Commercial RPMs

Reliable Power Microgrids for commercial facilities using at least 2 MWh a month: the offer and terms, decisions, how to assess leads, economics and financing, and customer files.

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

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

Where things stand (21 Oct 2026)

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.

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

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).

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

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

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

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

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

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.

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

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

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; waiting for Worship Harvest to agree to Phase 1. NFE lead: Aaron Tushabe. Introductions to Worship Harvest's decision-makers: Dansturn Kimbowa. Last updated 21 Oct 2026.

Next steps

The site

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)

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)

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

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.