Hypothesis · GreenWind Holding

Portfolio — 8 sites · 730 MW (5 operational, 3 pipeline)

Site	Entity	Country	MW	COD	Life	Turbines	Wind (m/s)	Net CF

Production cascade — from wind to billable MWh (S01 illustration, annual)

Theoretical gross yield = MW × 8,760 h × CF theoretical S01: 45 MW × 8,760 × 39.5% ≈ 155,700 MWh/yr

− Wake loss × (1 − 7%) Turbine-to-turbine wind shadow effect

− Technical loss × (1 − 5%) Transformer, cable, power quality losses

× Availability × 96% Planned + unplanned downtime, incl. maintenance windows

− Curtailment × (1 − 2%) Grid operator curtailment orders (congestion, frequency regulation)

× Degradation × ~0.4%/yr after age 5 Blade erosion, drivetrain wear — floor at 70% of nameplate

× Capture rate × 88% Price capture vs baseload — wind produces more when prices are low

= Net billable MWh → S01: ≈ 128,600 MWh/yr (net CF ≈ 32.8%)

× Seasonality (monthly) Jan ×1.22 · Feb ×1.18 · Mar ×1.20 · Apr ×0.85 · May ×0.78 · Jun ×0.77 · Jul ×0.78 · Aug ×0.80 · Sep ×0.92 · Oct ×1.10 · Nov ×1.20 · Dec ×1.20

Forecast vs realized capacity factor (why the step-up). The figures above are long-term P50 (median-year) net capacity factors from the resource assessment — what each site earns over its life, not the specific 2023-2025 outturn. Realized 2023-2025 ran lower (~27% across the onshore fleet, e.g. North Atlantic 26.7% vs P50 32.8%): normal inter-annual wind variability, with those years sitting below P50 — the Low_Wind scenario captures the P75-P90 downside. Separately, the group capacity factor steps up from 2028 as Jutland offshore (P50 ≈ 45%, 400 MW) joins the fleet, mechanically lifting the weighted average well above the onshore-only ~30%.

Major maintenance events (aging) S01 — 2030 & 2035 Blade inspection + gearbox overhaul modelled as O&M cost ×2.0 in those years. No production loss assumed (scheduled during low-wind periods).

Offtake — who buys the power Market + subsidy stack Onshore farms sell electricity into the wholesale market (spot/day-ahead) via an aggregator, with a subsidy layer on top (FiT / CfD). Jutland (S07, offshore) additionally carries a two-way CfD on most of its output — see the plain-language box below. The Jutland CfD — in plain terms A CfD is, in effect, fixing the price in advance on most of your output. For Jutland the model contracts 88% of the volume at a €90/MWh "strike"; the remaining 12% is sold at the variable wholesale price. It is two-way: when the market price falls below €90 the counterparty tops GreenWind up to €90; when it rises above €90, GreenWind pays the excess back. Net effect — stable, predictable revenue on the contracted slice: the project gives up price upside in return for protection against price falls.

Why it's in the model: a €1.2bn offshore farm funded with 80% debt is only bankable if lenders see contracted rather than merchant revenue — high coverage is standard offshore PF practice (UK CfD ≈ 100%; corporate/Danish structures 80-90%). The €90/MWh strike sits at the upper end of the €80–90 range, consistent with a long-dated contract fixed at signing. Strike held flat (not inflation-indexed) — a conservative choice. Together with a current-market build cost (€3.0M/MW, see §03) this makes Jutland a properly bankable asset that earns above its cost of capital. Revenue formula Onshore & the merchant share of Jutland: Revenue = Net MWh × Capture price + Subsidy, where Capture price = Baseload × Capture rate (capture <100% reflects wind's market-timing disadvantage — it produces most when prices are lowest).
Jutland's contracted 88%: earns the flat €90 strike, immune to the scenario price factor.
Subsidy = 12% of electricity revenue (flat proxy for FiT/CfD top-up — a simplification; real support varies by vintage and technology). Baseload price France & Spain: €65/MWh base (2023 reference), inflated at 2.5%/yr compounding. No country premium differentiator in the current model. Grid connection All sites are grid-connected (no battery storage). Curtailment losses (see §01) are the primary grid constraint. Grid connection costs are included in CapEx (10% of total project cost allocation).

