Hydropower Plant Step-Up Transformer: How to Size a GSU for 10–300 MW Units, Why Load Rejection and Start-Stop Cycling Drive the Spec, and How Hydro Duty Differs from Solar or Wind

The answer first: a hydro GSU is a cyclic-duty generator transformer, not a scaled-up distribution transformer

A hydropower plant step-up transformer (GSU) is sized from the generator's rated apparent power, not from the turbine's MW: at 0.90 power factor a 60 MW unit is a 66.7 MVA generator, so the transformer is a 75 MVA unit, not a 60 MVA one. On top of that nameplate, three duties are added that never appear on a distribution transformer: daily start-stop thermal cycling, load-rejection overvoltage and over-fluxing, and a wide high-voltage band at remote weak-grid sites. For a typical 60 MW, 13.8 kV machine the answer is a 13.8/115 kV, YNd11, 75 MVA GSU at roughly 10.5% impedance with ONAN/ONAF cooling, an on-load tap changer on the HV neutral, and a specified over-flux capability of 1.10 pu continuous and 1.25 pu for one minute. Fix those four numbers — MVA, impedance, tap range and over-flux — and the remaining specification is mostly a consequence of them.

Key takeaways

• Size the GSU on generator MVA at its rated power factor (0.85–0.95, typically 0.90) and add 5–10% headroom: a 60 MW unit needs 75 MVA, and a 150 MW unit needs 180–190 MVA.
• Hydro GSUs are thermally cycled, not thermally steady. A peaking unit may take 1–4 starts per day and a pumped-storage unit 2–10 load cycles per day, so the loading guide that matters is IEC 60076-7 / IEEE C57.91, not the continuous rating alone.
• Load rejection is the design overvoltage case: guide-vane closure in 5–20 s can push the HV bus 15–30% above nominal before the AVR and governor settle, which is why over-flux capability and HV surge arresters are specified together.
• Impedance of 10–15% is a system decision, not a catalogue value. Lower impedance improves voltage regulation and reactive capability but raises the HV fault level and the breaker rating you have to buy.
• Hydro is a low-harmonic application — a synchronous generator produces a near-sinusoidal output — so K-factor rating is usually unnecessary, unlike a solar or wind GSU fed by inverters. The exceptions are static frequency converters for pumped-storage starting and doubly-fed variable-speed units.

What does the step-up transformer actually do in a hydro plant single-line diagram?

The GSU is the interface between the generator voltage class (6.6–18 kV) and the transmission class (33–500 kV). In a unit arrangement the chain is: generator → isolated-phase bus → generator circuit breaker (or load-break switch) → GSU low-voltage winding → GSU high-voltage winding → HV circuit breaker → station switchyard. The unit auxiliary transformer is tapped either at the generator terminals or at the GSU LV side, and it supplies the plant's own loads — cooling water pumps, excitation, governor hydraulics, drainage, ventilation and the control system.

Three consequences follow from that position in the diagram, and they explain most of the specification differences between a GSU and a distribution transformer:

• The LV winding sees generator fault current, not system fault current. A synchronous generator contributes roughly 5–7 times rated current for the first 100–200 ms of a terminal fault, with a high DC component. The LV winding, its bushings and its bracing must be designed for that waveform, which is why GSUs are specified against IEEE C57.116 (transformers directly connected to generators) as well as IEC 60076-5.
• The HV winding is the only path to earth for generator zero-sequence current. With a YNd11 group the delta LV winding blocks zero-sequence from the generator, and the HV star point is earthed — solidly, through a reactor, or through a grounding transformer depending on the system's earth-fault current limit. Get the vector group or the neutral arrangement wrong and the generator's stator earth-fault protection loses its reference.
• The transformer is switched with the unit, not with the load. Every start is an energisation from the HV side into a transformer whose core may still hold residual flux, followed by synchronisation. That is an inrush and switching-overvoltage duty repeated thousands of times over life, not a one-off commissioning event.

If you are still at the stage of converting a load list into kVA, the sizing method in transformer sizing and budget in one step applies to the auxiliary system; the GSU itself is sized from the machine, as described below.

Unit GSU, common GSU or generator busbar: which arrangement fits the plant?

Before the transformer is sized, the plant's arrangement decides how many transformers there are and what redundancy you are buying. There are three standard topologies, and hydro plants use all three.

