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.

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.

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

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

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.

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 revenue

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.

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.

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.

NFE Commercial Reliable Power Microgrids

Commercial Reliable Power Microgrids (RPMs)

Phase 2 financial and bankability model | Worship Harvest worked example

STATUS
Team Review Draft

VERSION
0.1

DATE
18 Sep 2026



Core proposition
NFE sells reliable electricity as a service at approximately the customer's applicable utility tariff. The customer pays for energy used, not equipment. NFE owns, operates, maintains and replaces the reliability infrastructure, with an optional Phase 4 path to ownership.



1. Purpose of this document

This pack is intended to support the NFE weekly team review on the emerging Commercial RPM model. It captures the current product logic, a worked Phase 2 case, preliminary financing structure, customer-screening thresholds, model definitions and the decisions still required before NFE treats the model as investment-ready.

2. The Commercial RPM model

Phase

Customer outcome

NFE activity

1 - Measure & Manage

Establish an evidence-based load and outage baseline.

Install interval metering, characterize peak/shoulder/off-peak demand, identify critical loads and quantify current backup costs.

2 - Reliable Power

At least the contracted critical load remains powered through normal outages.

Deploy storage, inverter/control infrastructure and enough PV to help finance the reliability layer.

3 - Energy Optimization

Lower grid dependence and optimize energy cost/reliability.

Expand PV/storage, optimize dispatch and progressively use the grid as a secondary source.

4 - Ownership Option

Customer may choose to acquire the installed system.

Execute a predefined buyout/transfer mechanism that first protects any outstanding lender obligations.

3. Worship Harvest: current evidence base

Metric

Working value

How to treat it

Average monthly electricity consumption

~6.9 MWh/month

Derived from four supplied detailed UEDCL bills; use as the current baseline, not a guaranteed future load.

Annualized electricity consumption

~82.9 MWh/year

Used for the current screening model.

Observed load mix

~29% peak / 52% shoulder / 19% off-peak

Useful because the 18:00-24:00 peak period exactly matches the requested six-hour backup window.

Recent utility payment behavior

Bills in the supplied statement were substantially/fully cleared within the billing cycles shown.

Positive early credit signal, but not a substitute for full credit underwriting.

Phase 2 reliability target

At least 6 hours during 18:00-24:00

Must be validated with interval data and critical-load definition.

4. Preliminary Phase 2 technical design

Component

Working design

Rationale

LFP battery

120 kWh nominal

Provides headroom above historical average peak-period energy, plus usable-depth, conversion-loss and reliability reserve allowances.

Hybrid inverter

50 kW, three-phase

Provides headroom for instantaneous demand and motor/other transient loads that monthly bills cannot reveal.

Solar PV

36-40 kWp preferred

PV is not needed to make a 6-hour evening battery work technically; it is included because avoided daytime/peak grid purchases finance the reliability infrastructure.

Controls / EMS

NFE Microgrid OS + metering

Required for dispatch, monitoring, billing, alarms, asset health and later portfolio management.

Important engineering caveat
Monthly bills show energy consumption, not instantaneous power demand. The 50 kW inverter and 120 kWh battery are preliminary. Phase 1 interval metering should validate the maximum kW demand, critical-load profile, event-day behavior, battery charge window and site power quality before procurement.



5. Commercial model: where the RPM margin comes from

The RPM margin is not a surcharge on the customer tariff. It is the economic spread created when NFE can supply a portion of the customer's electricity at a lower effective cost than the utility tariff while preserving the customer-facing price anchor.

Cash-flow layer

Illustrative annual value

Meaning

Customer electricity revenue

~UGX 47.0m

Energy sold at the utility-equivalent weighted tariff assumption.

Gross avoided utility purchases

~UGX 34.8m

Value created by direct PV plus PV shifted through storage to displace grid purchases.

Routine O&M allowance

~UGX 2.1m

Annual operating/maintenance budget.

Battery + inverter lifecycle reserve

~UGX 6.9m

Explicit reserve contribution for major component replacement rather than assuming these costs disappear.

