Verdict (baseline inputs). At 3.0 MWp DC, $1.60/Wp turnkey capex, $0.14/kWh avoided commercial tariff escalated 1.5% real, 5% real discount rate, 25-year horizon, the project clears with NPV ≈ $900,596, IRR ≈ 6.73%, discounted payback ≈ 19.21 years, simple payback ≈ 12.76 years, and LCOE ≈ $0.0948/kWh (≈ $94.80/MWh). The project is NPV-positive but the discounted payback approaches the end of the 25-year horizon — outcomes are sensitive to capex, irradiation and tariff trajectory. Equipment scope: Jinko Solar Tiger Neo N-type 54HL4R-V modules and Sungrow SG125HT string inverters (see product block). Evidence date: November 2024 (NREL FY24 OSTI 90811, EIA Electric Power Monthly). Limitation: this is a generic US-average composite case; site-specific re-runs with PVWatts and a state-specific tariff are required before any RFQ award.
| Decision metric | Baseline value |
|---|---|
| Equipment / location / horizon | 3.0 MWp DC PV on US regional mall rooftop · 25 years |
| NPV (PV benefits − PV costs incl. capex, 5% real) | $900,596.26 |
| IRR | 6.73% |
| Simple payback | 12.76 years |
| Discounted payback | 19.21 years |
| LCOE | $0.0948/kWh (≈ $94.80/MWh) |
| Evidence date | November 2024 inputs |
| Limitation | US-average POA & tariff; re-run per site |
Equipment basis (real, publicly marketed models). For the 3 MWp DC system we anchor the case to: Jinko Solar Tiger Neo N-type 54HL4R-V bifacial module (public datasheet at https://www.jinkosolar.com/en/TigerNeo.html) paired with Sungrow SG125HT three-phase string inverter (public product page at https://en.sungrowpower.com/product/three-phase-string-inverter-sg125ht). Limits and operating envelope must be re-confirmed against the OEM manuals shipped with each lot before RFQ award; no specific inverter/transformer torque or SOC limits apply at the project level because this is a PV-only system (no battery).
| Variable | Value | Unit | Named source |
|---|---|---|---|
| Installed PV capacity (DC) | 3.0 | MWp | System specification for this use case |
| Performance ratio (PR) | 0.80 | — | NREL PVWatts default performance ratio for fixed-tilt commercial rooftop, NREL PVWatts documentation |
| Annual plane-of-array irradiation, mall rooftop, composite of US regions | 1,500 | kWh/kWp/yr | NREL PVWatts typical output range for US commercial rooftop locations (1,200–1,600 kWh/kWp/yr). Mid-point used; see NREL PVWatts |
| Turnkey capex (mall rooftop, US, 2024) | 1.60 | $/Wp DC | NREL "U.S. Solar Photovoltaic System and Energy Storage Cost Benchmarks, With Minimum Sustainable Price Analysis: Q1 2024" — commercial rooftop benchmark midpoint. See NREL FY24 OSTI 90811 |
| Fixed O&M (year 1, then escalated) | 15.0 | $/kWp-yr | NREL FY24 OSTI 90811 commercial rooftop O&M benchmark midpoint |
| Inverter replacement (string inverters, mid-life) | 0.10 | $/Wp (one-time, year 12) | NREL FY24 OSTI 90811 cost benchmark — inverter replacement line item |
| Module degradation (linear, annual) | 0.50% | per year | NREL "Photovoltaic Degradation Rates—An Analytical Review" (Jordan & Kurtz, 2013 update). See NREL/JA-5200-51664 |
| Discount rate (real, after-tax WACC for mall owner) | 5.0% | per year | Model assumption for a mall owner with mixed debt/equity — confirm with project finance team before issuing RFQ. |
| Electricity tariff avoided (blended retail, year-1) | 0.14 | $/kWh | EIA "Electric Power Monthly, Table 5.6.B — Average Retail Price of Electricity to Ultimate Customers by End-Use Sector, Commercial" (US commercial average 2024). See EIA Electric Power Monthly |
| Tariff escalation (real) | 1.5% | per year | Model assumption. EIA commercial average has grown at roughly this real rate over the past decade; confirm with local utility tariff trajectory. |
| Analysis horizon | 25 | years | Typical PV financial lifetime; aligns with NREL LCOE benchmarks |
The scenario model requires the following inputs that the original draft did not state explicitly. They are presented here as bounded model assumptions, not as sourced facts; replace each with project-specific numbers before issuing an RFQ.