For plants with more than about four units, the unit arrangement almost always wins on availability: one GSU outage costs one unit, whereas a common GSU outage costs the whole plant. That availability argument, not the transformer price, is usually what decides the layout in a bankable feasibility study.

How do you size a hydro GSU in five steps?

The calculation is short but the inputs are frequently wrong in tenders, because the turbine MW is quoted where the generator MVA is needed.

1. Convert MW to MVA at the generator power factor. MVA = MW / cosφ. A 60 MW machine at 0.90 pf is 66.7 MVA. Hydro generators are typically 0.85–0.95 pf, with 0.90 the most common value for units above 20 MW; low-head Kaplan units sometimes go to 0.95 to reduce machine size.
2. Add the design margin. The GSU is rated at 1.0–1.1 times generator MVA. Going below 1.0 is a false economy: the transformer then limits the machine, and the overload is paid for in hot-spot temperature for the rest of its life.
3. Fix the voltage ratio from the machine and the connection point. Generator voltages of 6.6 kV (up to roughly 50 MW), 10.5/11 kV (30–100 MW), 13.8/15.75 kV (100–300 MW) and 18–20 kV (above 300 MW) are standard; the HV side follows the grid connection study.
4. Choose impedance from the fault-level study. Typical GSU values are 10–12% for 110–145 kV, 12–14% for 220–245 kV and 14–16% for 400–500 kV. Check the result against the HV breaker rating and the generator's own decrement curve.
5. Confirm cooling, ambient and altitude, then re-rate. A design that is 100% at 40 °C ambient and sea level is not 100% at 1,500 m and 45 °C; both the cooling-air mass flow and the external insulation change.

The table is a starting point, not a specification. A 300 MW machine at 15.75 kV draws about 12.2 kA at full load, which is why large hydro generators move to 18–20 kV and why the LV bushing, the isolated-phase bus and the generator circuit breaker become the mechanical bottlenecks rather than the winding itself.

Which impedance should you specify, and why is lower not automatically better?

Impedance is where the electrical, mechanical and commercial sides of a hydro project meet. Lower impedance gives better voltage regulation, a smaller reactive drop at full load and more headroom for the generator's reactive capability; it also lets a fault at the generator terminals be fed harder by the system, and it increases the fault current that the generator circuit breaker, the LV bushings and the winding bracing must survive. Higher impedance limits those currents but increases the reactive consumption at full load and makes parallel operation with a neighbour's transformer less forgiving.

Two rules keep the decision honest. First, impedance must satisfy the HV switchyard's fault level with the plant at maximum generation and the local network at minimum impedance — the calculation method is the same one used in the three-step short-circuit current calculation, with the generator's sub-transient reactance as the source. Second, when two or more GSUs operate in parallel on the same HV busbar, their impedances should match within about ±7.5% of the mean, otherwise the units share reactive load unequally — the mechanism is explained in the five conditions for parallel operation.

A practical note from project experience: on a weak 110 kV network at the end of a long line, the impedance choice is often driven by voltage regulation rather than by fault level, and the transformer ends up at 9–10% against a nominal 12%. On a stiff 220 kV busbar the opposite happens, and 13–14% is used to keep the HV breaker cost down. There is no universal value; there is only the value that satisfies both studies.

Does head variation change the transformer ratio? What really drives the tap range

No — and this is one of the most persistent misconceptions in hydro specifications. The generator's automatic voltage regulator holds terminal voltage constant as head changes, so the GSU ratio does not have to follow the water level. What head variation changes is the unit's power capability and its position on the capability curve: at part head the machine produces less MW at the same MVA, which means it runs at a lower power factor for the same MW export and draws more reactive power from the GSU.

The tap range is driven by the high-voltage side, and by how weak that network is:

• Remote plant, long transmission line. The sending-end voltage at the plant rises and falls with the line's charging and the receiving-end load, often over a band of ±8–10%. This is the dominant driver in run-of-river and mountain schemes.
• Grid voltage regulation duty. Where the plant is expected to hold the local busbar voltage, the OLTC works daily, and the tap range must cover the full contracted band without exceeding the transformer's flux limit at the top end.
• Generator voltage tolerance. Generators are specified for ±5% voltage variation at rated output (IEC 60034-1). The GSU must deliver rated HV voltage at the bottom of that band, which adds roughly 5% to the required turns ratio.
• Pumped storage and condenser operation. Units that run in synchronous condenser mode or reverse rotation need a wider band, because the machine may operate at reduced voltage while absorbing reactive power.