NFE monitoring/billing/site overhead

~UGX 1.2m

Site-level software, monitoring, billing and operating support allowance.

CFADS (internal screening definition)

~UGX 24.5m

Cash flow available for debt service after the above conservative operating and reserve provisions, before debt service.

6. Base-case bankability structure

Item

Working assumption

Installed Phase 2 CAPEX

~UGX 143m

Customer contract term

15 years

Senior debt

50-55% of CAPEX preferred for early projects

Sponsor / investor equity

45-50% of CAPEX

Target debt tenor

10 years minimum

Target UGX debt rate

<=12% if possible; concessional/project finance preferred

Debt Service Reserve Account (DSRA)

6 months of scheduled debt service

Customer upfront equipment payment

Zero

Customer tariff

Utility-equivalent energy tariff, with contractually defined indexation

Ownership

NFE/SPV during service term; Phase 4 buyout option subject to lender discharge

7. Illustrative 55% debt case

Metric

Illustrative result

Interpretation

Senior debt

~UGX 78.5m

55% of ~UGX 142.8m CAPEX.

NFE/investor equity

~UGX 64.3m

Before DSRA funding.

Annual debt service

~UGX 13.9m

Assumes 12% debt over 10 years with level annual debt service.

Base DSCR

~1.76x

CFADS / scheduled debt service. Provides material cushion above 1.0x.

6-month DSRA

~UGX 7.0m

Liquidity buffer equal to half a year of scheduled debt service.

Unlevered project IRR

~15.1%

Return on the project before debt financing, under the current simplified 15-year constant-real-cash-flow assumptions.

Equity IRR

~15.6-16.0%

Approximate result depending on how/when DSRA is released.

Financing conclusion
The economics are much more attractive with long-tenor concessional or project debt than with ordinary high-cost commercial lending. Early RPMs should prioritize lower leverage and strong coverage rather than maximizing debt. Portfolio financing can increase leverage later after operating history exists.



8. Customer qualification threshold

The current model suggests a theoretical break-even/target-return threshold near 1.5 MWh/month for a customer with a load shape similar to Worship Harvest. For sales screening, NFE should use a more conservative threshold because fixed costs, site complexity, credit quality, solar yield and load shape vary.

Monthly usage

Screening interpretation

< 1.5 MWh

Usually below current economic threshold for a stand-alone Commercial RPM Phase 2.

1.5-2.0 MWh

Possible but marginal; requires especially favorable site/load/credit conditions.

>= 2.0 MWh

Recommended first-pass Commercial RPM qualification threshold.

>= 3.0 MWh

Strong candidate, subject to solar-compatible demand and site/credit quality.

Worship Harvest: ~6.9 MWh

Comfortably above the consumption threshold; the remaining work is engineering, regulatory, credit and financing validation.

9. Bankability risks and mitigations

Risk

Why it matters

Proposed mitigation

Volume risk

Customer pays for energy used; NFE debt service does not fall if customer consumption contracts.

Lower leverage for early sites; strong customer underwriting; termination protection; consider a modest minimum annual energy commitment only where financing requires it.

Tariff/indexation risk

A fixed customer tariff can become uneconomic as utility prices and operating costs change.

Contractually mirror the applicable utility tariff structure or define a transparent indexation formula.

Credit/collection risk

Energy revenue is the project cash flow.

Credit review, payment history, deposits, remote metering, clear default/curtailment procedures and diversified portfolio.

Technology/lifecycle risk

Battery/inverter replacement can destroy economics if omitted.

Explicit replacement reserve, manufacturer warranties, standardized equipment and remote health monitoring.

Performance risk

PV yield or storage availability may underperform assumptions.

Conservative yield, performance guarantees where available, commissioning tests and reserve margins.

Regulatory risk

The legal structure for on-site generation/resale/EaaS must be valid.

Obtain Uganda-specific regulatory/legal confirmation before financial close and standardize the compliant contract structure.

EPC / construction risk

Cost overruns or poor installation can impair returns and safety.

