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 - 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.

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.

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.

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.

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

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.

< 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.

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.

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.

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