Tariff Structures for Large Scale Hydroelectric IPPs

By Ryan T. Ketchum and Nicola R. Saporiti.  Ryan is a partner at Hunton Andrews Kurth.  Nicola Saporiti is a Senior Investment Officer at the International Finance Corporation.  He is not affiliated with Hunton Andrews Kurth.

As a dispatchable renewable energy technology, hydropower has a significant role to play in the energy transition.  The growing penetration of intermittent renewable energy on many grids has increased the need for ancillary services such as frequency regulation.  The fast response times and high ramp rates of hydropower make it well suited to provide these services, enabling further penetration by other renewable energy resources.  Although relatively few hydroelectric projects have been developed as independent power projects (“IPPs”), the growing value of hydroelectric resources in facilitating the energy transition is likely to change that.

The structure of tariffs for large scale hydroelectric IPPs has a significant impact on the bankability of these projects.  This article examines the principal options for structuring tariffs for both storage and run of river hydroelectric projects.

Storage and run of river projects distinguished

Although all hydroelectric projects are unique, in general terms storage projects usually involve tall dams which create sizeable reservoirs that are capable of storing water for long periods of time.  Storage projects may, for example, be capable of storing water collected during one season for use in another season.  In contrast, run-of-river projects usually involve a low dam, or weir, that diverts water into the hydropower plant’s penstock.  These structures may create reservoirs (pondage) that store a small volume of water relative to the average flow.  A run-of-river project may, for example, store enough water to generate electricity for several hours at rates that are higher than the rate that could be generated by the average flow of the river over the course of a particular day. Even limited amounts of pondage are sufficient to create significant additional value for an offtaker or transmission system operator because even limited  amounts of pondage will enable the offtaker or transmission system operator to maximize generation when the capacity is most valuable to the system (either technically or financially).

Pondage may also be used to increase the difference in elevation between the surface of the reservoir or pondage and the tailwater (the “head”).  This is an important consideration, given that the energy generated by any hydropower plant is a direct function of the head times the flow of water that can pass through the turbines.¹

Different types of tariff structures may be more appropriate for these different types of projects.

Tariff structures

Across all types of IPPs, tariffs fall into one of two structures.  Those structures are (i) capacity-based tariffs, and (ii) energy-based tariffs.

Capacity-based tariffs

Capacity-based tariffs are typically used for projects that are dispatchable by the offtaker or transmission system operator.  Capacity-based tariffs provide that the offtaker will pay:

• a charge (the capacity charge) for the generating capacity that is made available to the offtaker, regardless of whether energy is dispatched and generated; and
• a charge (the energy charge) for energy that is dispatched by, and delivered to, the offtaker.

The capacity charge is sized to enable the project company to generate revenues that are sufficient to enable the project company to:

• pay principal and interest on the project loans borrowed by the project company to fund the capital cost of the project;
• return the equity invested by the sponsors to fund the capital cost of the project to the sponsors over the term of the power purchase agreement;
• pay a return on the equity invested by the sponsors over the term of the power purchase agreement;
• pay all corporate and other taxes incurred by the project company; and
• pay for fixed operations and maintenance costs (operation and maintenance costs that are incurred by the project company regardless of the level of dispatch).

The energy charge is sized to enable the project company to recover (a) the cost of fuel (for thermal projects), and (b) the cost of variable operations and maintenance costs (operations and maintenance costs that vary depending on the quantity of energy generated by the project).

Energy-based tariffs

Energy-based tariffs are generally used for non-dispatchable technologies (primarily intermittent renewables).  For these types of projects, the power purchase agreement generally requires the project company to generate and deliver, and the offtaker to purchase, all or substantially all,² of the energy the project can generate.  If the offtaker is not able to purchase, or take delivery of, energy generated by the project, then the offtaker must pay for the energy the project could have generated and delivered.  These payments are known as curtailment payments, deemed energy payments, or deemed generation payments.

For an energy-based tariff, the energy charge is sized to enable the project company to generate revenues that are sufficient to cover (a) all of the components that would be used to size the capacity charge if the tariff were a capacity-based tariff (as describe above), (b) the cost of fuel (for thermal projects), and (c) variable operations and maintenance costs, if the project company is able to generate a quantity of energy that generally corresponds to a 90% probability of exceedance (which is known as P₉₀ and is the quantity of energy that the project is forecasted to be able to generate during 90% of the yearly periods during the term of the power purchase agreement).

Tariffs for storage projects and run of river projects with significant pondage

Capacity-based tariffs

Capacity-based tariffs tend to enhance the bankability of storage projects as well as of run of river projects that include significant pondage and are dispatchable.  There is, however, a significant difference between the thermal projects on which capacity-based tariffs are typically used and hydro projects.  That difference is that a thermal power generation plant should be able to generate at its full nominal capacity at all times and for extended periods of time..  In contrast, the ability of hydropower projects to generate at their full nominal capacity depends on the elevation of the surface of the reservoir or pondage.³ In addition, while some hydropower plants may be able to achieve very high load factors,⁴ the availability of sufficient water flows to generate at a 100% load factor for long periods should not be assumed.  Instead, the actual capacity that a project can be expected to make available must be adjusted for hydraulic conditions.  This could be done in following manner.

