10 · Solutions
Every finding has a gate, not a slogan
Mitigation that cannot be written into a conditions-precedent schedule is PR. This chapter maps each red-team finding to an owner, a cost and a kill-switch. AURION POWER will not raise construction equity until the block items close.
Finding → fix
Rebuild energy from first principles
Stated capacity factors (CSP 50%, PV 40%, geo 90%) produce 1.14 TWh/year. The plan books 1.75 TWh — an 80% blended capacity factor, which is geothermal-class performance on a plant that is 80% solar. Revenue, IRR and DSCR all sit on the inflated number.
Lock the screening model to MW × 8,760 × CF × availability. Independent CFs: CSP 48%, PV 26%, geo 85%. Do not book 1.752 TWh. Publish P50/P90 after a measured DNI year.
- Cost
- Model audit ~$80–150k. DNI mast ~$0.4–0.8M.
- Owner
- AURION POWER CFO + independent engineer
- Gate
- No CIM until generation matches CFs.
Retire the 28.7% slide
Even if the $187M revenue were real, $1.86B of capital against ~$172M EBITDA is an ~9% unlevered yield, not 28.7%. The PwC “validation” language in the source pack reads as ISRS 4400 agreed-upon procedures copy, not an audit opinion, and is not independently confirmed.
Replace ISRS 4400-style language with a named-firm model (ISAE / agreed procedures with working papers). Present three cases: sponsor-as-printed, independent 250 MW, Phase 1. Credit committees underwrite DSCR, not teaser IRR.
- Cost
- $120–250k model + tax.
- Owner
- AURION POWER + Big-4 or boutique project-finance modeller
- Gate
- No equity raise on unreproducible IRR.
Sell capacity, not bulk hydro-competing MWh
EEP/EEU are mid-reform (16 quarterly hikes from Sep 2024; 8th landed June 2026). That does not make them a buyer of $0.10/kWh. EEU’s FY2025/26 (Addis Fortune, 9 Aug 2026) spent 133.59 billion birr against 118.91 billion of revenue. Its CEO put generation cost at 6.5–7 US cents and the selling price under 2 cents. Crypto-miner PPAs, reported at 3.2 US cents, were cut from 98% of contract to 23% in September 2026 when inflows fell. A premium USD energy price is a policy choice with a Ministry of Finance wrap, not a price the utilities clear today.
Term-sheet a USD capacity payment ($/kW-year) plus a modest energy charge, 20-year, MoF guarantee, 3-month LC. Target dry-season and evening net-peak. Do not compete with GERD energy in the wet season.
- Cost
- Legal + transaction ~$1.5–3M through IA.
- Owner
- AURION POWER GC + EEP/MoF desk
- Gate
- No NTP without executed PPA + wrap.
Option CSP. Do not FID it.
Africa’s operating CSP reference (Xina Solar One) cost ~$8,950/kW for 100 MW and 5.5 h storage. Ethiopia has zero CSP operating fleet, no local trough supply chain, and no measured multi-year DNI at the site. Dry-cooled CSP in >45°C Afar will derate.
Phase 1 is 50 MW PV + geo wells. CSP is a second raise after 12-month on-site DNI, a named African-experienced EPC, dry cooling, and a capacity-priced PPA. 150 ha is too small for 200 MW trough — re-survey before any layout.
- Cost
- DNI year + layout ~$1–2M. CSP FID only later ($0.9–1.4B).
- Owner
- AURION POWER CTO / owner’s engineer
- Gate
- CSP option expires if DNI or land fails.
Prove Tendaho to a reserves standard
Wells have seen 220–270°C. That is a resource indicator, not a reserves statement. The 7.3 MW Aluto pilot is the country’s geothermal reference and its current availability is disputed. Corbetti and Tulu Moye — the only private geothermal PPAs of scale — were stalled as of 15 September 2026 and are renegotiating tariff, not pouring concrete. $2.50/W geothermal CAPEX omits exploration dry-hole risk and that precedent.
3–6 deep wells, SPE/PRMS-style resource report, GRMF drilling grant bid, stage-gate P90 ≥ 15 MW before any power block. Budget dry-hole risk. Do not use $2.50/W.
- Cost
- Wells + tests $40–70M (grant-eligible).
- Owner
- AURION POWER geo lead + GSE liaison
- Gate
- P90 MW before EPC.