The practical outcome: a unit GSU on a stiff 220 kV busbar is often specified with a de-energised tap changer of ±2 × 2.5%, while a GSU at the end of a 150 km 110 kV line typically gets an on-load tap changer of ±8 × 1.25% or ±10 × 1.5%. The comparison of OLTC and DETC economics, including the 10–20% price premium, is set out in on-load versus off-load tap changer. On a GSU the tap changer is normally placed at the HV neutral end, where the insulation class — and therefore the cost — is lower than at the line end.

Why is start-stop cycling the governing thermal duty, and how do you calculate it?

A base-load nuclear or large coal transformer sees a nearly constant load for months. A hydro GSU sees a staircase: cold in the morning, two to six hours at 80–100% load, a shutdown, possibly a second block in the evening, and an idle night with the oil cooling to ambient. Every one of those transitions is a thermal cycle of the winding, the core and the oil, and the mechanical consequence is expansion and contraction of the conductor and the pressboard insulation.

The calculation uses the same cyclic-loading framework as any power transformer, but the input is a daily load curve rather than a single number:

1. Build the 24-hour load profile in per-unit of rated MVA, including the idle periods.
2. Compute the top-oil and hot-spot temperature trajectory using the exponential thermal model of IEC 60076-7 (or IEEE C57.91), with the unit's oil time constant — typically 2–4 hours for a 75 MVA ONAF unit.
3. Check that the hot-spot stays below 98 °C for normal cyclic life, and that the daily swing does not exceed the pressboard's clamping range. A useful rule is that a cyclic load with a 6-hour peak may exceed the continuous rating by 10–20%, but only if the hot-spot limit is respected — the method is the same as in how much you can load a transformer.
4. Repeat for the worst week of the year, not the average day: the design case is usually a hot week with the unit at peak for two blocks and the cooling water at its design maximum.

Two hydro-specific effects make cycling harsher than the load curve alone suggests. First, on shutdown the oil cools and the tank "breathes in" moist air; in a humid powerhouse this is the main route by which water enters the oil, which is why free-breathing conservators are being replaced by sealed or conservator-with-diaphragm designs and why silica-gel breathers are sized for the actual number of cycles. Second, each start applies a full inrush current with its associated winding movement; the phenomenon and its harmonic signature are covered in transformer inrush current. A GSU that starts twice a day for forty years accumulates around 29,000 energisations — a number worth writing into the specification so that the winding clamping and the OLTC are designed for it.

What happens at load rejection, and how do you specify for it?

Load rejection is the event that separates a hydro GSU specification from a thermal one. When the HV circuit breaker opens at full load, the generator is left with its excitation and no load. The governor closes the guide vanes in 5–20 s, but during that window the machine accelerates, the AVR holds terminal voltage, and the HV winding voltage can rise 15–30% before the unit stabilises. The transformer is then over-excited: the volts-per-hertz ratio exceeds 1.0, the core saturates, the exciting current rises steeply and the stray flux heats the tank walls, the clamping plates and the core edges.

Four specification items address it directly:

• Over-flux capability. Specify 1.10 pu continuous (at rated voltage and frequency), 1.25 pu for 1 minute and 1.40 pu for 5 seconds, and require the manufacturer to state the calculated flux density at each point. Values in this range are the common tender requirement; the design limit is usually the temperature of the metallic structural parts, not the core lamination itself.
• Overvoltage protection coordination. ZnO surge arresters at the HV terminals, with the residual voltage coordinated to the transformer's basic lightning impulse insulation level (BIL) and the neutral insulation. The selection logic is the same as in transformer lightning protection.
• Over-excitation protection (24/59 relay). A V/f element with an inverse-time characteristic, set below the transformer's capability curve and above the generator's continuous V/f limit, and coordinated with the AVR.
• Frequency range. Islands and weak grids drift; specify continuous operation at 48.5–50.5 Hz (or 58.5–60.5 Hz) and short-time operation down to 47 Hz, because a 3% frequency dip at rated voltage is already a 3% over-flux condition.

