By Adam Wenner

The Federal Energy Regulatory Commission is charged with regulating wholesale power sales in all of the continental United States, except for sales in Texas.  As a result, its policies significantly affect the prospects for the development of new wind energy projects.  This article summarizes key FERC policies that affect wind energy development.

Regulatory Status

Project developers should try to have their projects qualify either as “exempt wholesale generators” or as “qualifying small power production facilities.” These categories are important because they spare a project from potentially onerous regulation under a 1935 statute called the Public Utility Holding Company Act, or “PUHCA.”

To obtain a FERC determination that a wind project is an exempt wholesale generator, or “EWG,” the entity owning the wind project must be engaged only in the wholesale power business and must sell power only at wholesale — it may not sell power directly to end users.

To be a qualifying small power production facility, or “QF,” a wind project cannot be larger than 80 megawatts in size, and no more than half the equity in the project can be owned by electric utilities.  A project can obtain QF status simply by filing a notice with FERC or by having FERC issue a formal order granting certification.

Although an entity that owns a wind project that is an EWG is exempted from regulation under PUHCA as a utility holding company, it remains subject to FERC regulation under the Federal Power Act as a “public utility.”  As a result, before it can sell power, the project must obtain FERC authorization to sell its output at market-based rates.  To obtain that authorization, the owner of the wind project must show that it lacks market power, or such a dominant position in the local electricity market that can set prices.  Because FERC regulations create a presumption that newly-constructed independent power projects do not possess market power, and because FERC has recognized that wind projects normally cannot profit by withholding power from the market, obtaining FERC authorization for market-based-rate sales is generally a straightforward process.

Interconnecting to the Grid

Wind projects must be located where there is sufficient wind.  This is usually not where many people live, which means that the electricity must be moved long distances to bring it to market.  As a result, the requirements for and pricing of interconnection facilities can be a key factor in the viability of a potential project.

It has not been easy for independent generators using any fuels to connect to the grid.  More than half of interconnection agreements between independent generators and utility are filed unsigned with the Federal Energy Regulatory Commission because the parties cannot agree on terms.  Wind projects have an even more difficult time because the intermittent nature of wind generation creates additional engineering issues.  FERC was so tired of mediating disputes between generators and utilities that it adopted a model interconnection agreement last year for the industry to use.  The model agreement and a set of standard interconnection procedures are spelled out in two FERC orders — Nos. 2003 and 2003-A.

FERC rules establish two different types of interconnection service. “Energy resource interconnection service” enables the wind project to deliver its output to the utility grid and to transmit its output on the grid, but only to the extent that transmission capacity is available. “Network resource interconnection service” is a higher-quality service that enables the wind project to be designated as a “network resource.” A network resource has the same claim on scarce transmission capacity on the grid as does electricity the utility generates itself; accordingly to provide this service, the utility must upgrade its system so as to permit the wind project to reach load in the same way that the utility integrates its own generators to service native load.

Regardless of which type of interconnection service a wind project takes, a key issue is who will pay for the equipment that is needed to permit the wind farm to interconnect and provide power into the grid.  FERC rules focus on the “point of interconnection,” which is the point where the wind project connects to the utility’s transmission system.  Under these rules, the wind project is responsible for the costs of “interconnection facilities”— facilities and equipment that are physically located on the generator side of the point of interconnection, regardless of who owns the facilities.

Facilities and equipment installed on the utility side of the point of interconnection are called “network upgrades.” The utility is ultimately responsible for the costs of network upgrades, subject to an exception for utilities that have turned over operating control over their grids to independent system operators — called “ISOs”— or regional transmission organizations — called “RTOs.” However, the generator must advance the cost of network upgrades, and it is repaid over time, with interest, as the utility is able to collect for the cost through wheeling charges from all users of the grid.  This FERC policy is favorable to wind generators, as the costs of improvements to the transmission grid are borne by all grid users and not charged entirely to the wind project.