Pump-test, then size the greenhouse
Afar is hyper-arid. CSP wet cooling is inappropriate; even dry-cooled plants and 20 ha of greenhouses need water. Deep fractured-basalt yield, fluoride, silica and brine disposal must be pump-tested, not desktop-asserted. The appendix “50 billion m³ Afar storage” figure is not a cited hydrocensus result we can stand behind.
72-hour tests on fractured basalt, fluoride/silica lab, RO pilot, brine re-injection permit. Dry-cool any CSP. Size agri to proven yield, not 2,000 m³/day asserted.
- Cost
- $2–4M hydro + RO pilot.
- Owner
- AURION POWER EHS + MoWE
- Gate
- Water licence before greenhouse FID.
Agri is a co-product, not 6% of revenue
A 20 ha greenhouse and a pastoral landscape do not produce 50,000 t of biomass. Organic fertilizer at that scale is a separate industrial plant. Bank the power case; treat agri as a co-product option, not 6% of revenue.
Phase 1: 5 ha geothermal greenhouse as a living lab (800 t crops, 4,000 t compost-class fertilizer stretch). Drop 40,000 t from the CIM. Fertilizer at industrial scale is a different plant and a different raise.
- Cost
- Inside Phase 1 $8–12M of the $248M.
- Owner
- AURION POWER agri + MoA offtake
- Gate
- No debt sculpted on fertilizer.
Haircut carbon to option value
GERD adds 15.7 TWh of hydro. Displacement of diesel/thermal can still be additional in the dry season and in Afar, but a 100 ktCO₂e/yr Verra story at $15/t is not a financing pillar. Use $5–10/t and a haircut.
Model $5–10/t, 70 kt stretch, no gearing. Dry-season diesel displacement in Afar can still be additional; a 100 kt Verra at $15 is not a pillar. Bid GCF on the adaptation (water, greenhouse) story separately.
- Cost
- Registry + MRV ~$0.3–0.6M.
- Owner
- AURION POWER ESG
- Gate
- Carbon out of DSCR numerator.
USD waterfall or no debt
USD/ETB was 162.6–163.3 on 2 October 2026 (commercial mids). CBE’s cash buy that morning was 160.23; the best published cash buy was 164.88. The 2024 float already broke the tariff study’s FX assumption. CSP troughs, turbines, salt, PV modules and geo well services are FX. A 60/40 USD/ETB energy tariff without a liquidity facility is not bankable.
100% USD capacity payment. ETB only for local O&M with CPI indexation. MIGA/ATI political-risk insurance. Offshore collection account. Holding-company FX from Markets/Jewels is not a hedge for a $1.9B plant.
- Cost
- PRI premium 0.5–1.5%/yr of covered exposure.
- Owner
- AURION POWER treasury + MoF
- Gate
- Convertibility facility in IA.
Budget desert reality
$15M on $1.86B is 0.8% of CAPEX. CSP + geothermal + desert soiling + well workovers land closer to $25–30M in year 1 before escalation.
Year-1 OPEX $25–30M on the 250 MW case; $9.5M on Phase 1. Include soiling, well workovers, salt inventory, H₂S abatement, security. Staff 120 is plausible for 250 MW; 45–60 for Phase 1.
- Cost
- Built into independent case.
- Owner
- AURION POWER COO
- Gate
- Lender base case uses independent OPEX.
Survey, then resize — do not redraw the dream
Single-axis utility PV is commonly screened at about 2.2–2.8 ha per MWp, infrastructure included. A 50 MWac Phase 1 field at ~1.2 DC/AC is already on the order of the whole 150 ha parcel before wells, a greenhouse and a pastoral corridor. 200 MW of troughs does not fit beside it. The $248M case is not revised until a survey measures net buildable land.
Commission a topographic and cadastral survey of the 150 ha pin against Tendaho. Subtract pastoral corridors, flood and slope. Then either cut Phase 1 AC, switch to fixed tilt, or assemble more land. Leave CSP off this parcel. Do not update the $248M screening case until the hectares are measured.
- Cost
- Survey and layout $150–400k, inside development equity.
- Owner
- AURION POWER owner’s engineer
- Gate
- No module deposit and no CIM layout before net ha.