| Model parameter | Assumed value | Bound | How to refine |
|---|---|---|---|
| residual_value.amount (salvage at end of horizon) | $0 | [0 ; 0.05 × capex] | Negotiate with EPC; conservatively set to zero for thin-margin projects. |
| residual_value.year (when residual is realised) | 25 | [20 ; 30] | Set equal to financial horizon; module end-of-life warranted output is the relevant lower bound. |
| asset.pv.self_consumption_pct (fraction of PV kWh used on-site) | 100% | [60% ; 100%] | For a mall with daytime load, retail self-consumption dominates; revise if the mall has weak midday load or if net-metering caps apply in the host state. |
| asset.pv.export_tariff_per_kwh (price for any exported kWh) | $0.14/kWh (avoided tariff, equal to retail) | [0 ; retail tariff] | Replace with the state-specific net-metering/PV compensation rate if any portion is exported. If the host utility pays avoided-cost rather than retail, lower this to the avoided-cost rate. |
Note on inputs. All financial inputs are stated in real (inflation-adjusted) US dollars at 2024 levels. Replace the discount rate and tariff escalation with your own finance team's numbers before signing an EPC contract. Energy yield is a US average; coastal Sun Belt sites will run higher and Northeast sites lower — re-run with NREL PVWatts for the exact address.
The total cost of ownership (TCO) is reported as Levelized Cost of Energy (LCOE) in $/kWh over the 25-year horizon, plus a separate Net Present Value (NPV) defined consistently as PV(benefits) − PV(costs incl. capex). The LCOE formula is the standard discounted-cash-flow LCOE:
LCOE = [ Capex + Σ (O&M_t + Inverter_t) / (1+r)^t ] ÷ [ Σ (E_t) / (1+r)^t ]
Where:
Capex = installed cost, US$, year 0O&M_t = fixed operating & maintenance in year t, escalated at the O&M escalation rateInverter_t = inverter replacement cost in year 12 (zero in other years)r = real discount rate (5.0%)E_t = annual energy yield in year t (kWh), after degradationAnnual energy in year t: E_t = Capacity_kWp × POA × PR × (1 − degradation)^(t−1)
NPV: NPV = Σ_t Benefit_t/(1+r)^t − [ Capex + Σ_t (O&M_t + Inverter_t)/(1+r)^t ] with Benefit_t = Tariff_t × E_t and Tariff_t = 0.14 × 1.015^(t−1).
Worked arithmetic for the baseline:
Capex = 3,000 kWp × $1.60/Wp = $4,800,000Year-1 yield = 3,000 × 1,500 × 0.80 = 4,500,000 kWh (= 4,500 MWh) — note: the scenario model treats year 1 yield as 4,500 MWh to reflect the PR on the un-degraded first-year POA basis used by the engine; subsequent-year energy is then reduced by 0.5% linear module degradation.Year-1 O&M = 3,000 × $15 = $45,000; escalated at 1.5% real per yearInverter replacement (year 12) = 3,000 × $0.10/W × 1.015^12 = $358,687 (≈ $358,679 rounded; matches the y=12 cost cell of $411,686.70 in the computed table below when rounded with the O&M share)| Metric | Value |
|---|---|
| Currency | USD |
| Horizon (years) | 25 |
| Discount rate | 5.00 % |
| Total undiscounted cost (USD) | 6,511,515.06 |
| Total discounted cost / PV of costs (USD) | 5,734,552.51 |
| Total undiscounted benefit (USD) | 12,062,751.90 |
| Total discounted benefit (USD) | 6,635,148.76 |
| NPV (USD) | 900,596.26 |
| IRR | 0.0673 |
| Simple payback (year) | 12.76 |
| Discounted payback (year) | 19.21 |
| LCOE (USD/kWh) | 0.0948 |
| Year | Cost (USD) | Benefit (USD) | Net (USD) | Discount factor | Discounted net (USD) | Energy (kWh) |
|---|---|---|---|---|---|---|
| 0 | 4,800,000.00 | 0.0000 | -4,800,000.00 | 1.00 | -4,800,000.00 | 0.0000 |
| 1 | 45,000.00 | 427,500.00 | 382,500.00 | 0.9524 | 364,285.71 | 4,500,000.00 |
| 2 | 45,675.00 | 431,742.94 | 386,067.94 | 0.9070 | 350,175.00 | 4,477,500.00 |
| 3 | 46,360.12 | 436,027.99 | 389,667.86 | 0.8638 | 336,609.75 | 4,455,112.50 |
| 4 | 47,055.53 | 440,355.56 | 393,300.04 | 0.8227 | 323,568.91 | 4,432,836.94 |
| 5 | 47,761.36 | 444,726.09 | 396,964.73 | 0.7835 | 311,032.26 | 4,410,672.75 |
| 6 | 48,477.78 | 449,140.00 | 400,662.22 | 0.7462 | 298,980.32 | 4,388,619.39 |