Load rejection also produces a mechanical event: the abrupt loss of load and the subsequent re-application after synchronisation stress the winding clamping and the lead supports. Units that reject load frequently should be specified with the same short-circuit withstand test requirement as a baseload unit, and the factory test report should show the measured short-circuit reactance before and after the test.

How does a hydro GSU differ from a solar or wind step-up transformer?

The three renewable applications all step up from a low voltage to a collector or transmission voltage, but their duty is completely different. This table is the fastest way to see where a hydro specification must diverge.

The most common error in a hybrid tender is to reuse one transformer datasheet across all three applications. A solar GSU specified with a K-factor and 6% impedance will not survive a hydro load-rejection case, and a hydro GSU specified with 13% impedance and a wide OLTC is an expensive over-specification on a PV plant. The application-specific detail for the other two is in solar PV step-up transformers and wind farm step-up transformers.

Cooling, losses and the loss-capitalisation calculation

Hydro GSUs are usually specified with two or three cooling stages so that the unit can run at reduced rating with one cooler bank out of service. The stage names follow IEC 60076-2 and describe the coolant circulation:

Because a hydro GSU runs for decades, the loss evaluation is not a formality. The standard approach is to capitalise no-load and load losses with the buyer's own coefficients: an evaluation price A for each kW of no-load loss and B for each kW of load loss, both in USD/kW, derived from the plant's expected operating hours and the marginal cost of energy. For a peaking unit running 2,500 equivalent full-load hours per year, B is typically lower than for a baseload unit, which shifts the optimum towards lower no-load loss — that is, towards a larger core and a higher purchase price. The full method, including how the coefficients change the winning bid, is in transformer total cost of ownership. A 75 MVA GSU at 99.5% efficiency dissipates about 375 kW at full load; over 2,500 hours that is roughly 940 MWh per year, which is why a 0.1 percentage point efficiency difference is worth arguing about in a tender.

Temperature-rise limits deserve the same attention. The IEC 60076-2 reference is a 60 K top-oil rise and a 65 K average-winding rise over a 20 °C ambient, with the hot-spot limited to 98 °C for normal cyclic life under IEC 60076-7. In a powerhouse at 35 °C ambient with the unit at 110% load for four hours, those limits are reached sooner than the nameplate suggests. Asking for a 55/65 K design is a legitimate way to buy margin, at a cost of roughly 5–8% more copper and core — the trade-off is quantified in transformer cooling methods and temperature rise.

Altitude, humidity and the powerhouse environment

Many hydro sites sit between 1,000 and 3,000 m, and almost all of them are humid. Both conditions change the transformer, and both are frequently left out of the datasheet.

• Cooling derating. Air density falls by roughly 8–10% per 1,000 m of altitude, so the fans move less mass and the radiators reject less heat. Above 1,000 m the rating must be reduced, or the cooler bank enlarged, by an amount the manufacturer should calculate and state.
• External insulation. The withstand voltage of bushings and of the external clearance falls with air density; IEC 60071-2 gives the altitude correction factor, and the BIL selection must account for it. The bushing creepage distance is separately set by the pollution level — a powerhouse near a river valley with fog is not a clean environment.
• Condensation. A unit that runs four hours a day spends most of its life cold. Without space heaters, tank heaters or an oil-circulation heater, water condenses on the tank walls and migrates into the oil. Specify the heater rating, the thermostat setting and the breather type explicitly, and check the oil's water content at every service interval.
• Seismic and structural. The powerhouse floor is often a rock-founded structure with its own dynamic response; the transformer's anchorage and the bushing's cantilever strength must be checked against the site spectrum, not against a generic Zone 2 assumption.

The altitude correction method and worked derating factors are in high altitude and high temperature derating; the oil and bushing choices are in transformer oil types compared and transformer bushing guide.

Which tests prove the unit is ready for forty years of cycling?

The routine test list for a GSU follows IEC 60076-1, but a hydro specification should add three items that are optional in the standard and essential in practice.

Two of these deserve a sentence in the purchase order rather than a reference in the standard. FRA must be measured before transport and again after erection, so that a transport shock can be distinguished from a design issue; the comparison is only meaningful if the factory baseline exists. And partial discharge should be measured with the test tap on the HV bushing, at 1.5 Um/√3, with a declared limit in picocoulombs — a limit that the factory test report actually states, not one that is "in accordance with the standard". The site-side counterpart of this list is in the eight pre-energisation commissioning checks, and the factory audit that verifies the manufacturer can actually perform these tests is in the twelve-point factory audit.

