NABCEP PVTS cheat sheet

Solar window analysis uses a Solar Pathfinder or Solmetric SunEye to read the sun-path chart; shading fraction = shaded sun-path hours ÷ total annual sun-path hours, and above roughly 20% annual shade the array is usually uneconomic.

Azimuth convention: true south = 180°, due east = 90°, due west = 270°; a roof facing 180° ± 30° is generally treated as a good production orientation in the northern hemisphere.

Roof pitch in degrees = arctan(rise ÷ run); pitch ratio 4:12 ≈ 18.4°, 6:12 ≈ 26.6°, 9:12 ≈ 36.9°; low-slope roofs under 2:12 often need ballasted or east-west racking.

Roof structural review: verify rafter/truss spacing and condition, and confirm the design snow load plus PV dead load (roughly 2.5-4 lb/ft² for rail-based racking) fits the existing structure; a licensed engineer signs off when required.

Usable array area = roof area × usable fraction; leave 18 in (or local code minimum) clear at ridges and edges for fire access, and account for vents, chimneys, skylights, and access pathways.

Annual production estimate: P (kWh/yr) = array kW × PSH (peak sun hours) × 365 × system derate; typical derate for a grid-tied string system is 0.75-0.85, covering soiling, temperature, mismatch, wiring, and inverter losses.

Interconnection screening: check utility feeder and transformer capacity, panel busbar rating, and main breaker size before promising a system size; a 200 A panel with a 200 A main breaker limits backfed PV to 40 A under the 120% rule.

Customer load profile: gather 12 months of kWh and demand data; a system sized to offset 80-100% of annual kWh is common, and time-of-use rates shift value toward west-facing arrays.

String sizing: maximum string voltage = Voc(STC) × N × temperature correction factor for record low cell temperature; the result must stay below the inverter maximum DC input voltage (often 600 V residential, 1000-1500 V commercial).

Minimum string length must keep Vmp above the inverter's MPPT start and operating window at the highest expected cell temperature (roughly 65-70 °C at the module surface).

Temperature coefficients: Voc falls about 0.25-0.35%/°C and Pmax falls about 0.30-0.45%/°C above 25 °C; use cell temperature, not ambient, for these corrections.

Module selection tradeoffs: efficiency (W/m²), temperature coefficient, degradation warranty, bifaciality, and inverter compatibility; higher Voc modules reduce conductor current but shorten maximum string length.

Inverter selection: string inverters for unshaded uniform arrays, DC optimizers or microinverters where module-level MPPT, per-panel monitoring, or shade mitigation is needed; check CEC efficiency and nighttime consumption.

Conductor sizing: ampacity must exceed 1.25 × Isc for continuous current, and voltage drop should stay under about 2% on the DC home run and 2% on the AC run to protect production.

Rapid shutdown (NEC 690.12) requires conductors within the array boundary to be limited to 80 V within 30 seconds of shutdown; module-level electronics or a listed shutdown device satisfy this.

Racking and attachment: choose roof-mount, ground-mount, or ballasted based on wind and snow loads; verify UL 2703 listing for bonding and grounding of the module-to-rail connection.

Simple payback (years) = net installed cost ÷ first-year annual savings; it ignores escalation and inverter replacement, so pair it with a 25-year cash-flow model.

Levelized cost of energy: LCOE = (total lifecycle cost, present-valued) ÷ (total lifetime kWh produced, present-valued); compare it to the customer's blended utility rate.

Federal residential credit is 30% of qualified installed cost under the residential clean energy credit, claimed via IRS Form 5695; commercial projects use the investment tax credit on Form 3468.

ITC basis excludes any portion of the system funded by a non-taxable grant or rebate; include racking, labor, permits, and electrical upgrades, but exclude structural roof repair.

Depreciation for commercial systems: MACRS 5-year schedule with bonus depreciation where available; the ITC reduces the depreciable basis by 50% of the credit amount.