FERC permits an RTO or ISO to adopt, subject to FERC approval, alternative policies for the pricing of network upgrades.  Several RTOs and ISOs, including PJM — which controls parts of the grid in Pennsylvania, New Jersey, Delaware, Maryland, Illinois, Ohio, Virginia, West Virginia and the District of Columbia — ISO New England, and the New York ISO, have adopted “but for” pricing for network upgrades.  Under this approach, a “base case” transmission expansion plan is developed by the RTO or ISO.  The cost of the new transmission facilities that would be added in the base case is compared to the cost of network upgrades that would be needed as a result of the interconnection of a wind energy plant.  The generator is responsible for any additional costs.  Because the generator is responsible for these costs, “but for” pricing is generally less favorable to wind projects.

In PJM, New York and New England, a generator that pays for expanding the transmission system by adding network upgrades is entitled to the financial or physical benefits of those upgrades.  In these RTO or ISO regions, the RTO or ISO operates a power pool, or auction, that establishes electricity prices at locations throughout the market.  When the transmission system is not being used at full capacity, the electricity price will be the same throughout the system.  However, when transmission use is high, the quantity of electric power available to transfer from one location to another may exceed the ability of the transmission system to carry power and the system becomes constrained.  In these constrained situations, the right to use the available transmission capacity or the financial benefits of having that right is valuable.  Several ISOs and RTOs provide that “congestion rights”— the rights to use limited transmission capacity — or the financial benefit that the physical right would provide — are awarded to whoever pays for the grid improvements when a new generator connects to the grid.  In these regions, by paying the cost of the upgrades, a wind generator receives the benefit of entitlement to the additional transmission capacity when the transmission system is overloaded.  However, there is no guarantee that the value of these rights will equal the cost of the network upgrade; rather, the value depends on the cost of the network upgrade compared to the benefit of transferring power from a low-cost region to a high-cost region during periods when the availability of the transmission system is limited.  In evaluating the feasibility of a wind energy project, the costs and benefits of any required network upgrades are clearly a key consideration.

Scheduling Issues

In order to function properly, supply on a utility system must equal demand, or “load,” on an instantaneous basis.  Most conventional forms of power generation can be operated to match a schedule that can be established before the fact.  However, wind energy is only available when the wind blows.  While wind availability can be forecasted with increasing accuracy, wind energy cannot be scheduled in the same way that conventional thermal generation is scheduled.

When FERC first required utilities to provide open access to the grid for independent generators in Order No. 888, it authorized utilities to require generators to schedule hourly energy deliveries and to impose penalties for deviations from the schedule.  In order to facilitate the operation of wind energy and other intermittent resources, several ISOs and RTOs have eliminated scheduling requirements for these resources.  For example, the California ISO permits wind generators to net out their deviations from the schedule on a monthly, rather than an hourly basis, and waives imbalance penalties.  The ISO forecasts wind energy production and responds to its forecasts; wind generators pay a fee of 10¢ per MWh for this service.  Monthly netting of imbalances should largely address the scheduling issue, as statistically “over” and “under” generation should cancel each other out over this longer period.

Another approach endorsed by FERC and adopted by several RTOs is the operation of “real-time” energy markets.  FERC Order No. 2000, which establishes criteria that the government uses to approve applications for new RTOs, states that an RTO must ensure that its customers have access to a real-time balancing market — in other words, a market for the auctioning off of electricity — operated by the RTO itself or by an entity that is not affiliated with market participants.  PJM, the New York ISO, and ISO New England operate real-time energy markets.  When such a market is available, if a wind project generates less than its scheduled output, then it (or its customer) can purchase the difference at a price reflecting the then-current value of electricity.  If it produces more than scheduled, then it can sell the excess into the market.  The prices in that market reflect the value of the energy bought or sold and thus provide an economically fair compensation for the over- or under-generation.