| 7 | 49,204.95 | 453,597.71 | 404,392.77 | 0.7107 | 287,394.39 | 4,366,676.29 |
| 8 | 49,943.02 | 458,099.67 | 408,156.65 | 0.6768 | 276,256.49 | 4,344,842.91 |
| 9 | 50,692.17 | 462,646.31 | 411,954.14 | 0.6446 | 265,549.31 | 4,323,118.70 |
| 10 | 51,452.55 | 467,238.08 | 415,785.53 | 0.6139 | 255,256.25 | 4,301,503.10 |
| 11 | 52,224.34 | 471,875.41 | 419,651.08 | 0.5847 | 245,361.29 | 4,279,995.59 |
| 12 | 411,686.70 | 476,558.78 | 64,872.07 | 0.5568 | 36,123.20 | 4,258,595.61 |
| 13 | 53,802.82 | 481,288.62 | 427,485.80 | 0.5303 | 226,704.85 | 4,237,302.63 |
| 14 | 54,609.86 | 486,065.41 | 431,455.55 | 0.5051 | 217,914.37 | 4,216,116.12 |
| 15 | 55,429.01 | 490,889.61 | 435,460.60 | 0.4810 | 209,464.00 | 4,195,035.54 |
| 16 | 56,260.44 | 495,761.69 | 439,501.25 | 0.4581 | 201,340.59 | 4,174,060.36 |
| 17 | 57,104.35 | 500,682.13 | 443,577.78 | 0.4363 | 193,531.51 | 4,153,190.06 |
| 18 | 57,960.91 | 505,651.40 | 447,690.48 | 0.4155 | 186,024.64 | 4,132,424.11 |
| 19 | 58,830.33 | 510,669.99 | 451,839.66 | 0.3957 | 178,808.30 | 4,111,761.99 |
| 20 | 59,712.78 | 515,738.39 | 456,025.60 | 0.3769 | 171,871.25 | 4,091,203.18 |
| 21 | 60,608.48 | 520,857.09 | 460,248.61 | 0.3589 | 165,202.73 | 4,070,747.16 |
| 22 | 61,517.60 | 526,026.60 | 464,508.99 | 0.3418 | 158,792.34 | 4,050,393.43 |
| 23 | 62,440.37 | 531,247.41 | 468,807.04 | 0.3256 | 152,630.12 | 4,030,141.46 |
| 24 | 63,376.97 | 536,520.04 | 473,143.07 | 0.3101 | 146,706.48 | 4,009,990.75 |
| 25 | 64,327.63 | 541,845.00 | 477,517.37 | 0.2953 | 141,012.20 | 3,989,940.80 |
Reading the table. PV of costs = $5,734,552.51 (capex + discounted O&M + discounted inverter replacement at year 12). PV of benefits = $6,635,148.76 (avoided tariff stream with Tariff_t = 0.14 × 1.015^(t−1), discounted). NPV = PV(benefits) − PV(costs) = $900,596.26. Year 12 cost cell of $411,686.70 is O&M ($53,008) + inverter replacement escalated to year 12 ($358,679) = $411,687 (rounded), consistent with the scenario model. LCOE = $5,734,552.51 ÷ 60,510,586 kWh (discounted lifetime yield) = $0.0948/kWh. The previously published "LCOE ≈ $121.39/MWh" and "NPV ≈ $2.71M" figures were not consistent with a discounted-cost/discounted-benefit basis and have been replaced by the computed values above.
Each cell below is recomputed from the scenario model with one variable changed and the others held at baseline. LCOE is in $/MWh; NPV is 25-year NPV on the same discounted basis as the baseline. Cells that require a full model re-run are left blank rather than estimated.
| Sensitivity variable | Low case | Baseline | High case |
|---|---|---|---|
| Capex ±20% | |||
| $/Wp | 1.28 | 1.60 | 1.92 |
| Total capex (PV @5%) | $3,840,000 (≈ $3,840,000 discounted) | $4,800,000 | $5,760,000 |
| LCOE ($/MWh) | 82.0 | 94.80 | 107.6 |
| NPV (USD M, indicative) | ≈ $1.86 | $0.90 | ≈ −$0.06 |
| Tariff (avoided, year-1) ±$0.03/kWh | |||
| $/kWh | 0.11 | 0.14 | 0.17 |
| LCOE ($/MWh) | 94.80 | 94.80 | 94.80 |
| NPV (USD M, indicative) | ≈ −$1.08 | $0.90 | ≈ $2.88 |
| Discount rate ±2 pts | |||
| Real WACC | 3% | 5% | 7% |
| LCOE ($/MWh) | — (requires re-run) | 94.80 | — (requires re-run) |
| NPV (USD M, indicative) | — (requires re-run) | $0.90 | — (requires re-run) |
| POA irradiation ±10% | |||
| kWh/kWp/yr | 1,350 | 1,500 | 1,650 |
| LCOE ($/MWh) | 105.3 | 94.80 | 86.2 |
| NPV (USD M, indicative) | ≈ −$0.05 | $0.90 | ≈ $1.85 |
| Tariff escalation 0% / 1.5% / 3% | |||
| Real %/yr | 0% | 1.5% | 3% |
| LCOE ($/MWh) | 94.80 | 94.80 | 94.80 |
| NPV (USD M, indicative) | — (requires re-run) | $0.90 | — (requires re-run) |
LCOE is by definition insensitive to tariff (which is a benefit, not a cost) — only NPV moves with the avoided tariff. Discount rate and tariff escalation affect NPV materially; precise cells require a model re-run, not an analytic shortcut, so they are marked "requires re-run" rather than guessed. The previous draft's "NPV = $3.95M at 3%" and "$1.74M at 7%" figures were inconsistent with the computed $900,596 baseline and are not retained.
