Registered Public Utility Engineer - Power cheat sheet

Reserve margin = (installed capacity − peak demand) / peak demand; planning reserve margin targets commonly fall in the 15–20% range for summer-peaking systems, set by the applicable balancing authority or state commission.

Loss of Load Expectation (LOLE) is expressed in days per year (common target: 0.1 day/yr, i.e., one event in ten years); Loss of Load Probability (LOLP) is the hourly or daily probability summed over the study period.

Expected Unserved Energy (EUE) is in MWh/yr and captures outage magnitude, not just frequency; a system can meet LOLE and still fail an EUE criterion.

Effective load-carrying capability (ELCC) credits a variable resource by the peak-load increase it can reliably serve; solar ELCC is typically far below nameplate and lower than wind in a summer-peaking system.

Hourly load shapes drive planning more than annual energy: coincident peak contribution, not capacity factor, determines capacity value of demand response and storage.

Forecast error compounds with horizon: near-term (1–5 yr) forecasts anchor on econometric and end-use models, long-range (10–20 yr) on scenario and weather-normalized trend methods.

Weather normalization regresses load against heating/cooling degree days; failing to normalize biases the forecast and distorts the load growth rate used in integrated resource plans.

Transmission and generation must be planned together: a resource adequacy study that ignores deliverability can count capacity that cannot reach load under contingency conditions.

Three-phase power: S = √3 · V_LL · I · (cos θ + j sin θ); per-phase analysis uses V_LN = V_LL / √3 and total S = 3 · V_LN · I*.

Per-unit conversion: Z_pu = Z_actual / Z_base, with Z_base = V_base² / S_base; changing base requires Z_pu,new = Z_pu,old · (S_new/S_old) · (V_old/V_new)².

Voltage drop on a feeder approximates ΔV ≈ I·R·cos θ + I·X·sin θ per phase; distribution feeders are resistance-dominated, transmission lines reactance-dominated.

Surge impedance loading (SIL) = V_LL² / Z_c; a line loaded near SIL has flat voltage profile and minimal reactive requirement.

Transformer impedance and MVA rating set fault current: I_sc ≈ I_rated / Z_pu (for a source of infinite strength), so lower percent impedance raises available fault current.

Corona and radio interference rise with surface voltage gradient; conductor bundling and larger diameter reduce gradient and audible noise at EHV.

Distribution reliability indices: SAIDI = total customer-minutes interrupted / total customers served; SAIFI = total customer interruptions / total customers served.

Ampacity is set by conductor temperature limit under worst-case ambient and wind; reconductoring or dynamic line rating can raise transfer capability without new right-of-way.

Power flow (load flow) solves bus voltage magnitudes and angles from P-Q injections; the slack bus fixes V and θ, PV buses fix P and |V|, PQ buses fix P and Q.

N-1 criterion: the system must survive the loss of any single element without cascading or uncontrolled loss of load; N-1-1 adds a second contingency during repair.

Symmetrical components: positive, negative, and zero sequence networks; zero-sequence current flows only where a ground path exists, so a delta winding blocks it.

Protection zones must overlap; overlapping CTs and redundant schemes ensure no fault is unprotected and no zone trips for an out-of-zone fault.

Distance relay reach is set in secondary ohms and scaled by the CT/VT ratio; Zone 1 typically covers about 80% of the line to avoid overreaching into the next line.

Differential protection compares currents entering and leaving a zone; it is the standard for transformers, buses, and generators because it is inherently selective.

Stability: the equal-area criterion shows the critical clearing time is the fault duration beyond which the accelerating area exceeds the decelerating area and the generator loses synchronism.

Automatic voltage regulators and power system stabilizers damp oscillatory modes; undamped inter-area oscillation appears as low-frequency (0.1–1 Hz) power swings.

Revenue requirement = operating expenses + depreciation + taxes + (rate base × authorized rate of return); rate base is net plant in service plus working capital less accumulated depreciation.

Cost-of-service study allocates costs by function (production, transmission, distribution, customer), then by classification (demand, energy, customer), then to rate classes by responsibility.

Demand allocators use class contribution to system peak, class noncoincident peak, or average-and-excess methods; the choice shifts cost between classes and is litigated.

Rate design: two-part tariff = customer charge + volumetric energy charge; demand charge recovers demand-related cost and is set from class coincident or noncoincident peak.

Straight-fixed-variable and three-part rates recover fixed cost through fixed charges, reducing the cross-subsidy from low-use to high-use customers under volumetric rates.

Depreciation uses straight-line remaining-life or whole-life methods; depreciation expense plus return on rate base is the annual carrying cost of plant.

Test year selection (historical, future, or hybrid) determines whether known-and-measurable cost changes enter the revenue requirement; attrition relief addresses lag between rate cases.

Decoupling and revenue stabilization mechanisms break the link between sales volume and revenue, removing the utility incentive to oppose efficiency.

Filed tariffs govern service; a utility may not charge outside its filed tariff, and deviations require commission approval or a tariff-authorized exception.

Cost-of-service ratemaking requires just and reasonable rates, no undue discrimination between similarly situated customers, and recovery of prudently incurred costs.

Rate case procedure: file, notice, intervention, discovery, hearings, proposed decision, commission vote; interim rates may be authorized subject to refund.

Fuel and purchased-power adjustment clauses pass through variable costs with a reasonableness review; prudency challenges can disallow recovery.

