Apple Gate

Upper Black Lake, Photo by Richard Stenzel

Section 2: Interconnection Issues

The development of successful hydropower production depends upon constraining the costs of interconnection and acquiring a power purchase agreement – be it net metering or wholesale power purchase – that supports the project development and ongoing costs.  This chapter discusses the current situations and issues related to electrical interconnection, with particular emphasis on the Grand Valley Irrigation Company sites, where significant interaction with Xcel Energy allowed an estimation of the costs and complexity of interconnecting the survey sites.


Before discussing electrical interconnect methods, it is useful to review of several technical topics which impact the choice of power conversion technology.  Utilities are frequently concerned about the ‘fault current’ produced by distributed generation.  Fault current is a current surge caused by a device when a fault occurs in the power system.  Typical faults include ground faults – an energized line contacting the ground – and phase-to-phase faults – two energized lines contacting each other.  Since all devices respond when a fault occurs, fault currents of all connected devices tend to add up, exacerbating the fault.  Generally, larger inertias cause larger fault currents, as do larger inductive or capacitive electrical components.  For example, a large induction motor driving a heavy turbine (large inductive load, large inertia) produces substantially more fault current than a small motor driving a pump (smaller inductive load, lower inertia).

In addition to fault current, utilities are also concerned about starting and stopping transients caused when a generator connects to the grid.  Before interconnecting a generator, the generator must be “brought into synchronization” with the grid – i.e. generator voltage must be at the same frequency as the grid, in-phase, and at the same magnitude as the grid.  Starting certain components – such as induction generators – can also cause current spikes, which may cause significant voltage fluctuations, or “flicker.”

Most utilities base their interconnect requirements upon the combination of several standards:

  • IEEE 1547.x, which specifies the behavior of an interconnected generation devices.  Inverters (power electronics) are additionally standardized by the related UL 1741 standard.
  • IEEE 519, which specifies allowable power distortion caused by an interconnected generator.
  • IEEE 142, which specifies system grounding rules.
  • ANSI C37, which defines standards for protection relays.
  • National Electrical Codes

However, individual utilities may impose additional requirements.

As discussed in the Interim Report, two primary technical approaches exist for connecting small, distributed generation to the grid – power electronics systems, such as inverters or regenerative, variable-frequency drives, or directly coupled induction or synchronous generators.


Many smaller, distributed generators utilize power electronics – typically an inverter or variable-frequency drive – to interconnect with the electrical power system.  An example drive train is shown in Figure 6. The inverter/drive provides synchronization with the utility, power conversion and controls for power production.  A system controller computes the correct loading on the turbine-generator to maximize power production.  While shown as a single-phase connection, power electronics systems readily connect to three-phase circuits and are routinely utilized for systems of several hundred kilowatts.

Figure 6: Typical Interconnect for Small Turbines

Most power-electronic-based systems can operate the turbine at variable speeds, which can improve efficiency at variable flow rates. Since turbine speed has some impact on water flow through the turbine, some designs can eliminate a variable-flow control device (typically a gate valve), while other designs utilize a traditional gate control.

Well-designed power-electronic systems have low fault currents, can synchronize without significant transients, and require no starting circuit.  Although advanced systems have the reactive power control capability, these generators typically operate at unity power factor. Due to the high speed switching utilized in the power electronics, inverter/drives are typically coupled to an output filter which eliminates high-frequency harmonics.  The filter may be included in the drive system, or may be a site-specific component.

Power electronics introduce an additional conversion step into the power system.  While modern electronics are efficient, some losses are incurred.  Typically, losses are 10-15% at design capacity, but efficiency typically decreases when operating above or below the design point.

Direct Generator Connection

Larger generators typically couple directly to three-phase electrical generators, most often through fixed-ratio shaft couplings, belts or gears.  The generators connect directly to the electrical grid, as shown in Figure 7 (Utility transformer not shown). Direct connection benefits from higher efficiency than the inverter system, but suffers from fewer control options.  Since the generator speed is effectively locked to a fixed grid frequency, the turbine typically rotates at a constant speed. Since speed is fixed, flow control must be provided externally in most cases, either through automatic or manual adjustment of intake gates.  Flow control is necessary for both synchronization and load control.