Competitive RFQ, fixed-price scope where feasible, commissioning acceptance tests and appropriate EPC warranties.

10. Proposed cash-flow waterfall

  1. Customer pays NFE for metered electricity under the EaaS contract.

  2. NFE/SPV pays utility/grid energy costs and other variable energy costs.

  3. NFE/SPV funds routine O&M and operating expenses.

  4. NFE/SPV funds the agreed battery/inverter lifecycle reserve.

  5. Remaining operating cash is CFADS for lender purposes under the internal screening model.

  6. Scheduled senior debt service is paid.

  7. Required DSRA top-up, if any, is funded.

  8. Residual distributable cash is available to NFE / equity investors.

11. Decisions requested from the NFE team

Decision

Current working position

Team discussion

Commercial Phase 2 product definition

Battery reliability + enough PV to support the economics.

Confirm whether this becomes the standard default or remains site-specific.

Customer tariff promise

Utility-equivalent tariff, not an equipment lease.

Define exactly which utility charges are mirrored and how tariff changes flow through.

Reliability promise

6-hour outage coverage for contracted critical load.

Decide whether the product SLA should be framed as hours, availability %, or both.

Debt strategy

50-55% debt for early projects; target <=12%, 10+ years.

Confirm acceptable leverage and target lender categories.

Customer minimum usage

No hard minimum in the preferred customer proposition.

Decide whether a soft minimum annual energy commitment is acceptable when a lender requires it.

Phase 4 ownership

Predefined buyout from a stated year, subject to lender discharge.

Agree lockout year and buyout methodology.

Commercial screening threshold

>=2 MWh/month first-pass screen.

Confirm and add load-shape, credit and site criteria.

Portfolio/SPV structure

Preferred long-term financing architecture.

Decide when to establish the first RPM project/portfolio SPV.

12. Immediate next steps

  1. Install/obtain interval metering for Worship Harvest and identify critical vs. discretionary loads.

  2. Request at least two local EPC/vendor quotations for the 120 kWh / 50 kW / 36-40 kWp design range.

  3. Refresh the model with quoted CAPEX, warranty terms, installation scope and realistic replacement assumptions.

  4. Confirm the legally compliant Uganda EaaS / on-site resale structure and required permits/licences/exemptions.

  5. Complete a customer credit review and obtain a longer utility-payment history if available.

  6. Develop the standard Commercial RPM EaaS term sheet: tariff indexation, SLA, deposit, termination, access, insurance and Phase 4 buyout.

  7. Prepare a lender-facing model with monthly cash flows, debt amortization, downside cases and covenant tests.

  8. Build a pipeline scorecard so NFE can screen commercial leads consistently before spending engineering time.

Appendix A - Model assumptions that must be refreshed before investment approval

Assumption

Current working value

Validation method

Annual load

~82.9 MWh

12 months of bills + interval metering

Solar yield

~1,500 kWh/kWp/year

Site-specific PV simulation / irradiation dataset

Installed CAPEX

~UGX 143m for 120 kWh + 50 kW + 40 kWp

Competitive EPC/vendor RFQs

Project term

15 years

Customer contract negotiation

Debt cost / tenor

12% / 10 years illustrative

Lender term sheets

Lifecycle reserve

Modelled explicitly

Warranty, cycle-life and replacement-price analysis

Utility-equivalent tariff

Working weighted energy price from current tariff structure

Refresh at proposal date and define indexation

Customer load shape

Historical TOU shares from bills

Interval metering

Regulatory structure

Not yet confirmed

Ugandan legal/regulatory review

Appendix B - Interpretation discipline

NFE Commercial RPM Finance Glossary

Commercial RPM Finance & Energy Glossary

Plain-English reference for NFE commercial microgrid discussions

STATUS
Reference Draft

VERSION
0.1

DATE
18 Sep 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 can reduce lender volume risk. NFE may prefer not to use a hard minimum unless financing requires it, to preserve the “pay for what you use” proposition.

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.



Glossary

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:

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 5 to 14 panels fit on one string.

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

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

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).