Utility bill savings = kWh offset × applicable retail or TOU rate; export compensation depends on net metering, net billing, or avoided-cost rates, which vary by state and utility.

Incentive stacking order: apply rebates and grants first to reduce cost basis, then the tax credit, then state credits or SREC income; confirm each program's rules on double-dipping.

Financing comparison: cash purchase maximizes lifetime return; loans add interest but retain the credit; leases and PPAs shift risk to the third party at the cost of lower customer savings.

A complete proposal states system size (kW-DC and kW-AC), module and inverter models, estimated annual kWh, offset percentage, net cost after incentives, and production assumptions.

Production estimates should cite the modeling tool and inputs (weather file, shading, soiling, availability); P50 is the median estimate and P90 is the conservative value used for financial guarantees.

Permit packages typically require a site plan, single-line electrical diagram, structural letter, module and inverter datasheets, and UL listings; AHJ turnaround can run 2-8 weeks.

Interconnection application goes to the utility separately from the building permit; approval timelines and any upgrade costs must be disclosed before contract signing.

Contract essentials: scope, price and payment schedule, change-order process, estimated completion, warranty terms, cancellation rights, and clear assignment of incentive responsibility.

Sales ethics: never quote a production number without a shading and weather basis, never guarantee an incentive amount, and disclose that utility rate structures can change.

Warranty stack to present: module product (10-25 yr) and power (25-30 yr), inverter (10-25 yr), rack (10-25 yr), workmanship (typically 5-10 yr), and production guarantee if offered.

Commissioning and handoff: verify rapid shutdown, labeling, monitoring activation, and deliver an as-built package with O&M instructions and shutdown procedure to the customer.

NEC 690 governs PV systems; 690.7 covers maximum voltage, 690.8 conductor ampacity (125% of Isc), 690.12 rapid shutdown, and 690.13 disconnecting means.

NEC 705.12(B) busbar rules: the 120% rule permits (main breaker + PV breaker) ≤ 1.2 × busbar rating when the PV breaker is at the opposite end from the utility feed.

Supply-side connection taps the service conductors ahead of the main breaker and is not limited by the busbar rule, but requires utility approval and a service disconnect.

NEC 250 grounding and bonding: module frames and racking must be bonded to the equipment grounding conductor; UL 2703 listed racking provides listed bonding paths.

Arc-fault protection (NEC 690.11) is required on DC circuits of 80 V or more; ground-fault protection (690.5) is required for grounded and many ungrounded arrays.

Labeling requirements include the DC disconnect, the point of interconnection, rapid shutdown equipment, and a plaque stating the system voltage and current at the service.

Net metering and interconnection rules follow IEEE 1547 and state public utility commission tariffs; systems above certain kW thresholds may need additional studies.

Workplace safety: OSHA fall protection at 4 ft general industry or 6 ft construction, lockout/tagout before servicing, and PPE for DC arc hazards; PV modules are energized whenever illuminated.

Expected performance ratio (PR) for a well-designed system is roughly 0.75-0.85; a sustained drop of more than about 10% from the modeled baseline warrants investigation.

Performance monitoring compares actual kWh to a weather-adjusted model; normalize using irradiance data so seasonal variation is not mistaken for a fault.

Common underperformance causes: soiling, snow cover, shading growth from vegetation, inverter derating or faults, string failure, and blown fuses.

IV curve tracing and insulation resistance testing locate ground faults, failed bypass diodes, and connector degradation without removing modules.

Thermal imaging identifies hot spots, cell cracks, and loose terminations; a temperature rise of more than about 10 °C above neighboring cells is a flag.

Inverter replacement is typically the largest O&M cost over 25 years; budget for one replacement around year 10-15 for a 10-15 year rated inverter.

Warranty claims require documented monitoring data, serial numbers, and commissioning records; keep an O&M log of service visits and measured values.

Customer communication: set expectations for seasonal output, explain monitoring alerts, and provide a service escalation path with response-time commitments.