Figure 7: Typical Interconnect For Larger Turbines

Two types of generators are utilized in directly coupled systems, and each type is started and managed differently:

  • Synchronous generators are started by imitating flow through the turbine to start the system spinning.  Water flow is then regulated to match the generator speed to the grid frequency.  When a match has been achieved, the breaker closes, connecting the generator to the grid.  Water flow may then be increased to generate power.   The starting operation is both complex and sensitive, and generally handled by the unit’s control system.
  • It is important to note that a synchronous machine typically requires a method to actively control water flow to regulate the turbine speed during synchronization.
  • Induction generators are similar to three-phase induction motors utilized for industrial loads.   Induction machines can be started utilizing a motor starter to start the motor and turbine spinning.  The motor starter limits the in-rush current to the motor, and may be required by the utility to reduce local voltage fluctuations (“flicker”). Once spinning, water flow is applied to the turbine to generate power.  Alternatively, induction machines can be started similarly to synchronous machines, although this obviates the most significant advantage of induction machines over synchronous machines.

Synchronous machines are somewhat more efficient than the equivalent induction machine, operating at similar conditions.  However, since industrial induction motors can be utilized as induction generators with proper design consideration, induction generators are often less expensive based upon the high-volume of induction motors.

In either case, the generators are directly coupled to a high-inertia device – the turbine – which is controlled by a slow governor – the flow-control gate.  As a result, fault currents are typically high.  Utilities typically require a delta-wye (Δ-Y) transformer connection, with the generator neutral tied to ground on the secondary side of the transformer.  Electrical equipment must be sized to handle the fault current and slow control response, increasing the interrupt rating of the breaker.  Finally, precautions must be taken to prevent turbine and generator overspeed if the breaker trips at full-power.

Utility and Equipment-Provider View of Interconnection

As a general rule, small hydropower equipment providers appear to favor directly coupled generation systems – most frequently synchronous machines, with a smaller number of induction machines.  This result is unsurprising, given that equipment providers are most frequently selected (graded) on total efficiency and capital cost.  However, purchasers should exercise caution.  While directly-coupled machines have higher efficiency at rated capacity, efficiency may drop off significantly at reduced flows, due primarily to the efficiency curve roll-off of the turbine.  System performance should be analyzed using time-weighted actual flows, not rated capacity. 

In addition, installation of a direct-connect generator is likely to incur additional installation costs, which may not be quoted in the turbine package.  These costs include:

  •  Protection relays[1] required by the utility.
  • Higher interrupt current ratings for breakers.
  • Utilities typically required an engineering study for directly coupled generators (e.g. a fault study and protection coordination study) which may add significant cost.
  • Controllable flow gate

The design of protection and synchronization equipment is not standardized.  Significant variation exists in the implementation of these systems.  A particular concern is the required “anti-islanding” function of the protection equipment, which prevents a synchronous generator[2] or inverter from powering the local utility circuits when they are “black” – i.e. disconnected from the grid. Perhaps unsurprisingly, utilities are therefore nervous about system behavior, and generally require an in-person “witness test” of the system prior to providing interconnect permission. 

Some equipment providers have implemented power-electronic solutions, typically variable-speed solutions based upon regenerative, variable-speed drive technology.  These solutions appear to be driven more by the behavior of the turbine than by an effort to reduce interconnect costs, although cost reduction may be achieved as a side effect.  Inverters/drives typically implement all synchronization and protection functions directly in the inverter.  Quality drive units are factory certified to appropriate standards, particularly UL 1741 and IEEE 1547.x.  Many utilities accept these certifications as a complete solution to synchronization and protection requirements.  In addition, the output stages of an inverter/drive, including the LCL filter, typically have much lower fault currents than an equivalent sized rotating machine.

In contrast with the equipment providers, discussions with Colorado electric utilities[3] indicate a distinct preference for power-electronics, due to the two factors listed above – lower fault currents and standardized interconnect and protection behavior.

For any generator, the utility will require an externally-accessible, lockable, disconnect between the utility and generator for the protection of line crews.  Some utilities may also required a data feed from the generator to the utility’s control (SCADA) system, which may require a 900 or 1800 MHz radio connection, land line or 3G cell phone connection.  On occasion, utilities may also require a remote control or remote lock-out capability.  Given the remote location of irrigation-based hydropower, these communication capabilities may add significant installation and operation costs.

Interconnection Technology Summary

The table below summarizes the technology trade-offs of the two types of power systems:


Power Electronics

Direct Connection

Interconnect protection equip.