Transmission Pricing Issues

Electricity must be wheeled across a grid to bring it to market.  FERC’s pricing of transmission, under which a transmission customer must make a fixed monthly payment for “firm” transmission service, can be problematic for wind developers since their projects must pay effectively to reserve transmission service on a “24/7” basis, but wind generators generally have a load factor of less than conventional thermal generation.  As a result, a wind project that reserves firm transmission capacity ends up paying for capacity that is likely to go unused for significant periods.  FERC also requires utilities to provide “non-firm” transmission service for which a transmission customer only pays on the basis of its actual usage.  However, as its name implies, non-firm service is available only when the grid is not being used at capacity by firm service customers.  Non-firm service is generally not a viable option for wind generators who need certainty that their electricity can get to market.

Relief from the problem of paying for more or less capacity on the grid than one actually needs may be found in the transmission pricing offered by some RTOs and ISOs, such as PJM.  In PJM, for example, it is the utilities serving retail customers and, where retail choice is available, retail customers themselves who are responsible for the costs of the regional transmission system.  By paying the embedded costs of the transmission system, a customer acquires the right for power to be transmitted to it from any point on the PJM system, without additional charge.  As discussed above, separate from transmission charges, a customer who wishes to retain the physical or financial benefits of using transmission capacity during periods when the transmission system is constrained must acquire congestion rights.

Under this type of transmission pricing, since the cost of transmission is a “sunk” cost for which the customer is ultimately responsible irrespective of which generator it taps for electricity, a new wind project serving a customer located within the PJM system does not incur any additional transmission charges.  A similar result occurs when a wind generator interconnects with a utility that is the purchaser of the project’s power — since the utility has already incurred the cost of the transmission capacity used to serve its customer load, the wind generator does not incur a transmission charge for its sale of power to the utility.  In contrast, where power from a wind generator must be transmitted across one or more utility transmission grids that are not part of an ISO or RTO, the generator can be assessed “pancaked” multiple transmission charges.

Other Interconnection Issues

In response to complaints that certain provisions in the model interconnection agreement and policies should not be applied to wind generators, FERC exempted wind projects from several of its generally applicable requirements, including the requirements to install power system stabilizers and to maintain a specified power factor.  Wind projects use small, non-synchronous generators that respond differently to grid disturbances than do large synchronous generators.  In Order No. 2003-A, FERC afforded the wind industry an opportunity to suggest other areas in which the unique electrical characteristics of wind generators call for adoption of different approaches for the interconnection of wind generation.

The American Wind Energy Association has proposed that FERC adopt a “low voltage ride-through standard” for wind farms.  It also wants standards for projects to install remote supervisory control and data acquisition equipment (SCADA) that allows remote control of wind farms.  According to AWEA, low voltage ride-through capability ensures that wind projects will remain on line during most power system disturbances and help support the stability of the grid.  AWEA proposes that low voltage ride-through capability be required when it is found to be beneficial based on significant amount of wind project penetration on the system.

Regarding SCADA equipment, AWEA suggests wind farms should install equipment that would curtail output during system emergencies and provide bi-directional electronic communications between the grid operator and the wind farm to exchange information needed for forecasting and scheduling.  AWEA also proposes that wind generators be required to maintain a power factor of up to 0.95 leading and 0.95 lagging.  Finally, it has asked FERC to require that engineering models used to determine interconnection requirements be current, and to permit wind generators to do their own feasibility studies of a proposed interconnection rather than having to submit a completed power systems load flow study as part of its interconnection request.  Because the turbine selection decision is greatly influenced by the grid conditions at the utility interconnection point, until those conditions are known, the turbine selection and electrical design is not completed.  However, in order to enter the interconnection queue, a wind developer must have a completed electrical design.  To avoid this “Catch-22,”AWEA proposes to permit the developer, upon payment of the appropriate deposit, to enter the interconnection queue, receive grid base case data, including load flow, stability and short-circuit base case data, and then present the utility with an electric design sufficiently detailed to enable the utility to conduct a system impact study.

FERC held a hearing on the AWEA proposals in mid September.  The agency is expected to announce its decisions about them early next year.