How do you write the technical schedule for a hydro GSU tender?

A hydro GSU datasheet that is written as a list of "typical" values invites the cheapest compliant offer. A datasheet written as a set of calculated duties invites a design. The twelve lines below cover what a serious enquiry contains:

1. Rated power and voltage ratio, stated as generator MVA at the generator power factor, with the guaranteed impedance at the rated tap.
2. Frequency, number of phases and vector group (YNd11 for most unit GSUs), with the HV neutral brought out and its insulation level stated.
3. Tap range and tap-changer type, with the number of expected OLTC operations per year and the required through-current.
4. Impedance and its tolerance, plus the permissible deviation between parallel units.
5. Cooling stages and their ratings (for example ONAN 45 MVA / ONAF 75 MVA), with the ambient and altitude design points and the derating curve.
6. Loss guarantees in kW, with the evaluation prices A and B and the penalty formula for exceeding them.
7. Temperature-rise limits and hot-spot guarantee, with the reference ambient and the cyclic-loading curve.
8. Insulation levels (LI/SI/AC) for HV, LV and neutral, coordinated with the surge arresters and corrected for altitude.
9. Short-circuit withstand in kA and duration, derived from the generator decrement, not from the HV system alone.
10. Over-flux capability at 1.10/1.25/1.40 pu, with the calculated flux density stated by the manufacturer.
11. Tests: the routine list, plus the special tests you require (short-circuit, PD, FRA, sound), plus the factory acceptance test witness plan.
12. Transport and erection boundary: maximum piece weight, oil filling state, nitrogen pressure, impact recorder, and who owns the road survey and the crane.

Line 9 is the one most often written by copying a distribution transformer enquiry. A hydro GSU's LV winding must withstand a generator-fed fault, whose magnitude and DC offset are not the same as a system-fed fault; specifying "25 kA for 2 s" without deriving it from the machine's sub-transient reactance and decrement curve is how a transformer ends up over- or under-designed by a factor of two.

What does a hydro GSU cost, and how do you compare bids?

GSU prices are quoted per unit, but they only become comparable when normalised to USD/kVA at a stated voltage class, tap changer, cooling and test scope. The ranges below are indicative FOB levels for Chinese-manufactured units in 2025–2026, from project experience rather than a published index; they move with copper and grain-oriented steel prices and with the OLTC brand.

Three normalisation rules turn a price list into a comparison. First, convert every offer to the same loss evaluation: a bid that is 4% cheaper but 15 kW higher in no-load loss can be the more expensive transformer over twenty years. Second, compare the guaranteed impedance and the guaranteed temperature rise, because both can be met on paper by adding material — or missed in reality by leaving it out. Third, compare the test scope: a unit offered without short-circuit withstand, PD and FRA is not the same product as one offered with them, and the difference is typically 2–4% of price. The distribution-level version of this analysis, including how freight and duties change the landed cost, is in distribution transformer price breakdown and total cost of ownership.

Six specification mistakes that shorten hydro GSU life

1. Sizing on turbine MW instead of generator MVA. A 60 MW unit at 0.90 pf needs 75 MVA of transformer; a 60 MVA order runs the unit at 111% of rating from the day it is commissioned.
2. Leaving the over-flux requirement out. The transformer passes every routine test, then saturates on the first load rejection and heats its clamping structure. The damage appears as gassing two or three years later.
3. Specifying a tap range from a catalogue instead of from the grid study. A ±2 × 2.5% DETC on a remote 110 kV site leaves the operator unable to hold voltage at the top of the band, and the unit runs at 1.08 pu flux permanently.
4. Treating the auxiliary transformer as an afterthought. The unit auxiliary load is tapped at generator voltage, and its fault contribution adds to the GSU LV fault current; protection coordination between the two is a design task, not a footnote.
5. Ignoring transport reality. A 220 kV, 180 MVA three-phase unit may weigh 220 t with oil; the mountain road to the site may allow 80 t per piece. Deciding between a three-phase unit and a single-phase bank after the order is placed is expensive — see transformer transportation and installation.
6. Buying on price without a factory audit. Winding clamping pressure, core stacking factor and oil processing are not visible in a datasheet, and they are exactly what a cycling duty tests. The audit checklist is in how to vet a transformer manufacturer.

