX 13.9m debt service = about 1.76x. Above 1.0x means modeled cash flow exceeds scheduled debt service; lenders normally require additional cushion.
DSRA	Debt Service Reserve Account	Cash reserve maintained to cover debt service if operating cash flow is temporarily insufficient. A 6-month DSRA holds roughly half a year of scheduled debt service.
IRR	Internal Rate of Return	The discount rate at which the net present value of an investment's projected cash flows equals zero. In plain English, it is a time-adjusted measure of the return generated by investing capital today and receiving future cash flows. Compare IRR with NFE/investor return requirements and the risks in the assumptions; it is not the same as annual profit margin.
Project IRR	Project / unlevered Internal Rate of Return	IRR calculated on the project's operating cash flows before debt financing. It answers: “Does the asset itself generate an adequate return regardless of how we finance it?”
Equity IRR	Equity Internal Rate of Return	IRR on the cash invested by NFE/equity investors after accounting for debt drawdown and debt service. Leverage can increase or decrease equity IRR depending on the cost and terms of debt relative to project returns.
NPV	Net Present Value	Today's value of future project cash flows after discounting them at a chosen required return. Positive NPV means the modeled project creates value above that required return; negative NPV means it does not.
ROI	Return on Investment	A simpler return metric comparing gain to amount invested. Unlike IRR, basic ROI does not inherently account for when cash flows occur.
WACC	Weighted Average Cost of Capital	The blended required return/cost of a project's debt and equity capital, weighted by how much of each is used. It is often used as a discount rate or hurdle reference.
LLCR	Loan Life Coverage Ratio	Present value of CFADS available during the remaining loan life divided by outstanding debt. It looks beyond a single year's DSCR to the debt coverage over the loan period.
PLCR	Project Life Coverage Ratio	Present value of CFADS over the remaining project life divided by outstanding debt. It includes cash flows after the loan matures and is therefore normally higher than LLCR.
LCOE	Levelized Cost of Energy	Lifetime cost of producing electricity divided by lifetime electricity produced, discounted over time. Useful for comparing generation technologies, but it does not by itself capture reliability value or the timing value of stored energy.
LCOS	Levelized Cost of Storage	Lifetime cost of operating storage divided by the energy delivered from storage, generally accounting for efficiency, degradation and replacement. It is a storage analogue to LCOE.
P50 / P90	Probability-based energy cases	P50 is the energy estimate expected to be exceeded roughly 50% of the time; P90 is a more conservative estimate expected to be exceeded roughly 90% of the time. Lenders often care about conservative production cases.

3. Non-acronym terms that matter for RPM

Term	Meaning for NFE
Utility-price anchor	NFE's customer price is tied to the applicable utility tariff or a defined utility-based index, rather than an equipment lease payment.
RPM margin per kWh	The value NFE creates inside the customer's energy price after accounting for the cost of grid/other energy and RPM operating provisions. It is not automatically an extra charge above the utility tariff.
Lifecycle reserve	Cash set aside over time to fund major replacements such as batteries and inverters. It prevents the model from looking profitable only because future replacement costs were ignored.
Minimum energy commitment	A contractual floor on energy purchases that reduces lender volume risk. For Commercial RPMs, NFE uses the minimum monthly energy payment below (agreed 6 Oct 2026) rather than a take-or-pay commitment.
Minimum monthly energy payment	From commissioning, the customer pays the greater of the actual metered energy charge or 50% of the reference monthly energy charge. It replaces a lower bill and is never added on top, and service-performance credits apply if NFE fails to deliver. Agreed 6 Oct 2026.
Reference monthly energy charge	The monthly energy charge agreed after Phase 1 submetering: the measured baseline consumption, valued at the applicable Code 10.2 time-of-use tariffs. The kWh baseline is fixed in the contract; tariff changes adjust its value.
Consolidated energy bill	NFE's preferred billing arrangement: NFE manages and pays the customer's UEDCL bill and issues one bill for all the facility's electricity. The customer decides during Phase 1.
Ownership stage	The customer-facing name for the optional purchase of the system from year 5, subject to agreed terms. Used in proposals instead of "Phase 4" so it is not confused with step 4 of the delivery plan.
Code 10.2 tariff	The ERA/UEDCL commercial time-of-use tariff that Commercial RPM pricing mirrors. Q3 2026, before VAT: peak (18:00–24:00) UGX 666.5/kWh, shoulder 562.1, off-peak 429.7. ERA reviews it quarterly.
Take-or-pay	A stronger form of volume commitment under which a customer pays for a minimum contracted quantity even if it does not consume it. This can improve bankability but may conflict with the desired RPM customer experience.
Early termination payment	A payment due if a customer voluntarily exits before the contract ends, typically designed to cover outstanding debt, demobilization and a defined portion of unrecovered investment.
Tariff indexation	Rules that change the customer tariff over time based on a reference such as the applicable utility tariff, inflation or another agreed index.
Critical load	The subset of facility demand that must remain powered during an outage. Defining critical load can materially reduce battery/inverter size and project cost.
Bankability	The combination of predictable cash flows, enforceable contracts, acceptable risks, sufficient coverage, credible counterparties and technical/regulatory certainty that makes a lender willing to finance a project.

4. The four numbers to remember in an RPM financing discussion

Number	Question it answers
IRR	Is the project/equity return high enough for the risk and capital being committed?
DSCR	Does current project cash flow comfortably cover this period's debt payment?
CFADS	How much cash is actually available to service the debt after operating obligations?
CAPEX per site / per supported kW	How much capital must NFE deploy to deliver the promised reliability and what size portfolio can available capital support?

Practical rule IRR is a return metric; DSCR is a debt-safety metric. A project can have an attractive IRR but still be difficult to finance if cash flows arrive too late or DSCR is weak in the debt years. Conversely, a project can have strong DSCR because it uses little debt while still offering a poor equity return.

See also: Glossary (NFE-wide acronyms) and NFE Commercial Reliable Power Microgrids.