Scenario modifiers (from scenario_definitions.csv)

Scenario	Wind factor	Price factor	OpEx inflation	Debt delta	CapEx delay	Curtailment factor
Base	×1.0	×1.0	+2.5%/yr	0 bps	0 months	×1.0
High_Price	×1.0	×1.2	+2.5%/yr	0 bps	0 months	×1.0
Low_Wind	×0.92	×1.05	+2.5%/yr	0 bps	0 months	×0.95
Delayed_CapEx	×1.0	×1.0	+2.5%/yr	0 bps	+12 months	×1.0
Rate_Shock	×1.0	×1.0	+2.5%/yr	+200 bps	0 months	×1.0
Inflation_Shock	×1.0	×1.03	+6.5%/yr	0 bps	0 months	×1.0
Curtailment_Shock	×1.0	×0.95	+2.5%/yr	0 bps	0 months	×2.0

Variable O&M — scales with installed MW Onshore: €35,000/MW/yr Covers turbine maintenance contracts (O&M full-service or time-&-materials), scheduled servicing (oil changes, filter replacements, blade inspections every 2–3 yrs). At 45 MW (S01): ≈ €1.6M/yr. Doubles in major maintenance years (2030, 2035 for S01). Offshore: €80,000/MW/yr Higher due to vessel access costs, marine logistics, anti-corrosion treatment, subsea cable inspections. Applies to S07 Jutland Offshore Link (400 MW) post-COD 2028.

Fixed O&M — per site, regardless of output Onshore: €450,000/site/yr Site-level fixed costs: land lease (fermage) or land rent contracts, site security, perimeter maintenance, meteorological mast, SCADA monitoring subscription, local insurance (property + liability), annual safety inspections required by French/Spanish regulators, local authority liaison costs. Offshore: €1,500,000/site/yr Adds: offshore substation lease, seabed lease (from state maritime authority), subsea cable maintenance retainer. Applies to S07 Jutland post-COD 2028.

SG&A — Selling, General & Administrative Site-level: €80,000/site/yr (onshore) Per-site admin: local project management, community liaison (obligatory in French ICPE permit conditions), local accounting/payroll, regulatory reporting to CRE (France) / CNMC (Spain). Holding: €2,000,000/yr GreenWind Holding SA central costs: C-suite (CEO, CFO, General Counsel), central FP&A team, group audit fees, group legal retainer, consolidated regulatory reporting, Board costs, D&O insurance, investor relations if applicable. This is a lean holding model — no IT or HR shared services assumed. Offshore site: €250,000/site/yr Higher due to more complex regulatory environment, dedicated marine project team.

Depreciation & Amortisation Component-split method CapEx is split across components, each depreciated over its own useful life:
Turbines (70% of CapEx) — depreciated over asset life (22 yrs onshore). Straight-line.
Civil works (10%) — 40 yrs (foundations, access roads, concrete).
Grid connection (10%) — 35 yrs (underground cable, switchgear).
Substations (10%) — 30 yrs (transformer, HV equipment).
Onshore CapEx reference: €1.4M/MW. S01 (45 MW) = €63M gross CapEx.
Offshore CapEx reference: €3.0M/MW (current-market fixed-bottom, 2024-2028 COD). Jutland (400 MW) = €1.2bn gross CapEx.

Working capital AR — Revenue 1-month collection lag (electricity market settlement cycle). AR — Subsidies 2-month lag (administrative processing by CRE/CNMC for FiT/CfD reimbursements).

Project finance — construction & operations Structure Project finance (non-recourse) at the SPV/subsidiary level. Debt is ring-fenced per entity (E_FR, E_ES etc.); the Holding (E_HOLD) bears no project debt. Leverage 60% during construction (drawn progressively as milestones are hit). At COD refinancing: 70% onshore / 80% offshore of total CapEx. Remaining equity is injected via programmed equity calls. Cost of debt Base rate: 5.0% p.a. (fixed, proxy for project finance bank margin + base rate blended). Scenario-adjustable via cost_of_debt_bps delta. At COD refinancing, margin reduction of 75 bps applied (lower risk post-construction → tighter bank pricing). Tenor 18 years from first drawdown. Fully amortising (level debt service). Matches typical wind project finance tenor in France/Spain (aligned with FiT contract duration). Capitalized interest during construction Interest accrued on drawn debt during construction phase is capitalized (added to the asset cost, not expensed). Reflected as IDC in investing cash flows. DSCR covenant Standard project finance covenant: lenders require minimum DSCR ≥ 1.20× (not modelled as a hard constraint in the engine — flagged as a KPI for CFO monitoring). Below 1.20×: cash sweep / dividend lock-up provisions typically triggered.