  • Protection generally included in inverter/drive system
  • Turbine speed control not required for grid synchronization
  • Requires auxiliary protection equipment
  • Grid synchronization requires speed control turbine speed control

Fault Current

  • Low
  • Delta typically, but Wye connect OK
  • Nominal interrupt rating on breakers.
  • High
  • Typically requires delta-wye connection with grounded neutral.
  • High interrupt rating on breakers

Efficiency @ Rated

  • 85-90% typical
  • >95% typical

Efficiency for flows above/below design capacity

  • Variable speed improves turbine efficiency for some turbine types, but power electronic losses may increase operating away from rated capacity
  • Turbine efficiency may drop off at flows above/below design flows.


  • Filter required.  May or may not be bundled into the drive system.
  • Minimal filtering required.
  • May require a resistor on neutral connection.

Protection Systems

  • Included in inverter/drive
  • Separate, utility-approved, control relay required.

Utility Preference

  • Preferred for small systems
  • ·         Preferred for large systems


Interconnection and Power Sales

Before interconnecting and selling power to the local utility, a power provider must acquire an “interconnect agreement” with the local utility and a “power purchase agreement” with a utility which will purchase the power.  While these two agreements may be with the same entity on occasion, in general they are executed with two different utilities.  This section discusses the interconnection agreement first, followed by a discussion of utility structures common in Colorado, and finally power purchase types and agreements.



An interconnection agreement is, in most respects, similar to the service agreement executed by most customers when signing up for electrical service with their local utility.  However, since far fewer generators are connected to the utility than loads, there is more variation in interconnect agreement content, topic, applications and costs.   An interconnection agreement allows a customer to generate power in parallel with the grid.  The power may be utilized internally by the customer or may be exported to the grid.

Interconnect may occur using a single-phase or three-phase connection, determined primarily by the size of the generator.   A typical maximum size for a single-phase connection is 50 kVA,[4] although some locations can support single phase connections as high as 100 kVA.  Above these limits, a three-phase connection is required.  All of the generators considered in this report operate at low voltage – i.e. below 600 V – and would be coupled to the grid through a transformer that connects into the local medium-voltage distribution system, typically operating at 10-25 KV.

Interconnect agreements specify required equipment provided by the customer, terms of service, certification requirements and billing procedures.   Most utilities charge a service fee to process the application and set up the customer’s account, and a monthly “distribution charge” to cover the cost of maintaining the connection to the customer’s location.  The agreement will also clearly define the demarcation between the customer’s and utility’s responsibility for service and repair, typically defined as the secondary connection on the utility transformer.

Utility Structure

A few utilities in Colorado, including Public Service of Colorado (Xcel Energy), are vertically integrated utilities, operating end-to-end utilities, from generation to customer connection.   More typically, the local distribution utility (e.g. Poudre Valley REA) operates the distribution system and customer connection, while a separate entity provides transmission and generation (T&G) services (TriState T&G for Poudre Valley).  In most cases, the distribution utility has a “sole provider” contract with the T&G provider, which limits the power a distribution utility can purchase from sources other than the T&G provider … including locally produced hydropower.  The Governor’s Energy Office (GEO) annually compiles a report summarizing utilities in Colorado[5]  which is useful for understanding the operational structure of any utility operating in the state.

Utility structure and its impact on power purchase arrangements is a substantial subject, out of the scope of this report.  However, to understand the following sections, a few key points must be highlighted:

1)     Since irrigation system hydropower plants are small – very small by utility standards – they will be interconnectedtothe distribution system.  The interconnect agreement is therefore an agreement between the distribution utility and customer. 

2)     Many distribution utilities have the contractual flexibility to purchase small amounts of power directly from their customers.  Many, but not all, utilize this flexibility.  Most of these programs were initiated to support residential photovoltaic systems.  While the smaller hydropower plants discussed here are similarly sized, they may or may not qualify for these programs – check with your utility.  Most programs apply only to systems of 10 kW or smaller. 

3)     For systems larger than those supported by (2) above, two entities must agree to the generation:  The distribution utility must agree to interconnect the generator and the T&G operator must agree to purchase the power.  Either entity can block implementation.  

4)     If power is purchased by the T&G operator, the distribution utility may charge a “feed in” or “wheeling” fee, based upon the amount of power produced, to cover the cost of transmitting the power into the T&G operator’s system.   These fees can be substantial – $0.01 - $0.02 / kWh is not uncommon – and justification for them seldom available, making it difficult to negotiate reductions.

Power Purchase Agreements

The price paid for power is a complex convolution of Federal Energy Regulatory Commission (FERC) rules, state law, PUC rulings, and the negotiating leverage of the customer, T&G operator and distribution utilities. 