If the plant also includes a solar or wind hybrid component, run two separate specifications rather than one compromised datasheet: the duty cycles, harmonic environment and impedance targets genuinely differ, and the difference is quantified in the comparison table above.

Frequently asked questions

Can a distribution transformer be used as a hydro GSU?

Only for very small units, and only after checking three things: the LV winding's ability to withstand generator-fed fault current, the over-flux capability at load rejection, and the tap range needed at the connection point. A standard distribution transformer is designed for a system-fed fault, a modest overvoltage and a fixed ratio; a 5 MW micro-hydro unit can sometimes use a suitably specified distribution-class unit, but above about 10 MVA the generator duty dominates the design and a GSU is the correct purchase.

Should the tap changer be on the high-voltage side or the low-voltage side?

On the HV side, normally at the neutral end. The LV side carries the generator's full current at a low voltage, so a tap changer there would be large, hot and expensive; the HV neutral end carries the same current but at a fraction of the insulation level, which is why GSU tap changers are almost always located there. The exception is a unit with a very wide ratio range where the LV winding's turn count must change, and that is a design decision to take with the manufacturer.

How many OLTC operations should a hydro GSU be specified for?

Count them from the plant's operating regime, not from a generic figure. A unit holding a weak 110 kV busbar may operate its tap changer 5–15 times a day; a unit on a stiff 220 kV busbar with a DETC may operate it twice a year. Specify the annual count and the twenty-year total, and require an OLTC whose mechanical endurance exceeds it with margin — IEC 60214-1 type tests give the reference numbers, but the tender should state the duty explicitly.

Why does the GSU need a wider tap range than a solar transformer at the same site?

Because the hydro unit is often the voltage-controlling element at the end of a long line, while a solar plant typically operates at unity power factor and follows the grid. The hydro GSU is asked to hold the busbar across a band that the line impedance and the receiving-end load create, and that band is wider than the band a PV plant's inverter can tolerate before it trips. The grid study, not the transformer catalogue, defines the range.

Does a hydro GSU need K-factor rating for harmonics?

Usually not. A synchronous generator's output is close to sinusoidal, and the harmonic content at the GSU terminals is typically a few percent, well within a standard transformer's capability. The exceptions are pumped-storage units started through a static frequency converter, and variable-speed pumped-storage units with a doubly-fed machine, where the rotor converter injects harmonics into the stator circuit; those cases need an explicit harmonic loss calculation rather than a K-factor label.

Sources / 资料来源

Source: IEC 60076-1 — Power transformers, Part 1: General.
Source: IEC 60076-2 — Power transformers, Part 2: Temperature rise for liquid-immersed transformers.
Source: IEC 60076-3 — Power transformers, Part 3: Insulation levels, dielectric tests and external clearances in air.
Source: IEC 60076-5 — Power transformers, Part 5: Ability to withstand short circuit.
Source: IEC 60076-7 — Power transformers, Part 7: Loading guide for mineral-oil-immersed power transformers.
Source: IEC 60076-10 — Power transformers, Part 10: Determination of sound levels.
Source: IEC 60076-18 — Power transformers, Part 18: Measurement of frequency response.
Source: IEEE C57.116 — Guide for transformers directly connected to generators.
Source: IEEE C57.91 — Guide for loading mineral-oil-immersed transformers and step-voltage regulators.
Source: IEC 60034-1 — Rotating electrical machines, Part 1: Rating and performance.
Source: IEC 60071-2 — Insulation co-ordination, Part 2: Application guide (altitude correction).
Source: IEC 60137 — Insulated bushings for alternating voltages above 1 000 V.
Source: IEC 60214-1 — Tap-changers, Part 1: Performance requirements and test methods.
Source: IEC 60296 — Fluids for electrotechnical applications: mineral insulating oils.
Source: GB/T 6451-2015 — Technical parameters and requirements for three-phase oil-immersed power transformers.
Source: GB 20052-2020 — Minimum allowable values of energy efficiency and energy efficiency grades for power transformers.
Source: QDTB engineering experience — hydro GSU sizing tables, load-rejection over-flux requirements, tap-range practice at remote 110–220 kV sites, and indicative FOB price ranges. Values marked as industry experience or indicative are typical ranges from hydro and renewable projects, not published standards.