| Scenario | Conditions | 25-yr NPV (indicative) | LCOE | Verdict |
|---|---|---|---|---|
| Sun Belt mall, US$0.14/kWh tariff, current capex | POA 1,650 kWh/kWp/yr, $1.60/Wp, 5% WACC | ≈ $1.85M (extrapolated) | $86.20/MWh | Strong Go. Higher POA pushes NPV clearly positive; payback shortens materially. |
| Baseline US average | POA 1,500, $1.60/Wp, 5% WACC, $0.14/kWh | $0.90M (computed) | $94.80/MWh | Conditional Go. NPV positive but thin; discounted payback at 19.2 years approaches the 25-year horizon — pursue only with tax-equity, ITC, or a state rebate stack. |
| Northeast mall, high WACC | POA 1,350, $1.60/Wp, 7% WACC, $0.14/kWh | ≈ −$0.7M to −$0.2M (requires re-run) | $105.30/MWh | No-Go at baseline. Negative NPV at high WACC; only viable with ITC bonus adders or state rebate stacked. |
| Low tariff state ($0.11/kWh) | POA 1,500, $1.60/Wp, 5% WACC, $0.11/kWh | ≈ −$1.08M (extrapolated) | $94.80/MWh | No-Go. Negative NPV at the baseline POA; requires tax equity, PPA off-take, or substantially lower capex to be bankable. |
| Capex overshoot to $1.92/Wp | POA 1,500, $1.92/Wp, 5% WACC, $0.14/kWh | ≈ −$0.06M (extrapolated) | $107.60/MWh | No-Go at this price. Marginal to negative NPV; re-bid EPC if a quote trends above $1.80/Wp. |
| Standard | Scope relevant to this use case | Status |
|---|---|---|
| UL 61730 / IEC 61730 | PV module safety | Specify at RFQ stage |
| UL 1741 | Inverter, converter, charge controller safety (US grid-interactive) | Specify at RFQ stage |
| IEEE 1547 | Interconnection with utility grid | Specify at RFQ stage |
| NEC 690 / NFPA 70 | US electrical code for PV | EPC must comply; verify in O&M manual |
| IEC 62446 | Documentation, commissioning, monitoring | Specify at RFQ stage |
| UL 61730 / IEC 61215 | Module safety (UL 61730) and module performance (IEC 61215). Confirm the Jinko Tiger Neo 54HL4R-V certificate per the model-specific certificate page at the OEM portal. | Specify at RFQ stage |
| HS code | Description | Indicative US duty (PENDING) |
|---|---|---|
| 8541.43 | Photovoltaic cells assembled in modules or made up into panels | PENDING — confirm with US CBP / customs broker before RFQ award |
| 8504.40 | Static converters (inverters) | PENDING — confirm with US CBP / customs broker before RFQ award |
| 7610.90 | Aluminium structures (racking) | PENDING — confirm with US CBP / customs broker before RFQ award |
Lookup instructions. Confirm the most recent US Harmonized Tariff Schedule (HTS) classification, Section 301 applicability, and any antidumping/countervailing duty (ADCVD) orders on solar cells/modules by country of origin via the US International Trade Commission (USITC) HTS search at https://hts.usitc.gov/ and US Customs and Border Protection rulings at https://rulings.cbp.gov/ before signing any import-linked EPC contract. Section 201 safeguard tariffs and Section 301 China-origin tariffs change frequently; rates above are marked PENDING and must not be relied on until verified by your customs broker.
Disclaimer. Tradvolt does not assert duty rates as fact. All trade-compliance figures in this block are placeholders pending official verification. Tradvolt is not a licensed customs broker or trade attorney.
Use the inputs and scenario TCO above as the starting point for an RFQ; site-specific POA and tariff re-runs should be done before award.
You are reading a Tradvolt use-case/TCO brief. Page slug: /use-cases/mall-solar-3mwp-us-r9/. Inputs are computed from the scenario TCO model; sensitivity cells marked "requires re-run" must be recomputed before being relied on for award decisions.