While there are no hard-and-fast rules, it is useful to divide power purchase into three categories:

1)     Large generators.  For large systems – multiple megawatts – all generation is purchased using negotiated contracts, and state-mandated bidding rules may also apply.   Few irrigation hydropower systems fall into this category.

2)     Net-metering.  Small systems – typically less than 10 kW – can be connected in a net metering arrangement, where produced power is combined with local loads, and the difference (i.e. net amount) is settled (billed) by the utility.   As noted above, most net metering programs were set up of residential photovoltaic systems, and may or may not be available for hydropower.

Since net-metering provides power “behind the meter,” produced power offsets the retail price of electricity, rather than the wholesale price seen by units in (1) or (3).  It is often the most financially advantageous means of using distributed generation.  However, this benefit fades if the produced power exceeds local loads.  It is not unusual for “net power” to provide customer benefit of more than $0.06/kWh, while the utility credits only $0.02-$0.04/kWh for “excess” power sold back to the utility.

Finally, the definition of net metering varies between utilities.  Some utilities allow multiple meters, at different interconnection points, to be “netted” on one bill.  Others insist that net metering is exactly that – net power behind one meter.

3)     Other.  Most of the systems considered in this report lie in the no-man’s land between net-metering and large operations.   Few hard-and-fast rules exist in this space.  Interconnect agreements may be non-standard and problematic.  The vast majority of systems in this category operate as wholesale power producers, under bilateral contracts with the appropriate T&G operator.

We now consider the application of (2) and (3) to the hydropower systems considered in this report.

Net metering:

For any given irrigation site, two entities may be interested in net-metered electricity production.

1)     Irrigation Company: If the irrigation company has significant loads near the structure, there may be an opportunity to net meter those loads with power production.   While a statistically-significant survey has not yet been conducted, no sites were found in our limited survey where this would be possible.  However, if the local distribution utility permits net-metering across several interconnection points, it may be possible to net power production at one or more hydropower plants with pumping loads elsewhere.  In this case, load and generation should be temporally well-aligned – the best case for net-metering.

2)     Nearby Load:  Another party near the structure could potentially develop the site and net-meter power produced with local loads.  This may be practical for some smaller sites in built-up areas.   Development requires a three-way agreement between the irrigation company, the local power user, and the utility.

Without a complete survey of irrigation-related sites, it is difficult to project the quantity and quality of net-metering opportunities.  However, it is the opinion of this research team that few such sites exist unless distribution utilities support net metering aggregating multiple meters.

Wholesale power sales:

Above the net-metering size, few hard-and-fast rules exist.   However, one useful classification is to consider the presence or absence of applicable renewable portfolio standards (RPS).  When the resource counts against RPS, the power purchase price is significantly higher, and purchase rules are governed differently, than when RPS does not apply.  

Currently, different RPS targets are specified for utilities regulated by the Colorado PUC (Xcel Energy and Black Hills Power) and unregulated entities.  For this report, all sites studied in detail were in Xcel’s service area, and this report will focus on the Xcel case.    At the time of this report, Xcel had met all of its Colorado RPS standards, and was not in need of any additional purchases of renewable power.  Therefore, no RPS-based prices were applicable to the sites studied here.

FERC mandates that all renewable power purchases be made at or below “lowest avoided cost” (LAC) unless a particular renewable source is subject to a state (or future federal) RPS that specifies another treatment.  Considering Xcel Energy, current LAC is based upon Comanche III, a coal-fired thermal power plant utilized for base load.  Currently published LAC is $18.68/MWh with a capacity payment[6] of $7.63/KW-month.  LAC minus Xcel’s profit would therefore be the “floor” price for any power purchase agreement.

However, Xcel personnel indicated that Xcel preferred to move away from a capacity payment for renewable resources.  The “capacity” of renewable resources is generally uncontrolled, and therefore does not reflect Xcel’s operating procedures.  Xcel now typically offers an energy-only contract computed by inserting the proposed generation into Xcel’s existing dispatch model and running a multi-year dispatch simulation.   This method tends to reward units which produce power during the summer peak months – such a irrigation hydropower – as the “displaced units” in the model are the most expensive in Xcel’s portfolio.

It is important to note that the current dispatch model typically does not react (i.e. dispatch the new unit) unless the unit is larger than 10 MW.  This represents an additional challenge for small hydropower.

No firm prices are available, but off-the-record discussions indicate that recent energy-only offering prices have been in the range of 35-40 $/MWh.