As a starting point, the project company would declare the capacity that is available from the project assuming nominal hydraulic conditions.  For a large scale storage project or run of river project with significant pondage, hydraulic conditions could be defined as the head height.  In this scenario, nominal hydraulic conditions would equal the difference between (i) the surface of the reservoir at its maximum fill height, and (ii) the surface of the tail water.  The hydraulic conditions would be measured at regular intervals, such as every six seconds or some longer interval.  The capacity declared to be available by the project company during a given settlement period or hour assuming nominal hydraulic conditions could then be adjusted by an index that might be stated as the actual hydraulic conditions during the interval divided by nominal hydraulic conditions raised to the power of a factor that correspond to changes in the expected efficiency of the plant at various head heights.  If the appropriate factor were 1.5, this could be stated as:

The Hydraulic Adjusted Capacity determined by the above formula would be used to determine the capacity the project company would actually be expected to make available during that settlement period or hour if the offtaker or transmission system operator dispatches the plant. If the offtaker or transmission system operator does dispatch the plant during that settlement period or hour and the project company is not able to deliver the Hydraulic Adjusted Capacity during that settlement period or hour, then the capacity payment would be reduced using the types of time and generation shortfall weightings that are used to adjust the capacity payment for other types of generation projects.

This capacity payment structure effectively allocates hydrology risk to the offtaker because the offtaker is obligated to pay for the electro-mechanical capacity of the project regardless of the level of the reservoir or pondage.  As a result, the offtaker is in the same position in relation to hydrology risk that it would be in had it developed the project on balance sheet instead of as an IPP.

Energy-based tariffs

As a general rule, we would advise offtakers against the use of energy-based tariffs for storage projects in the absence of compelling circumstances, such as a legal prohibition on capacity-based tariffs imposed by the legal framework of a particular country.  These projects are usually so capital-intensive that it is not feasible to allocate hydrology risk to a party other than the offtaker. For these projects, lenders and sponsors are likely to require that the hydrological risk be allocated to the offtaker even if energy-based tariffs is used, which adds considerable complexity to power purchase agreements. For hydropower projects, energy-based tariffs must be coupled with a take or pay requirement, like it would be with most any other energy-based tariff for a non-dispatchable renewable energy projects.⁵ However, as is the case with a capacity-based tariff, specific contractual adjustments must be made to the take or pay requirement for hydropower plants, to reflect the fact that the availability of water in any given period cannot be assumed.

For projects subject to seasonal hydrology, these adjustments could start with stating the take or pay obligation in terms of a monthly take or pay quantity instead of an annual take or pay quantity.  The monthly take or pay quantities would be set using the anticipated availability of water during each month, taking any reservoir rules⁶ into account.

The following quantities of energy could then be credited against the monthly take or pay quantity:

• the quantity of energy actually generated by the project during the month; and
• any reductions to the quantity of energy actually generated to the extent caused by maintenance, technical outages, or any reduction to the energy generated for reasons not attributable to the offtaker or to risks that have been allocated to the offtaker.

In the event that water flows are not sufficient to generate the monthly take or pay quantity, then the quantity of energy not generated would be carried forward to subsequent months during that year.  This carrying forward would effectively increase the aggregate of the take or pay quantities for the remainder of the year.  In the event that water flows are not sufficient to enable the project to generate a minimum level of the monthly take or pay quantities during the course of a full year, then the offtaker would be required to either make a one time payment to the project company or increase the energy charge during the following year. 

If such an alternative is adopted and poor hydrology continues for some period of time, then the project company must be made whole either through the payment of a one time payment or through a termination of the project agreements coupled with a transfer of the project to the offtaker in exchange for termination compensation.⁷ Despite these adjustments, which are required for project bankability, lenders are likely to perceive an energy-based tariff as riskier than an equivalent capacity-based tariff, and to offer less favorable financing terms as a result.

Tariffs for run of river projects without significant pondage

For hydroelectric projects that do not include significant pondage, we suggest that a model similar to those used for photovoltaic solar or wind projects be used.  These tariffs would include an obligation to purchase all, or substantially all, of the energy the project can generate plus curtailment payments in the event the project spills water that could have been used to generate due to an instruction to curtail generation. 

The suggested tariff structure for run of river projects without significant pondage would effectively treat these types of projects like any other intermittent renewable resource would be treated.

¹ The higher the head, the higher the energy produced by the same flow of water passing through the turbines.  The higher the flow, the higher the energy produced by a hydropower plant with a given head.

² In some markets, the quantity of energy the offtaker is be required to purchase annually may be capped.  A 90% probability of exceedance means that the project will usually generate more than the P₉₀ quantity.  In some cases it could generate materially more energy.  In some markets, offtakers may be reluctant to agree to purchase an unlimited quantity of energy the project can generate without a firm cap.

³ At the end of the dry season, the reservoir level may be low, preventing the hydropower plant from generating at full capacity, given the same unit flow of water. Note that, to prevent cavitation in turbines, in well-designed hydropower plants the tailwater elevation does not fluctuate significatively.

 ⁴ In British Columbia, for example, large scale storage projects achieve load factors of around 85% - 90%.  See http://www.energybc.ca/runofriver.html.

⁵ Projects without a fixed take-or-pay tariff are subject to dispatch risk and normally referred to as “merchant” projects. Merchant projects are considerably riskier for sponsors and lenders, and only observed in more developed and liberalized energy markets.

⁶ The management of large reservoirs is normally subject to fixed “rules”, which regulate the discharges from, and the level in, the reservoir throughout the year.  Reservoir rules are typically set by national water agencies in consultation with multiple stakeholders, taking into account technical, economic, risk, environmental and social considerations.

⁷ For more information on termination compensation, please see our previous client alert.