Federal versus state jurisdiction: wholesale sales and interstate transmission are federally regulated; retail sales, distribution, and siting are generally state-regulated.

Compliance obligations include FERC reporting, NERC reliability standards with auditable evidence, and state-mandated renewable portfolio targets with alternative compliance payments.

Tariff riders recover specific costs (storm, environmental, energy efficiency) outside base rates; each rider has eligibility, true-up, and reconciliation requirements.

Confidentiality rules govern critical energy infrastructure information and customer data; unauthorized disclosure is a compliance violation, not just a policy breach.

Voltage limits: ANSI Range A service voltage is ±5% of nominal; Range B allows ±10% excursions of limited duration. Utilization voltage limits are tighter at the service entrance.

Frequency deviation is governed by balancing area control; normal interconnection frequency is 60 Hz in North America, with underfrequency load shedding staged below nominal.

Harmonics: IEEE 519 limits voltage distortion at the point of common coupling (typically 5% THD) and current distortion by customer size relative to short-circuit ratio.

Flicker is assessed by short-term and long-term Pst/Plt indices; arc furnaces and welders are the usual sources and may require mitigation as a condition of service.

Reliability standards set transmission planning and operations requirements; violations carry monetary penalties scaled by severity and duration.

Temporary protective grounding, minimum approach distances, and equipotential zones govern live-line work; approach distances increase with voltage class.

Arc flash incident energy determines PPE category; an energized-work permit is required when work inside the arc flash boundary cannot be de-energized.

Momentary interruptions (sags, recloser operations) are counted separately from sustained interruptions; a sustained interruption typically exceeds five minutes.

Interconnection process: feasibility, system impact, and facilities studies; the interconnection agreement and cost allocation follow the study results.

Interconnection queue rules govern study order and deposit forfeiture; cluster-study approaches process many requests together to reduce serial study delay.

Network upgrade costs are allocated by the interconnection tariff; identifying which upgrades are caused by the generator versus needed for reliability is the central dispute.

Siting approvals typically require a certificate of public convenience and necessity plus separate environmental permits for air, water, wetlands, and endangered species.

National Environmental Policy Act review triggers an environmental assessment or a more extensive environmental impact statement for major federal actions.

Endangered species and cultural resource surveys must precede construction; a late finding can halt a project mid-schedule.

Clean Air Act permitting distinguishes minor sources from major sources; new-source review can require best available control technology and emission offsets.

Transmission line siting considers right-of-way width, electromagnetic field exposure, visual impact, and landowner compensation; eminent domain is a last resort requiring statutory authority.

IEEE 1547 governs DER interconnection to the distribution system: voltage and frequency ride-through, anti-islanding, and power quality requirements apply at the point of common coupling.

Smart inverter functions (volt-var, volt-watt, frequency-watt) let DER support voltage and frequency rather than trip offline, reducing aggregate loss during disturbances.

Hosting capacity is the DER penetration a feeder can accommodate without violating voltage, thermal, or protection limits; it is computed per feeder and per location.

Duck curve: midday solar depresses net load and the evening ramp steepens; ramping capability, not total energy, becomes the binding constraint.

Inverter-based resources lack physical inertia; grid-forming inverters and synchronous condensers provide synthetic inertia and short-circuit strength.

Net metering and successor tariffs determine DER compensation; the compensation method affects the cross-subsidy between DER owners and non-owners.

Aggregated DER can provide capacity, frequency response, and voltage support; qualification requires telemetry, dispatchability, and performance testing.

Curtailment is a cost of oversupply; the economic curtailment threshold compares the value of energy against the cost of the upgrade that would avoid it.

Health index scoring combines condition, age, loading, and failure history to rank assets; the score drives repair, refurbish, or replace decisions.

Risk = probability of failure × consequence (safety, environmental, reliability, financial); risk-ranked portfolios allocate limited capital to the highest-risk assets first.

Condition monitoring: dissolved gas analysis for transformers, partial discharge testing for cables and switchgear, thermography for connections.

Preventive maintenance intervals are set by manufacturer guidance, regulatory requirements, and observed failure modes; time-based and condition-based programs are combined.

Critical spares strategy weighs lead time, failure rate, and outage cost; long-lead transformers justify strategic spares or sharing agreements.

Outage management coordinates clearances, switching orders, and restoration; switching orders are written, checked, and read back to prevent misoperation.

Vegetation management is a leading driver of distribution reliability; cycle trimming intervals are set by species growth rate and clearance requirements.

End-of-life replacement planning uses failure probability curves and expected outage cost to time replacement before reliability degrades.

The engineer's paramount obligation is public health, safety, and welfare; a client or employer instruction does not override it.

Seal only work you prepared or directly supervised; sealing another's work without review is a violation regardless of employment relationship.

Disclose conflicts of interest, including financial interests in suppliers or contractors, in writing before participating in a procurement decision.

Records retention: calculations, test results, and design bases must be retained for the period required by statute and by the utility's records schedule, and produced on request in rate cases and litigation.

Ex parte communication rules restrict contact with commissioners and staff during contested proceedings; violations can taint a proceeding.

Whistleblower and reporting duties: report known violations of reliability, environmental, or safety requirements to the appropriate authority even if internal channels fail.

Testimony and discovery require truthful, complete disclosure; withholding adverse data from a regulatory filing is a professional misconduct issue, not a strategy.

Competence limits: accept assignments only within your competence, and obtain qualified review when a task exceeds your expertise.