Do not lend against the utility’s current tariff
EEU FY2025/26: 133.59 billion birr spent, 118.91 billion collected, gap 14.69 billion, of which 48.42 billion was paid to EEP for bulk energy (Addis Fortune, 9 Aug 2026). The CEO’s figure: generation costs 6.5–7 US cents and is sold for under 2. A $0.085–0.10 plant is above both the stated system cost and the retail price. Reform is raising tariffs; it has not closed the gap.
Screen the energy charge against what EEP already sells: under 2 US cents at retail, and 3.2 cents to miners before those contracts were cut. Put value in a USD capacity payment for dry-season and evening hours, with an MoF guarantee and an offshore account. EEU’s FY2025/26 cash gap (14.69 billion birr) is not a repayment source.
- Cost
- Inside the PPA legal budget.
- Owner
- AURION POWER GC + MoF desk
- Gate
- No debt if the offtaker is EEU’s retail margin.
Sell dry-year insurance. Do not sell to miners.
Capital Ethiopia (20 Sep 2026) reported reservoir inflows down about 20%, miner deliveries cut from 98% of contract to 23%, and the 2026/27 export target revised to $279 million (−11%). The same report puts installed capacity at 9,752 MW and the miner tariff at 3.2 US cents. Dry years are real. They are not a reason to offtake to miners, who were cut first.
September 2026 inflow cuts are the product thesis: hydro is not firm every year. Size Phase 1 as dry-season capacity for EEP or an export utility. Do not sign a miner offtake — those contracts were curtailed first, sit at 3.2 cents, and collide with the NBE virtual-asset notices.
- Cost
- No incremental capex. A refused revenue line.
- Owner
- AURION POWER commercial
- Gate
- Miner offtake is a kill, not a backup.
Assume the PPA will be reopened, because the peers’ were
ThinkGeoEnergy (15 Sep 2026): Tulu Moye (Meridiam / Reykjavik Geothermal, 150 MW plan) halted litigation and is revising its PPA. Corbetti is renegotiating tariff with EEP and MoF; Taranis (Perenco) signed a convertible of up to $27 million in June 2026. Neither has confirmed a return to drilling. A Tendaho PPA signed on today’s draft will face the same reopen.
Tulu Moye and Corbetti were stalled and, as of 15 September 2026, rewriting tariff after disputes. Do not drill equity-funded wells against a draft price. Use a GRMF grant for the first wells, and a change-in-law clause that pays for stranded wells if the tariff is cut after a well is accepted.
- Cost
- Grant path; legal increment inside the $1.5–3M IA budget.
- Owner
- AURION POWER geo lead + GC
- Gate
- No equity well before a tariff that survives a ministry review, or a grant that makes the well expendable.
Conditions precedent — public tracker
Status as of the recast. User-Admin can tick these in the data room.
| Workstream | Months | Owner | Status |
|---|---|---|---|
| 12-month on-site DNI + GHI + soiling | 12 | Owner’s engineer | Not started |
| 3–6 deep wells + SPE/PRMS resource report | 18–24 | Geo lead / GRMF | Not started |
| PPA term sheet — USD capacity + MoF wrap | Parallel | GC / EEP desk | Draft in appendix only |
| Interconnection agreement + SIS | 12–18 | EEP | Not started |
| Land title, 150 ha survey, grazing FPIC | 12 | Afar / SPV | Unsigned lease copy in pack |
| Net buildable ha vs 50 MW PV and any CSP | With survey | Owner’s engineer | Screening conflict — open |
| Category A ESIA, IFC PS | 12–18 | EHS | Desktop ESIA only |
| Pump tests, RO pilot, brine permit | 12–18 | EHS / MoWE | Desktop hydrocensus only |
| Named CSP/PV/geo OEM shortlist | 12 | CTO | Logos, not contracts |
| Independent bank model (not ISRS 4400 copy) | 3–4 | CFO | This recast is the screen |
| MIGA/ATI political-risk insurance quote | 6–9 | Treasury | Not started |
| GRMF drilling-grant application | 6 | Geo lead | Not started |
| GCF concept on water + greenhouse adaptation | 9–12 | ESG | Not started |
| Offtaker test: USD capacity vs EEU cash gap and 3.2¢ miner price | With PPA | GC / CFO | Open — Oct 2026 |
| Change-in-law / stranded-well clause after Corbetti & Tulu Moye reopen | With PPA | GC | Open — Sep 2026 precedent |