Corporate RCF (Revolving Credit Facility) — holding level Facility €150M RCF at GreenWind Holding level. Not a project finance instrument — used purely for holding liquidity management. Pricing 4.5% p.a. on drawn amounts. 0.30% commitment fee on undrawn balance (cost of keeping the line available). Usage logic Engine draws the RCF when Holding cash falls below €10M (minimum floor). Target cash level: €25M. RCF is repaid first from any cash upstreamed from subsidiaries.

Equity calls programme Scheduled injections €100M — June 2026 (construction continuation S05 Andalusia + S08 Baltic East)
€75M — March 2027 (peak Jutland construction — Q1)
€75M — September 2027 (Jutland 75% milestone)
€50M — March 2028 (final balance Jutland, pre-COD)
Total programme: €300M · Source: equity_calls_programme.csv

Cash upstream policy (sub → holding) Eligibility conditions A subsidiary can upstream cash only if: (1) site age ≥ 2 years post-COD, (2) subsidiary retains ≥ €5M cash buffer after distribution, (3) no DSCR breach. 80% of eligible excess cash is upstreamed annually (20% retained at sub level).

Inflation Price inflation 2.5%/yr compounding on baseload electricity prices (France & Spain, from 2023 base). Scenario-adjustable via price_factor. OpEx inflation 2.5%/yr on all operating costs (O&M variable + fixed + SG&A). No differentiation between labour and materials inflation in the base model. CapEx CapEx is expressed in nominal terms at time of spend (no inflation escalation — cost is assumed locked via EPC contract at signing).

Corporate income tax (IS) France & Spain 25% — standard rate. Tax is computed on taxable income (EBIT − interest), not EBITDA. No deferred tax modelled. Germany 30% (combined corporate + trade tax). GreenWind Deutschland GmbH — S06 Bavaria Wind Farm (40 MW onshore, COD 2024). Denmark 22%. GreenWind Nordic ApS — S07 Jutland Offshore Link (400 MW, under construction, COD 2028). Poland 19%. GreenWind Polska Sp. z o.o. — S08 Baltic East Wind Farm (60 MW onshore, under construction, COD 2026). Functional currency: PLN. Tax losses / carry-forward Not explicitly modelled. Sites with losses in early years (construction/ramp-up) are assumed to benefit from NOL carry-forward at the local entity level; this may overstate tax in the first profitable years.

FX & currency Functional currency E_FR, E_ES, E_DE and E_DK operate in EUR. E_PL (GreenWind Polska Sp. z o.o.) operates in PLN — translation exposure arises on consolidation (S08 Baltic East, 60 MW). No hedging assumed in the base model; PLN balances are translated at the closing EUR/PLN rate from fx_rates.csv. DKK rates are also loaded for completeness (E_DK reports in EUR in the model).

Model limitations to flag to lenders / auditors: (1) DSCR is a KPI, not a hard covenant constraint in the engine. (2) Tax loss carry-forwards are not modelled explicitly — early-year tax may be overstated. (3) Subsidy rate (12%) is a flat proxy — real FiT/CfD amounts depend on vintage, tariff period and market price floors. (4) No PPA structure, no merchant price curve — price is a simple inflation-adjusted baseload. (5) Offshore CapEx/OpEx parameters apply post-COD; S07 Jutland is currently in construction phase (actuals 2023–2025 pre-COD). (6) TODO (pending O4): CfD/PPA strike price for S07 Jutland (400 MW) and NOL carry-forward by entity not yet reflected in the engine — current base case treats Jutland as merchant (88% capture rate). Hypotheses will be documented here once O4 recalibration is complete.