Cost of Interconnection

Interconnection costs for small hydropower plants were investigated by looking in more detail at the Grand Valley Irrigation Company sites studied for this report.  Eight sites were identified, and are described in detail in the appendices.  Seven sites were located in Xcel Energy’s service territory, and Xcel estimated interconnection costs.  The 13 Loma Road site was located in Grand Valley Power’s service area, and was not evaluated.  Finally, one site in Xcel’s territory – Headgate – was not evaluated because the applicable turbine type, and thus power production, was too uncertain.  Fortunately, the six remaining sites represent a representative selection of conditions.

Figure 8 summarizes the electrical service costs for all six sites, with two entries for The Dividers, which could be connected at single- or three-phase.

Figure 8: Summary of Interconnect Costs

Explanation of the table:

  • Nominal Capacity:  The capacity of the site calculated from hydraulic considerations and turbine type.
  • Electrical Service Constraints: For The Falls andThe Dividers, available electrical service is less than the nominal capacity.  These columns adjust the capacity and energy production appropriately.
  • Service Installation Costs: Xcel engineers estimated service installation costs, which do not include protection relays, filters and other equipment, as noted above.  To allow meaningful comparison, these costs are scaled by the service-constrained capacity and the service-constrained total power production over a 20 year period.

Figure 9 illustrates the cost of service as a function of the unit capacity.  As expected, there is strong relationship between the unit size and cost, with larger sizes costing proportionally more.  The exception to this rule is the 18.5 Road Drop, which is significantly more expensive for its size than other sites.  This reflects the rural location, requiring installation of overhead lines (4 spans were estimated).

Figure 9: Cost of Electrical Service Unit Capacity

Also notable is the “Y intercept” of the cost.  Regardless of size, the electrical service cost for his sample bottoms out at approximately $5,000.  A similar cost floor is seen for most small distributed generation, which is why net-metering, which shares an electrical service, is attractive for small systems. 

(a)Service Cost / Unit Capacity                               (b) Service Cost / 20-year Energy Production

Figure 10: Service Cost Ratios Based Upon Unit Capacity

Figure 10 displays the same data, scaled by the unit capacity (A) or power produced during twenty years of operation (B).  Here the penalties for rural (18.5 Road) or small (Gates  and Oldam’s) sites are clearly manifest.  The rural site is probably unworkable at current power price.  The sites below 10 kW could be cost-effective if net metering is an option and the power output could be tied into an existing service at low voltage.   If a new service and meter are required, however, these sites are probably not viable, since the electrical service along would cost 10-25% of the likely revenue from power purchase over twenty years.

For the larger sites, electrical services costs drop from $0.96/MWh for the 100-200 kW sites to $0.54/MWh for the larger First Street site.  While these costs are only a portion of total development costs, they do appear to eliminate development potential at these sites.

Electrical InterConnet Conclusions

The optimum choice of a power conversion and interconnect system for small hydropower is currently unclear.  While directly coupled machines may benefit from simplicity and higher efficiency at rated load, power electronics solution may cost less to interconnect and produce higher efficiencies below rated loads.  Ongoing work at CSU will study typical sites for potential system configurations and costs.

Considering revenue, irrigation-related hydropower faces severe challenges.  Small sites are unlikely to be profitable without net metering, and net metering is an unlikely option unless more local distribution utilities support “netting” power production across multiple, dispersed meters.  This is currently uncommon.

Larger sites are similarly challenged by

  • Complex of interconnect and power purchase agreements
  • Lack of standardized solutions
  • Low wholesale power purchase revenue.

Section 3: Typical Infrastructure in Colorado

[1] A protection relay is a electronic control device which monitors the generation connection for issues such as ground fault, phase imbalance, or overcurrent, and disconnects the generator by opening the breaker.

[2] By their nature, induction generators cannot operate without a grid frequency, except in rare conditions.

[3] Conversations were conducted with XcelEnergy, Grand Valley Power regarding hydropower interconnection, and additional discussions were held with Poudre Valley REA regarding distributed generation interconnect in general.

[4] kVA, or kilo-volt-amps, is a measure of the apparent power on a circuit. It is the geometric sum of real andreactive power, or , where  is the real power,  is the reactive power, and  is the apparent power.  For generators operating near unity power factor, , and .  However, certain loads, such as motors, and certain generators, such as induction generators, can have nontrivial reactive power requirements, significantly decreasing the real power capacity of the circuit below the apparent power rating.

[5] Colorado Governor’s Energy Office, 2010 Colorado Utilities Report, August 2010

[6] Capacity is the largest demand serviced by a generator during a billing, or settlement, period.